PORTLAND GENERAL ELECTRIC CO /OR/ - Quarter Report: 2010 March (Form 10-Q)

Location

2010
Forecast
Runoff *

2009
Actual
Runoff *

Columbia River at The Dalles, Oregon

Mid-Columbia River at Grand Coulee, Washington

Clackamas River at Estacada, Oregon

Deschutes River at Moody, Oregon

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, 2010

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, 2010 is 75,275,512 shares.

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2010

TABLE OF CONTENTS


Definitions		3

PART I – FINANCIAL INFORMATION

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	27

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	46

Item 4.	Controls and Procedures	46

	PART II – OTHER INFORMATION

Item 1.	Legal Proceedings	47

Item 1A.	Risk Factors	47

Item 6.	Exhibits	47

SIGNATURE		48

DEFINITIONS

The following abbreviations and acronyms are used throughout this document:


Abbreviation or Acronym		Definition
AFDC		Allowance for funds used during construction
BART		Best Available Retrofit Technology
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
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
LLC		Limited Liability Corporation
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt hours
NVPC		Net Variable Power Costs
OEQC		Oregon Environmental Quality Commission
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
S&P		Standard & Poor’s Ratings Services
SB 408		Oregon Senate Bill 408
SEC		Securities and Exchange Commission
SIP		Oregon Regional Haze State Implementation Plan
Trojan		Trojan Nuclear Plant
URP		Utility Reform Project
VIE		Variable Interest Entity

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,
	2010		2009
Revenues	$	449	$	485
Operating expenses:
Purchased power and fuel		224		255
Production and distribution		39		42
Administrative and other		45		45
Depreciation and amortization		57		57
Taxes other than income taxes		23		23

Total operating expenses		388		422

Income from operations		61		63

Other income (expense):
Allowance for equity funds used during construction		4		2
Miscellaneous income (expense), net		1		(3	)

Other income (expense), net		5		(1	)
Interest expense		29		25

Income before income taxes		37		37
Income taxes		10		13

Net income		27		24

Less: net losses attributable to the noncontrolling interests		-		(7	)

Net income attributable to Portland General Electric Company	$	27	$	31


Weighted-average shares outstanding (in thousands):
Basic		75,229		65,521

Diluted		75,246		65,607

Earnings per share:
Basic	$	0.36	$	0.47

Diluted	$	0.36	$	0.47

Dividends declared per common share	$	0.255	$	0.245

See accompanying notes to condensed consolidated financial statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in millions)

(Unaudited)


	March 31, 2010		December 31, 2009
ASSETS
Current assets:
Cash and cash equivalents	$	52	$	31
Accounts receivable, net		150		159
Unbilled revenues		71		95
Inventories		53		58
Margin deposits		89		56
Regulatory assets - current		202		197
Current deferred income taxes		48		-
Other current assets		129		94

Total current assets		794		690
Electric utility plant, net		3,964		3,858
Regulatory assets - noncurrent		532		465
Non-qualified benefit plan trust		47		47
Nuclear decommissioning trust		32		50
Other noncurrent assets		67		62
Total assets	$	5,436	$	5,172

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, 2010			December 31, 2009
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	209		$	187
Liabilities from price risk management activities - current		180			128
Current portion of long-term debt		37			186
Regulatory liabilities - current		18			27
Other current liabilities		91			92

Total current liabilities		535			620
Long-term debt, net of current portion		1,750			1,558
Regulatory liabilities - noncurrent		651			654
Deferred income taxes		426			356
Liabilities from price risk management activities - noncurrent		202			127
Unfunded status of pension and postretirement plans		144			143
Non-qualified benefit plan liabilities		96			96
Other noncurrent liabilities		80			75

Total liabilities		3,884			3,629

Commitments and contingencies (see notes)
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, 2010 and December 31, 2009		-			-
Common stock, no par value, 160,000,000 shares authorized; 75,275,512 and 75,210,580 shares issued and outstanding as of March 31, 2010 and December 31, 2009, respectively		829			829
Accumulated other comprehensive loss		(5	)		(6	)
Retained earnings		727			719

Total Portland General Electric Company shareholders’ equity		1,551			1,542
Noncontrolling interests’ equity		1			1

Total equity		1,552			1,543

Total liabilities and equity	$	5,436		$	5,172

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,
	2010			2009
Cash flows from operating activities:
Net income	$	27		$	24
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		57			57
Increase in net liabilities from price risk management activities		106			87
Regulatory deferral - price risk management activities		(106	)		(87	)
Deferred income taxes		12			11
Senate Bill 408 deferrals		(1	)		(6	)
Allowance for equity funds used during construction		(4	)		(2	)
Power cost deferrals, net		-			(5	)
Other non-cash income and expenses, net		9			9
Changes in working capital:
Increase in margin deposits		(33	)		(16	)
Decrease in receivables		33			19
Decrease in payables		(11	)		(35	)
Other working capital items, net		(13	)		(21	)
Other, net		(8	)		5

Net cash provided by operating activities		68			40

Cash flows from investing activities:
Capital expenditures		(92	)		(91	)
Distribution from Nuclear decommissioning trust		19			-
Sales of Nuclear decommissioning trust securities		13			7
Purchases of Nuclear decommissioning trust securities		(12	)		(7	)
Other, net		(1	)		-

Net cash used in investing activities		(73	)		(91	)

Cash flows from financing activities:
Proceeds from issuance of long-term debt		191			130
Payments on long-term debt		(149	)		-
Proceeds from issuance of common stock, net of issuance costs		-			170
Borrowings on revolving lines of credit		-			82
Payments on revolving lines of credit		-			(213	)
Borrowings (payments) on short-term debt, net		4			(72	)
Dividends paid		(19	)		(15	)
Debt issuance costs		(1	)		(1	)
Noncontrolling interests’ capital contributions		-			7

Net cash provided by financing activities		26			88

Increase in cash and cash equivalents		21			37
Cash and cash equivalents, beginning of period		31			10

Cash and cash equivalents, end of period	$	52		$	47

Supplemental disclosures of cash flow information:
Cash paid during the period for interest, net of amounts capitalized	$	16		$	13
Non-cash investing and financing activities:
Accrued capital additions		68			104
Accrued dividends payable		20			18

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 817,393 retail customers as of March 31, 2010.

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, 2010 and 2009 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, 2009 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2009, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 25, 2010, 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.

Recent Accounting Pronouncements

On January 1, 2010, PGE adopted Statement of Financial Accounting Standard No. (SFAS) 167, “Amendments to FASB Interpretation No. 46(R),” (SFAS 167) which is a revision of FASB Interpretation No. 46(R), Variable Interest Entities, and changes how a company determines when a variable interest entity (VIE) should be consolidated. The determination of whether a company is required to consolidate an entity is based on, among other things, an entity’s purpose and design and a company’s ability to direct the activities of the entity that most significantly impact the entity’s economic performance. SFAS 167 requires a company to provide additional disclosures about its involvement with variable interest entities and what any significant change in risk exposure does to that involvement. A company is also required to disclose how its involvement with a VIE affects the company’s performance. The adoption of SFAS 167, which was codified in the FASB Accounting Standards Codification 810, Consolidation, upon the adoption of SFAS 168, The FASB Accounting Standards Codification and the Hierarchy of Generally Accepted Accounting Principles - a replacement of FASB Statement No. 162, did not have a material impact on PGE’s condensed consolidated financial position, condensed consolidated results of operations, or condensed consolidated cash flows.

ASU 2010-06, Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU 2010-06) requires new disclosures about (i) the transfers in and out of Levels 1 and 2 and a description of the reasons for the transfers and (ii) for an entity to report separately about purchases, sales, issuances, and settlements for Level 3 fair value measurements. For additional information on the three broad levels, see Note 3. ASU 2010-06 also clarifies existing disclosures and requires (i) an entity to provide fair value measurement disclosures for each class of assets and liabilities and (ii) disclosures about inputs and valuation techniques. In accordance with the provisions of ASU 2010-06, on January 1, 2010, PGE adopted the requirements of ASU 2010-06, except for the disclosures about purchases, sales, issuance and settlements in the roll forward of activity in Level 3 fair value measurements, which did not have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows. Based on the provisions of ASU 2010-06, PGE will adopt the disclosure requirements about purchases, sales, issuance and settlements in the roll forward of activity in Level 3 fair value measurements on January 1, 2011, which 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, 2010 and December 31, 2009.

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


	Three Months Ended March 31,
	2010			2009
Balance at beginning of period	$	5		$	4
Provision		1			2
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 are used in operations, maintenance and capital activities and are recorded at average cost. Fuel inventories include natural gas, coal, and oil and are used in PGE’s generating plants. Natural gas is recorded at the lower of average cost or market, with coal and oil recorded at average cost.

Electric Utility Plant, Net

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


	March 31, 2010			December 31, 2009
Electric utility plant	$	5,728		$	5,596
Construction work in progress		406			406

Total cost		6,134			6,002
Less: accumulated depreciation and amortization		(2,170	)		(2,144	)

Electric utility plant, net	$	3,964		$	3,858

Accumulated depreciation and amortization in the table above includes amortization of intangible assets of $124 million and $122 million as of March 31, 2010 and December 31, 2009, respectively. Amortization expense related to intangible assets was $3 million and $4 million for the three month periods ended March 31, 2010 and 2009, respectively.

Regulatory Assets and Liabilities

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


	March 31, 2010				December 31, 2009
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Price risk management	$	152	$	196	$	118	$	125
Pension and other postretirement plans		-		194		-		196
Deferred income taxes		-		83		-		91
Deferred broker settlements		42		1		49		1
Debt reacquisition costs		-		25		-		26
Utility rate treatment of income taxes		3		-		7		-
Boardman power cost deferral		-		-		17		-
Other		5		33		6		26

Total regulatory assets	$	202	$	532	$	197	$	465

Regulatory liabilities:
Asset retirement removal costs	$	-	$	553	$	-	$	541
Asset retirement obligations		-		31		-		30
Utility rate treatment of income taxes		14		14		9		24
Trojan ISFSI pollution control tax credits		-		19		-		17
Other		4		34		18		42

Total regulatory liabilities	$	18	$	651	$	27	$	654

On February 12, 2010, the OPUC issued an order authorizing the offset of the Boardman power cost deferral with the simultaneous amortization of an equal amount of customer credits related to nuclear decommissioning activities. Based on the OPUC order, $19 million was transferred from the Nuclear decommissioning trust to PGE, which is included in the condensed consolidated statements of cash flows for the three months ended March 31, 2010.

Credit Facilities

PGE has the following unsecured revolving credit facilities:

•

A $370 million syndicated credit facility, with $10 million and $360 million scheduled to terminate in July 2012 and July 2013, respectively;

•

A $200 million syndicated credit facility, which is scheduled to terminate in December 2012; and

•

A $30 million credit facility, which is scheduled to terminate in June 2012.

Pursuant to the individual terms of the agreements, all credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities also permit the issuance of standby letters of credit. All credit facilities 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, 2010, PGE was in compliance with this covenant.

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

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt up to $750 million through February 6, 2012. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

As of March 31, 2010, PGE had issued $233 million in letters of credit under the credit facilities and had no borrowings or commercial paper outstanding. As of March 31, 2010, the aggregate credit available under the credit facilities was $367 million.

Long-term Debt

During the first quarter of 2010, PGE had the following long-term debt transactions:

•

On January 15th, issued $70 million of 3.46% First Mortgage Bonds due January 2015, with interest payable semi-annually on January 15th and July 15th;

•

On March 11th, remarketed $121 million of Pollution Control Bonds due May 2033 at 5.0%, with interest payable semi-annually on March 1st and September 1st, which are backed by first mortgage bonds; and

•

On March 15th, repaid $149 million of 7.875% unsecured notes.

As of March 31, 2010, the Company holds $21 million of repurchased Pollution Control Bonds, which can be remarketed through 2033.

Pension and Other Postretirement Benefits

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


	Defined Benefit Pension Plan						Other Postretirement Benefits				Non-Qualified Benefit Plans
	2010			2009			2010		2009		2010		2009
Service cost	$	3		$	3		$	1	$	1	$	-	$	-
Interest cost		7			8			1		1		1		1
Expected return on plan assets		(10	)		(11	)		-		-		-		-
Amortization of net actuarial gain		1			-			-		-		-		-

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

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair value of financial instruments, both assets and liabilities recognized and not recognized in PGE’s consolidated balance sheet, for which it is practicable to estimate fair value as of March 31, 2010 and December 31, 2009 is as follows:

•

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

•

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

•

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

•

The fair value of long-term debt is estimated based on the quoted market prices for the same or similar issues or on the current rates offered to PGE for debt of similar remaining maturities. As of March 31, 2010, the estimated aggregate fair value of PGE’s long-term debt was $1,911 million, compared to its $1,787 million carrying amount. As of December 31, 2009, the estimated aggregate fair value of PGE’s long-term debt was $1,818 million, compared to its $1,744 million carrying amount.

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

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

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

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

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


	Level 1		Level 2		Level 3		Total
As of March 31, 2010:
Assets:
Nuclear decommissioning trust*:
Cash	$	13	$	-	$	-	$	13
Debt securities:
U.S. treasury securities		5		-		-		5
Corporate debt securities		-		8		-		8
Mortgage-backed securities		-		5		-		5
Municipal securities		-		1		-		1
Non-qualified benefit plan trust:
Equity securities		21		1		-		22
Debt securities - mutual funds		3		-		-		3
Assets from price risk management activities*:
Electricity		-		18		-		18
Natural gas		-		15		1		16

	$	42	$	48	$	1	$	91

Liabilities - Liabilities from price risk management activities*:
Electricity	$	-	$	101	$	22	$	123
Natural gas		-		59		200		259

	$	-	$	160	$	222	$	382

As of December 31, 2009:
Assets:
Nuclear decommissioning trust*:
Cash	$	31	$	-	$	-	$	31
Debt securities:
U.S. treasury securities		4		-		-		4
Corporate debt securities		-		8		-		8
Mortgage-backed securities		-		5		-		5
Municipal securities		-		2		-		2
Non-qualified benefit plan trust:
Equity securities		21		-		-		21
Debt securities - mutual funds		4		-		-		4
Assets from price risk management activities*:
Electricity		-		7		-		7
Natural gas		-		6		-		6

	$	60	$	28	$	-	$	88

Liabilities - Liabilities from price risk management activities*:
Electricity	$	-	$	72	$	9	$	81
Natural gas		-		29		145		174

	$	-	$	101	$	154	$	255

* Activities are subject to regulation, with certain gains and losses deferred pursuant to regulatory accounting and included in Regulatory assets or Regulatory liabilities as appropriate.

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 fund general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and consist of money market funds and fixed income securities. Non-qualified benefit plan trust reflects the assets held in trust to fund a portion of the obligations of PGE’s non-qualified benefit plans and consist primarily of marketable securities. The Non-qualified benefit plan trust also holds insurance policies recorded at cash surrender value, which are excluded from the table above as they are not recorded at fair value.

Assets and liabilities from price risk management activities represent derivative transactions entered into by PGE to manage its exposure to commodity price risk and minimize net power costs for service to the Company’s retail customers and may consist of forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil. PGE applies a market based approach to the fair value measurement of its derivative transactions. Inputs into the valuation of derivative activities include forward commodity and foreign exchange pricing, interest rates, volatility and correlation. PGE utilizes the Black-Scholes and Monte Carlo pricing models for commodity option contracts. Forward pricing, which employs the mid-point of the market’s bid-ask spread, is derived using observed transactions in active markets, as well as historical experience as a participant in those markets, and is validated against nonbinding quotes from brokers with whom the Company transacts. Interest rates used to calculate the present value of derivative valuations incorporate PGE’s borrowing ability. The Company also considers the liquidity of delivery points of executed transactions when determining where in the fair value hierarchy a transaction should be classified. PGE considers its creditworthiness and the creditworthiness of its counterparties when determining the appropriateness of a particular transaction’s assigned Level in the fair value hierarchy.

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


	Three Months Ended March 31,
	2010			2009
Net liabilities from price risk management activities, as of beginning of period	$	(154	)	$	(123	)
Net realized and unrealized losses		(57	)		(51	)
Purchases, issuances, and settlements, net		(10	)		4

Net liabilities from price risk management activities, as of end of period	$	(221	)	$	(170	)

Net realized and unrealized losses are recorded in Purchased power and fuel expense in the condensed consolidated statements of income, and include net losses of $57 million in the first quarter of 2010 and $45 million in the first quarter of 2009, of Level 3 net realized and unrealized losses that have been fully offset by the effects of regulatory accounting. Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. Transfers out of Level 3 occur when the significant inputs become more observable, such as the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers in and transfers out of Level 3 at the end of the reporting period for all of its financial instruments.

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, where adverse changes in prices and/or rates may effect the Company’s financial position, performance, or cash flow.

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 wholesale 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. These derivative instruments are recorded at fair value on the balance sheet, with changes in fair value recorded in the statement of income. However, as a regulated entity, PGE recognizes a regulatory asset or liability in order to defer the gains and losses from derivative activity until realized, in accordance with the ratemaking and cost recovery processes authorized by the OPUC. This accounting treatment defers the mark-to-market gains and losses on derivative activities until settlement, reducing volatility related to commodity price risk and foreign currency exchange rate risk. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as purely economic hedges. PGE does not engage in trading activities for non-retail purposes.

PGE has elected not to net on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists.

PGE’s net volume related to its Price risk management assets and liabilities resulting from its derivative activities was as follows (in millions):


	March 31, 2010	December 31, 2009
Commodity contracts:
Electricity	12 MWh	12 MWh
Natural gas	109 Decatherms	96 Decatherms
Foreign exchange	$5 Canadian	$5 Canadian

PGE’s Assets and Liabilities from price risk management activities resulting from its derivative activities, offset by regulatory accounting, consist of the following (in millions):


	Asset derivatives				Liability derivatives
	Balance sheet classification	Fair value			Balance sheet classification	Fair value
As of March 31, 2010:
Derivatives not designated as hedging instruments:
Commodity contracts:
Electricty	Current assets	$	16		Current liabilities	$	66
Natural gas	Current assets		12		Current liabilities		114

Total current derivative activity			28	⁽¹⁾			180

Commodity contracts:
Electricity	Noncurrent assets		2		Noncurrent liabilities		57
Natural gas	Noncurrent assets		4		Noncurrent liabilities		145

Total noncurrent derivative activity			6	⁽²⁾			202

Total derivatives not designated as hedging instruments		$	34			$	382

Total derivatives		$	34			$	382


As of December 31, 2009:
Derivatives not designated as hedging instruments:
Commodity contracts:
Electricty	Current assets	$	6		Current liabilities	$	57
Natural gas	Current assets		5		Current liabilities		71

Total current derivative activity			11	⁽¹⁾			128

Commodity contracts:
Electricity	Noncurrent assets		1		Noncurrent liabilities		24
Natural gas	Noncurrent assets		1		Noncurrent liabilities		103

Total noncurrent derivative activity			2	⁽²⁾			127

Total derivatives not designated as hedging instruments		$	13			$	255

Total derivatives		$	13			$	255

(1)	Included in Other current assets on the condensed consolidated balance sheet.

(2)	Included in Other noncurrent assets on the condensed consolidated balance sheet.

Net realized and unrealized losses on derivative transactions recognized in the statement of income were as follows (in millions):


Derivatives not designated as hedging instruments	Location of net loss recognized on derivative activities in the statement of income	Three months ended March 31,
		2010*		2009*
Commodity contracts:
Electricity	Purchased power and fuel expense	$	53	$	81
Natural Gas	Purchased power and fuel expense		91		88

*	Unrealized gains and losses and certain realized gains and losses are offset by regulatory accounting. Of the net loss recognized in net income for the three months ended March 31, 2010 and 2009, $141 million and $166 million has been offset, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2010 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):


	2010 *		2011		2012		2013		2014		Total
Commodity contracts:
Electricity	$	36	$	48	$	11	$	7	$	3	$	105
Natural gas		84		72		60		25		2		243

Net unrealized loss	$	120	$	120	$	71	$	32	$	5	$	348

*	Represents period from April 1, 2010 through December 31, 2010.

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 Ratings Services (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties and certain other counterparties will have the right to terminate their agreements with the Company.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2010 was $318 million, for which the Company had $213 million in posted collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2010, the cash requirement would have been $292 million.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities as of March 31, 2010 or December 31, 2009 were as follows:


	March 31, 2010		December 31, 2009
Assets from price risk management activities:
Counterparty A	42	%	41	%
Counterparty B	15		2
Counterparty C	9		14
Counterparty D	3		15

	69	%	72	%

Liabilities from price risk management activities:
Counterparty A	20	%	19	%
Counterparty D	12		13
Counterparty E	11		14

	43	%	46	%

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

NOTE 5: EARNINGS PER SHARE

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


	Three Months Ended March 31,
	2010		2009
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	27	$	31

Denominator (in thousands):
Weighted-average common shares outstanding - basic		75,229		65,521
Dilutive effect of restricted stock units and employee stock purchase plan shares		17		86

Weighted-average common shares outstanding - diluted		75,246		65,607

Earnings per share:
Basic	$	0.36	$	0.47

Diluted	$	0.36	$	0.47

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

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

NOTE 6: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):


	Three Months Ended March 31,
	2010			2009
Net income	$	27		$	24
Pension and other postretirement plans’ funded position, net of taxes		2			-
Reclassification of defined benefit pension plan and other benefits to regulatory asset, net of taxes		(2	)		-
Gains (losses) on cash flow hedges:
Reclassification to net income for contract settlements, net of taxes		-			1
Reclassification of net realized and unrealized gains to regulatory liabilities, net of taxes		-			(1	)

Total gains on cash flow hedges		-			-

Comprehensive income		27			24

Less: comprehensive losses attributable to the noncontrolling interests		-			(7	)

Comprehensive income attributable to Portland General Electric Company	$	27		$	31

NOTE 7: CONTINGENCIES

Legal Matters

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant and sought full recovery of, and a rate of return on, its Trojan plant costs in a general rate case filing with the OPUC. The OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan plant costs.

Court Proceedings on OPUC Authority to Grant Recovery of Return on Trojan Investment. Numerous challenges, appeals and reviews were subsequently filed in various state courts 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). In 1998, the Oregon Court of Appeals upheld the OPUC order authorizing PGE’s recovery of the Trojan

investment, but held that the OPUC did not have the authority to allow PGE to recover a return on the Trojan investment and remanded the case to the OPUC for reconsideration.

In 2000, PGE, CUB, and the staff of the OPUC entered into agreements to settle the litigation related to PGE’s recovery of, and return on, its investment in the Trojan plant. The URP did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements.

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. In 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. Pursuant to the remand, the OPUC considered whether it has authority to engage in retroactive ratemaking and what prices would have been if, in 1995, it had interpreted the law to prohibit a return on the Trojan investment.

On September 30, 2008, the OPUC issued an order that required PGE to refund $15.4 million, plus interest at 9.6% from September 30, 2000, to customers who received service from PGE during the period October 1, 2000 to September 30, 2001. The $15.4 million amount, plus accrued interest, resulted in a total refund of $33.1 million, payment of which was completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below have separately appealed the order to the Oregon Court of Appeals.

Class Actions. In a separate legal proceeding, two class action suits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers (the Class Action Plaintiffs). The suits seek damages of $260 million plus interest as a result of the inclusion of a return on investment of Trojan in the prices PGE charged its customers.

In August 2006, the Oregon Supreme Court issued a ruling abating the class action proceedings until the OPUC responded with respect to the 2002 Order (described above). The Oregon Supreme Court concluded that the OPUC has primary jurisdiction to determine what, if any, remedy it can offer to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment PGE collected in prices for the period from April 1, 1995 through October 1, 2000.

The Oregon Supreme Court further stated that if the OPUC determined that it can provide a remedy to PGE’s customers, then the class action proceedings may become moot in whole or in part. The Oregon Supreme Court added 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 Marion County Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings.

In October 2006, the Marion County Circuit Court issued an Order of Abatement in response to the ruling of the Oregon Supreme Court, abating the class actions.

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

Complaint and Application for Deferral – Income Taxes

On October 5, 2005, the URP and another party (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of Oregon Senate Bill 408 (SB 408), PGE’s rates were not just and reasonable and were in violation

of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers since September 2, 2005 for state and federal income taxes, less amounts actually paid by or on behalf of PGE to the federal and state governments for income taxes.

In August 2007, the OPUC issued an order granting the Application for Deferred Accounting for the period from October 5, 2005 through December 31, 2005. The OPUC’s order also dismissed the Complaint, on grounds that it was superfluous to the Complainants’ request for deferred accounting.

In August 2009, the OPUC issued an order that denied amortization of any deferral in this matter, based on a review of PGE’s earnings. On October 16, 2009, plaintiffs filed an appeal of the August 2009 order with the Oregon Court of Appeals.

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

Turlock Irrigation District Claim

PGE and Power Resources Cooperative (PRC) are parties to an Ownership and Operation Agreement (OOA), pursuant to which PRC is entitled to ten percent of the power generated at Boardman. In 1992, PRC entered into a power purchase agreement with Turlock Irrigation District (Turlock) in which PRC agreed to provide Turlock with its share of the Boardman output. In October 2005, Boardman experienced an outage that extended into 2006.

In 2007, Turlock filed a lawsuit against PGE in Multnomah County Circuit Court in the state of Oregon, alleging breach of contract, negligence, and gross negligence, and seeking damages in excess of $15 million as a result of having to purchase power in the open market to replace lost output from Boardman during the outage. The complaint further alleges that PRC assigned its litigation rights relating to the outage to Turlock pursuant to an assignment agreement executed in 2007.

PGE sought and received an order joining PRC as a necessary party to the litigation. PRC intervened as a plaintiff, also alleging breach of contract and damages in the amount alleged by Turlock, for the purpose of reimbursing Turlock for those expenses.

In August 2009, PGE filed a motion for summary judgment asserting, among other things, that Turlock does not have standing to bring a contract or tort claim against PGE, that damages based on economic loss are not recoverable under a tort claim, and that, under the OOA, the parties have waived the right to bring tort claims based on a theory of negligence. In November 2009, the Court denied PGE’s motion for summary judgment. A trial has been scheduled for February 2011.

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

City of Glendale Claim

In September 1988, PGE and the City of Glendale, California (Glendale) entered into a Long-Term Power Sale and Exchange Agreement (Agreement) pursuant to which Glendale purchases up to 20 MW of firm system capacity from PGE as scheduled by Glendale. The Agreement remains effective until 2012. In

2005, Glendale disputed the price that PGE had been charging for power under the contract and requested refunds. In addition, Glendale asserted that the closure of Trojan triggered a duty under the Agreement to renegotiate price terms.

On August 25, 2005, PGE filed a complaint against Glendale, requesting a declaratory ruling that PGE does not owe Glendale any refunds under the Agreement. In response to PGE’s complaint, Glendale filed a counterclaim against PGE seeking approximately $23.3 million, plus interest. Subsequently, each party filed a motion for summary judgment. In July 2009, the Court granted PGE’s motion for summary judgment in substantial part and denied Glendale’s motion for summary judgment.

The parties have reached a tentative settlement, pursuant to which the parties agreed to reduce future payments by Glendale by approximately $2 million over the remaining life of the contract and amend the contract to clarify certain provisions. The tentative settlement is contingent upon a formal contract amendment and approval by the Glendale City Council and is subject to FERC approval. On April 7, 2010, the trial court dismissed the lawsuit, allowing that it could reopen the matter if a formal contract amendment is not consummated by June 7, 2010.

Management believes that the ultimate outcome of this matter will not have a material adverse impact on the financial condition, results of operations, or cash flows of the Company.

Regulatory Matters

Pacific Northwest Refund Proceeding

In July 2001, the FERC called for a 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 June 2003, the FERC issued an order terminating the proceeding and denying the claims for refunds. Parties appealed various aspects of the FERC order to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit).

In August 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. After denying requests for rehearing, the Ninth Circuit on April 16, 2009 issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC. In January 2010, the Supreme Court of the United States denied a petition for certiorari filed by various sellers, including PGE.

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

The settlement between PGE and certain other parties in the California refund case in docket No. EL00-95, et. seq., approved by the FERC in May 2007, resolved all claims 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 did not settle potential claims from other market participants relating to transactions in the Pacific Northwest.

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

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. However, management believes that the outcome will not have a material adverse impact on the financial condition, results of operations, or cash flows of the Company.

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, the EPA requested information from various parties, including PGE, concerning 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. During 2009 and early 2010, the EPA has listed 27 additional PRPs.

The EPA will determine the boundaries of the site at the conclusion of the RI/FS in a Record of Decision, now expected in 2012, in which it will document its findings and select a preferred cleanup alternative.

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

Harbor Oil

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

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

PGE received a Special Notice Letter for RI/FS from the EPA, dated June 27, 2005, in which the Company was named as one of fourteen PRPs with respect to the Harbor Oil site. On May 31, 2007, an Administrative Order on Consent was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The EPA has approved an RI/FS work plan. On-site sampling commenced in 2008 and has yet to be completed.

Sufficient information is currently not available to determine the total cost of investigation and remediation of the Harbor Oil site or the liability of the PRPs, including PGE. Management cannot predict the ultimate outcome of this matter. However, 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 operations and cash flows in future reporting periods.

Other Matters

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

NOTE 8: GUARANTEES

PGE enters into financial 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, 2010, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

PGE has a loan guarantee to a financial institution that has provided a loan to one of the variable interest entities with which PGE is involved, for the construction of photovoltaic solar generating facilities. For further information on PGE’s relationship with variable interest entities, see Note 9. The maximum amount available pursuant to the loan agreement is $13.1 million, with the maximum potential amount that PGE could be required to pay pursuant to the guarantee equal to the amount outstanding under the loan at the time of default, plus any outstanding interest. As of March 31, 2010, approximately $4 million is outstanding under this loan agreement, which is included in Other current liabilities on PGE’s condensed consolidated balance sheet. PGE has no recourse to any party for any amount it could be required to pay pursuant to this guarantee.

NOTE 9: VARIABLE INTEREST ENTITIES

PGE has determined that its interest in three VIEs, as outlined below, contains the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the power to direct the activities that most significantly affect the entities’ economic performance. Accordingly, the VIEs are consolidated with the Company’s condensed consolidated financial statements. All three arrangements 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 Limited Liability Corporations (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.

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) PGE has the expertise to own and operate electric generating facilities and is authorized to operate the LLCs pursuant to the operating agreements, and therefore PGE has control over the most significant activities 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) based on projections prepared in accordance with the operating agreement, PGE expects to absorb a majority of the expected losses of the LLCs.

During the first quarter of 2009, impairment losses of $7 million, which are classified in Depreciation and amortization expense, were recognized on two of 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 to be amortized over their remaining estimated useful lives.

As noted above, PGE has consolidated the VIEs 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.

There are no restrictions on the LLCs’ assets included in PGE’s consolidated balance sheet as of March 31, 2010 and December 31, 2009, with carrying amounts of those assets totaling $11.1 million and $6.9 million, respectively, substantially all of which are classified as Electric utility plant, net. As of March 31, 2010, the LLCs’ liabilities totaled $4.1 million, substantially all of which are classified as Other current liabilities, while as of December 31, 2009, the LLCs’ total liabilities were nominal.

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 and 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 7, Contingencies, in the Notes to Condensed Consolidated Financial Statements;

•

unseasonable or extreme weather and other natural phenomena, which in addition to affecting PGE’s customers’ demand for power, could significantly affect the Company’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 systems;

•

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

•

the continuing effects of weak economies in the state of Oregon and the United States, including decreased demand for electricity and reduced revenue from sales of excess energy during periods of low wholesale market prices, impaired financial soundness of vendors and service providers and elevated levels of uncollectible customer accounts;

•

capital market conditions, including access to capital, interest rate volatility, reductions in demand for investment-grade commercial paper and the availability and cost of capital, as well as changes in PGE’s credit ratings, which could have an impact on the Company’s cost of capital and its ability to access the capital markets to support requirements for working capital, construction costs, and the repayments of maturing debt;

•

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;

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

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

•

employee workforce factors, including aging, potential strikes, work stoppages, and transitions in senior management;

•

general political, economic, and financial market conditions;

•

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

•

acts of war or terrorism; and

•

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

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

Overview

Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) is intended to provide an understanding of the business environment, results of operations, and financial condition of PGE. MD&A should be read in conjunction with the Company’s condensed consolidated financial statements contained in this report as well as the consolidated financial statements and disclosures in its Annual Report on Form 10-K for the year ended December 31, 2009, and other periodic and current reports filed with the SEC.

Operating Activities - PGE is a vertically integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon, as well as the wholesale sale of electricity and natural gas in the western United States and Canada. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to customers in its service territory.

The Company’s revenues and income from operations can fluctuate during the year due to the impacts of seasonal weather conditions on demand for electricity, price changes, customer usage patterns (which can be affected by the local economy), and the availability and price of purchased power and fuel. PGE is a winter-peaking utility that typically experiences its highest retail energy sales during the winter heating season, with a slightly lower peak in the summer that generally results from air conditioning demand.

Customers and Demand - Electricity use decreased during the first quarter of 2010 as the result of warmer than normal weather and the continued effects of a weak economy and high unemployment. Retail energy deliveries decreased 9% in the first quarter of 2010 compared to the first quarter of 2009.

The average temperature for the Portland metropolitan area was 3.5 degrees above normal during the first quarter of 2010, compared to 0.9 degrees above normal during the first quarter of 2009. As a result, heating degree-days decreased 19% in the first quarter of 2010 compared to the first quarter of 2009, contributing to a 13% decrease in energy deliveries to residential customers.

On a weather adjusted basis, retail energy deliveries decreased 3.3%, with deliveries to residential customers down 2.2%, primarily due to the effects of sustained high unemployment, despite an increase in the average number of residential customers of approximately 2,400. Weather adjusted retail energy deliveries to commercial and industrial customers decreased 3.3% and 6%, respectively, primarily due to the weak economy, despite an increase in the average number of commercial and industrial customers of approximately 1,400.

The average seasonally adjusted unemployment rates for the first quarters of 2010 and 2009 are as follows:


	United States		Oregon		Portland/ Salem
Q1 2010	9.7	%	10.6	%	10.3	%
Q1 2009	8.2		10.6		9.8

PGE projects that weather adjusted retail energy deliveries for 2010 will be largely unchanged from 2009. The Company anticipates energy deliveries to paper products manufacturers to be lower than in 2009. Such decline, along with the effects of the continued weak economy, is expected to be partially offset by a moderate increase in 2010 deliveries to other existing industrial customers, including those in the high technology sector.

Power Operations - PGE’s total system load in the first quarter of 2010 was down 6% from the first quarter of 2009 due to decreased demand, as discussed above. To meet the energy and capacity needs of its customers, the Company utilizes a combination of its own generating resources and wholesale market transactions. Based on numerous factors, such as plant availability, demand, and current wholesale prices, PGE makes economic dispatch decisions continuously throughout a given period in an effort to minimize power costs for its retail customers. Additionally, the proportion of power generated and purchased in the wholesale market to meet the Company’s retail load requirement can vary from period to period. The average power cost of the Company’s total system load in the first quarter of 2010 decreased 6% from the first quarter of 2009, primarily due to an increase in the proportion of power provided by Company-owned generating resources and a decrease in the cost of fuel used in natural gas-fired production.

During the first quarter of 2010, the Company’s generating plants provided approximately 68% of its retail load requirement, compared to 64% in the first quarter of 2009. Availability of the plants that PGE operates approximated 95% in the first quarter of 2010 and 99% in the first quarter of 2009. The availability of Colstrip, which PGE does not operate, approximated 97% in the first quarters of 2010 and 2009.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia projects decreased 17% in the first quarter of 2010 from the first quarter of 2009. These resources provided approximately 20% of the Company’s retail load requirement in the first quarter of 2010, compared to 23% in the first quarter of 2009. Energy received from these sources fell short of projections in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 21% and 12% in the first quarters of 2010 and 2009, respectively. Such projections, which are finalized and filed with the OPUC in November each year, establish the power cost component of retail prices for the following calendar year. Any shortfall in energy received from hydro resources from that projected in the AUT is generally replaced with power from higher cost sources. Current forecasts of the April-to-September 2010 runoff indicate continued below normal regional hydro conditions.

Biglow Canyon Phase III, a 175 MW wind project consisting of 76 wind turbines, is currently under construction and is expected to be completed in the third quarter of 2010, with individual units expected to be placed in service beginning in the second quarter of 2010. This addition to PGE’s generation portfolio is another important step in helping the Company meet Oregon’s Renewable Energy Standard (RES). In the first quarter of 2010, wind generation increased 29% compared to the first quarter of 2009, primarily a result of Phase II becoming operational during the second and third quarters of 2009, and provided 1.8% of PGE’s retail load requirement compared to 1.3% in the first quarter of 2009.

General Rate Case - Regulatory review of PGE’s 2011 General Rate Case, filed with the OPUC in February 2010, is continuing, with a final order expected to be issued by mid-December 2010 and new rates expected to become effective January 1, 2011. PGE filed for a $125 million increase in annual revenues, representing an approximate 7.4% overall increase in customer prices, which includes a 2% decrease related to projected power costs. The filing also includes a proposed capital structure of 50% debt and 50% equity, a return on equity of 10.5%, a cost of capital of 8.289%, and an average rate base of approximately $3.2 billion.

In addition, PGE is proposing the following:

•

Modification of the PCAM for closer alignment with similar mechanisms of comparable electric utilities, with a symmetrical deadband of $10 million above or below the established net variable power cost baseline;

•

Continuation of decoupling and certain other adjustment mechanisms;

•

Plans to recover costs of future major storm damage;

•

Plans to recover environmental mitigation and remediation expenses for specifically identified projects;

•

Recovery of carrying costs/benefits related to power supply collateral requirements; and

•

Recovery of costs associated with the Company’s defined benefit pension plan.

Based upon uncertainties related to the expected life and alternative operating plans for PGE’s Boardman coal plant, the Company has included a separate tariff to implement necessary rate changes resulting from decisions regarding the future operation of the plant. For additional information, see Boardman emissions controls in the Capital Requirements section of Item 2. - “Management’s Discussion and Analysis of Financial Condition and Results of Operations.”

Additional information regarding PGE’s 2011 General Rate Case filing is available on the Company’s Internet website at www.portlandgeneral.com and on the OPUC Internet website at www.puc.state.or.us.

Capital Requirements and Financing - In November 2009, PGE filed with the OPUC a new Integrated Resource Plan (IRP) that includes a four-year strategy for the acquisition of new resources and a 20-year strategy that outlines long-term expectations for resource needs and portfolio performance, which included the operation of Boardman until at least 2040 with the installation of required emissions controls at a cost estimated from $520 million to $560 million (100% of total costs, excluding AFDC). In the proposed IRP, PGE projects that it will need approximately 873 MWa of new resources by 2015, increasing to approximately 1,396 MWa by 2020, to meet customer demand. These requirements are primarily driven by continued load growth and the expiration of certain long-term power supply arrangements and are expected to be met by energy efficiency measures, additional renewable resources, new transmission capability, and new generating plants.

In April 2010, PGE filed an addendum to its proposed IRP that requests ceasing coal-fired operations at Boardman at the end of 2020 if (i) environmental regulatory bodies modify existing rules; (ii) issues related to forthcoming Clean Air Act standards are resolved; and (iii) pending litigation with the Sierra Club is resolved. If these contingencies are not resolved, the Company will pursue OPUC acknowledgement for the operation of Boardman until at least 2040, as originally proposed, which includes the installation of required emissions controls. For additional information about emissions controls for the Boardman plant, see Boardman emissions controls in the Capital Requirements section of this Item 2.

PGE’s 2010 capital requirements are related primarily to the following major projects and debt maturities for 2010:

•

Construction of Biglow Canyon Phase III, the smart meter project, and ongoing capital expenditures for the upgrade, replacement, and expansion of transmission, distribution and generation infrastructure. Capital expenditures are expected to approximate $495 million for the year. See the Capital Requirements section of this Item 2.

•

The maturity of $186 million of long-term debt in 2010, of which $149 million matured in the first quarter of 2010 and $37 million of which matures in the second quarter of 2010.

To fund these projects and debt maturities, the Company expects to issue a total of $250 million of long-term debt in 2010, with $191 million issued in the first quarter. In addition, PGE expects cash from operations to approximate $475 million in 2010.

Legal, Regulatory and Environmental Matters - PGE is a party to certain proceedings whose ultimate outcome may have a material impact on the results of operations and cash flows in future reporting periods. These include matters related to:

•

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

•

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

•

Investigation of environmental matters at Portland Harbor.

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

The following retail price adjustments, as approved by the OPUC, became effective during the first quarter of 2010:

•

Power Costs - Pursuant to the Annual Power Cost Update Tariff (AUT) process, PGE annually files an estimate of the following year’s power costs. Under this process, new prices become effective January 1st each year. In the event a general rate case is filed in any given year, forecasted power costs would be included in such filing. The AUT for 2010 resulted in an overall 4.1% decrease in retail prices, effective January 1, 2010.

•

Renewable Resources - Pursuant to a renewable adjustment clause (RAC) mechanism, PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The Company submits an annual filing to the OPUC by April 1st each year, with rates to become effective January 1st of the following year. As part of the RAC, the OPUC has authorized the deferral of eligible costs not yet included in rates until their January 1st effective date. Under this mechanism, PGE filed for recovery of its investments in Biglow Canyon Phase II and certain solar generating facilities in 2009, which resulted in an overall 2.5% increase in retail customer prices, effective January 1, 2010.

•

PCAM - Customer refunds related to results of the 2007 PCAM, totaling $16 million, were completed in 2009, resulting in an approximate 1.1% increase in customer prices on January 1, 2010. No customer refunds or collections were recorded for the first quarter of 2010 and the years 2009 and 2008.

•

Selective Water Withdrawal project - In January 2010, the Selective Water Withdrawal structure at PGE’s Pelton/Round Butte hydroelectric project was completed. Effective February 1, 2010, the Company has been allowed an annualized revenue requirement of $9.8 million related to this capital project, representing a 0.6% overall increase in customer prices. Such increase remains in effect until new rates are established pursuant to the Company’s 2011 General Rate Case.

The above items, combined with other miscellaneous tariff changes, resulted in an overall retail price decrease of approximately 1.2% during the first quarter of 2010.

Rate actions pending include, but are not limited to, the following:

•

Utility Rate Treatment of Income Taxes (SB 408) - Following its formal review of PGE’s tax report for the calendar year 2008, the OPUC issued an order on April 6, 2010 that authorizes the Company to refund to retail customers approximately $9.6 million, plus accrued interest, over a one-year period beginning June 1, 2010.

For the year 2009, PGE recorded an estimated $13 million refund to customers, which, if approved by the OPUC, would begin June 1, 2011.

•

Decoupling Mechanism - Effective February 1, 2009, the OPUC authorized a decoupling mechanism, which is intended to provide for recovery of reduced revenues resulting from a reduction in electricity sales attributable to energy efficiency and conservation efforts by residential and certain commercial customers. In April 2010, PGE filed an advice with the OPUC requesting authorization to refund to customers $2.7 million related to the twelve month period ended January 31, 2010, as weather adjusted use per customer exceeded that approved in the 2009 General Rate Case. Such refunds to customers are expected to begin June 1, 2010.

•

Renewable Resources - On April 1, 2010, PGE submitted its RAC filing, requesting, among other things, $17 million in 2010 related to Biglow Canyon Phase III. Effective January 1, 2011, the revenue requirements related to Biglow Canyon Phase III are expected to be reflected in retail prices, an increase of approximately 1.9%, through the Company’s 2011 General Rate Case.

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, 2009, filed with the SEC on February 25, 2010.

Results of Operations

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


	Three Months Ended March 31,
	2010				2009
	Amount		% of Revenues		Amount			% of Revenues
Revenues	$	449	100	%	$	485		100	%
Operating expenses:
Purchased power and fuel		224	50			255		52
Production and distribution		39	8			42		9
Administrative and other		45	10			45		9
Depreciation and amortization		57	13			57		12
Taxes other than income taxes		23	5			23		5

Total operating expenses		388	86			422		87

Income from operations		61	14			63		13
Other income (expense):
Allowance for equity funds used during construction		4	1			2		-
Miscellaneous income (expense), net		1	-			(3	)	-

Other income (expense), net		5	1			(1	)	-
Interest expense		29	7			25		5

Income before income taxes		37	8			37		8
Income taxes		10	2			13		3

Net income		27	6			24		5
Less: net losses attributable to the noncontrolling interests		-	-			(7	)	(1	)

Net income attributable to Portland General Electric Company	$	27	6	%	$	31		6	%

Net income attributable to Portland General Electric Company was $27 million, or $0.36 per diluted share, for the first quarter of 2010 compared to $31 million, or $0.47 per diluted share, for the first quarter of 2009. Operating results for the first quarter of 2010 were adversely affected by a 9% decrease in retail energy deliveries, caused by both warmer weather and a continued weak economy. A 13% decrease in residential energy sales reflected weather that was warmer than normal in the first quarter of 2010 and colder than normal in the first quarter of 2009. The continuing effects of a weak economy contributed to a 5% decrease in energy deliveries to commercial and industrial customers in the first quarter of 2010.

The average variable power cost decreased 6% in the first quarter of 2010 compared to the first quarter of 2009, primarily due to an overall decrease in the cost of thermal production, which was driven by a decrease in the cost of fuel used in natural gas-fired production, combined with a reduction in load requirements and a shift in the mix of sources of energy. The average variable power cost decreased despite a reduction of 17% in energy received from Company-owned and purchased hydro resources.

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


	Three Months Ended March 31,
	2010				2009
	Amount		% of Total		Amount			% of Total
Revenues:
Retail sales:
Residential	$	206	46	%	$	233		48	%
Commercial		140	31			149		31
Industrial		50	11			42		8

Total retail sales		396	88			424		87
Direct access customers		3	1			(1	)	-
Other retail revenues		21	5			29		6

Total retail revenues		420	94			452		93
Wholesale revenues		21	4			28		6
Other operating revenues		8	2			5		1

Total revenues	$	449	100	%	$	485		100	%


Average number of retail customers:
Residential		716,181	88	%		713,747		88	%
Commercial		100,157	12			98,771		12
Industrial		258	-			249		-
Direct access:
Commercial		221	-			239		-
Industrial		14	-			25		-

		816,831	100	%		813,031		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,
	2010				2009
Energy sold and delivered:
Retail energy sales:
Residential	2,046		39	%	2,351		40	%
Commercial	1,651		31		1,733		30
Industrial	736		14		604		10

Total retail energy sales	4,433		84		4,688		80

Delivery to direct access customers:
Commercial	85		2		88		2
Industrial	177		3		362		6

	262		5		450		8

Total retail energy deliveries	4,695		89		5,138		88
Wholesale sales	580		11		709		12

Total energy sold and delivered	5,275		100	%	5,847		100	%


Sources of energy:
Generation:
Thermal	2,719		50	%	2,645		46	%
Hydro	479		9		504		9
Wind	88		2		68		1

Total generation	3,286		61		3,217		56

Purchased power:
Term purchases	1,257		23		1,640		28
Purchased hydro	503		9		681		12
Spot purchases	343		7		220		4

Total purchased power	2,103		39		2,541		44

Total system load	5,389		100	%	5,758		100	%

Less: wholesale sales	(580	)			(709	)

Retail load requirement	4,809				5,049

Revenues decreased $36 million, or 7%, in the first quarter of 2010 compared to the first quarter of 2009 as a result of the following offsetting factors:

Total retail revenues decreased $32 million, or 7%, due primarily to the following offsetting factors:

•

A $25 million decrease resulting from a 9% decline in total retail energy deliveries, due to both warmer weather in 2010 (the third warmest first quarter in the past 60 years) and the continuing effects of a weak economy. Partially offsetting this decrease in revenues was the impact of an approximate 3,800 increase in the average number of customers served and the return of certain former direct access customers to PGE for their energy requirements;

•

A $15 million decrease resulting from a 4% reduction in average retail prices during the first quarter of 2010, primarily due to lower power costs;

•

A $5 million increase due to a higher estimated collection from customers recorded in the first quarter of 2010 related to the decoupling mechanism, resulting from lower weather adjusted use per customer than that approved in the 2009 General Rate Case; and

•

A $3 million increase resulting from tariff changes applicable to direct access customers.

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 2010, heating degree-days decreased 19% compared to the first quarter of 2009. 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
	2010	2009
January	609	767
February	510	656
March	510	599

1st quarter	1,629	2,022

15-year average for the quarter	1,849	1,831

On a weather adjusted basis, retail energy deliveries decreased 3.3% in the first quarter of 2010 compared to the first quarter of 2009, with deliveries to residential, commercial, and industrial customers decreasing by 2.2%, 3.3%, and 6%, respectively. PGE projects that weather adjusted energy deliveries will remain essentially flat in 2010 compared to 2009.

Other retail revenues include certain customer credits and charges that are fully offset within Total retail revenues. The $8 million decrease in the first quarter of 2010 was due primarily to changes in credits and charges related to the PCAM for 2007 and SB 408 for 2006 and 2007, partially offset by the results of the decoupling mechanism.

Wholesale revenues result from sales of electricity to utilities and power marketers, which are made in conjunction with the Company’s effort to balance retail load with power supply, manage risk, and administer its existing long-term wholesale contracts. Such sales can vary significantly from period to period. Wholesale revenues decreased $7 million, or 25%, in the first quarter of 2010 compared to the first quarter of 2009 due primarily to a $5 million decrease related to an 18% decline in wholesale energy sales and an approximate $2 million decrease related to a tentative settlement and contract amendment with the City of Glendale, California.

Other operating revenues increased $2 million, or 40%, due to sales of fuel oil and increased revenues from the resale of transmission capacity in the first quarter of 2010.

Purchased power and fuel expense decreased $31 million, or 12%, in the first quarter of 2010 compared to the first quarter of 2009, with $17 million related to a 6% decrease in total system load and $14 million related to a 6% decrease in average variable power cost. The average variable power cost was $41.65 per MWh in the first quarter of 2010 compared to $44.42 per MWh in the first quarter of 2009.

The decrease in Purchased power and fuel expense consisted of the following:

•

A $26 million, or 17%, decrease in the cost of purchased power, driven by a decrease in purchases. The decrease in purchases was offset by a 1% increase in the average cost of purchased power; and

•

A $5 million, or 5%, decrease in the cost of thermal production, due to an 8% decrease in average cost, partially offset by a 3% increase in generation. The decrease in average cost was primarily due to an 11% decrease in the average cost of natural gas-fired production, while the increase in generation was driven by economic dispatch decisions.

Regional hydro conditions were below normal in the first quarter of 2010. PGE-owned hydro production and energy received under contracts from mid-Columbia projects were down 5% and 26%, respectively, from the first quarter of 2009. Current forecasts indicate that regional hydro conditions in 2010 will be below normal levels. The following indicates the forecast of the April-to-September runoff (issued April 22, 2010) compared to the actual runoffs (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):

*	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.

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 2010, the deadband ranges from approximately $17 million below, to $35 million above, the baseline NVPC. As of March 31, 2010, the difference between actual and baseline NVPC for the first quarter of 2010 was approximately $7 million above the baseline, with NVPC for the year ending December 31, 2010 expected to be above the baseline but below the established deadband threshold of $35 million; accordingly, no amount was recorded for collection from retail customers as of March 31, 2010. The difference between the actual and baseline NVPC for the year 2009 was $22 million above the baseline NVPC, with $3 million above the baseline NVPC in the first quarter of 2009. As the difference between actual and baseline NVPC for the year 2009 was below the threshold of $29 million, no collection from customers was recorded in 2009.

Production and distribution expense decreased $3 million, or 7%, in the first quarter of 2010 compared to the first quarter of 2009 due to a reduction in repair and restoration activities, related primarily to wind storms in the first quarter of 2009.

Administrative and other expense in the first quarter of 2010 was unchanged from that of the first quarter of 2009. A $1 million reduction in incentive compensation and a $1 million reduction in customer account write-offs were offset by an increase in employee benefit expenses, including pension costs.

Depreciation and amortization expense in the first quarter of 2010 was unchanged from that of the first quarter of 2009. Increases related to Biglow Canyon Phase II, the smart meter project, and other capital

additions were offset by a $7 million decrease related to 2009 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 9 to the Condensed Consolidated Financial Statements included in Item 1 - “Financial Statements”.

Other income (expense), net was $5 million in the first quarter of 2010 compared to ($1) million in the first quarter of 2009. The change is primarily due to the net effect of the following:

•

A $5 million increase in income from non-qualified benefit plan trust assets, resulting from a $2 million increase in the fair value of the plan assets in the first quarter of 2010 compared to a $3 million decrease in the first quarter of 2009; and

•

A $2 million increase in the allowance for equity funds used during construction as a result of higher construction work in progress balances in 2010, related primarily to Biglow Canyon Phase III.

Interest expense increased $4 million, or 16%, in the first quarter of 2010 compared to the first quarter of 2009. The increase was due primarily to a higher average balance of outstanding long-term debt in the first quarter of 2010 ($1,766 million) compared to the first quarter of 2009 ($1,372 million).

Income taxes decreased $3 million, or 23%, in the first quarter of 2010 compared to the first quarter of 2009, primarily due to lower income before taxes in 2010. An increase in federal energy tax credits was offset by higher state income taxes resulting from an increased tax rate enacted in 2010 and retroactive to 2009. The effective tax rate was 27% in the first quarter of 2010 compared to 35.1% in the first quarter of 2009.

Net losses attributable to the noncontrolling interests represents the noncontrolling interests’ portion of the net losses of PGE’s less-than-wholly-owned subsidiaries. The majority of the $7 million in the first quarter of 2009 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):


	2010				2011		2012		2013		2014
Ongoing capital expenditures	$	255				$240 - $260		$225 - $245		$235 - $255		$275 - $295
Biglow Canyon Phase III		175		-				-		-		-
Hydro licensing and construction		10				$90 - $110
Smart meter project		40		-				-		-		-
Boardman emissions controls ⁽¹⁾		15				$10 - $30				-		-

Total capital expenditures	$	495	⁽²⁾

Long-term debt maturities	$	186			$	-	$	100	$	100	$	73

⁽¹⁾

Represents 80% of estimated total costs based on installation of nitrogen oxide and mercury controls to meet regulatory requirements. In 1985, PGE sold a undivided 15% interest in Boardman to a third party, reducing the Company’s ownership interest from 80% to 65%. The purchaser has certain rights to participate in the financing of the portion of the total capital cost attributable to its interest. If the purchaser does not exercise its rights to finance the portion of the total cost attributable to its interest, PGE’s share of the total cost for the emissions controls at Boardman is expected to be 80%.

⁽²⁾

Amounts shown include preliminary engineering and removal costs, which are included in other net operating activities in the condensed consolidated statements of cash flows.

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

Biglow Canyon Phase III - Phase III is currently under construction, with an estimated total cost of $390 million, including $20 million of AFDC, and an installed capacity of 175 MW. Installation of wind turbines is expected to begin in the second quarter of 2010, with all 76 turbines expected to be placed in service by the end of the third quarter of 2010.

Hydro licensing and construction - PGE anticipates that in 2010 the FERC will issue a decision on PGE’s application for a new 45-year license for the Company’s four hydroelectric projects on the Clackamas River. Capital spending requirements reflected in the table above relate primarily to modifications to the projects to enhance fish passage and survival, as required by conditions contained in a 2006 settlement agreement submitted to the FERC. Pending issuance of the new license, the projects are operating under annual licenses issued by the FERC.

Smart meter project - PGE has installed approximately 646,000 new customer smart meters as of April 13, 2010. A total of approximately 850,000 new customer meters is expected to be installed, with the remainder expected to be installed by the end of 2010. This project, which enables two-way remote communication with the Company, is expected to provide improved services, operational efficiencies, and a reduction in future operating expenses. The capital cost of this project is estimated at $130 million to $135 million, excluding AFDC.

Boardman emissions controls - Current rules - Pursuant to the Regional Haze Program and the Best Available Retrofit Technology (BART) Determination process, in June 2009, the OEQC adopted a rule that would require the installation of emissions controls at Boardman. The rule requires controls to limit:

•

nitrogen oxides (NO_X ), to be installed by July 1, 2011; and

•

sulfur dioxide (SO₂ ) and particulate matter, to be installed by July 1, 2014.

The installation of these emissions controls would meet federal requirements for installing BART. PGE estimates the total cost of the NO_x controls, excluding AFDC, at approximately $28 million while the SO₂ and particulate matter controls would cost approximately $290 million.

The OEQC rule also requires the installation of Selective Catalytic Reduction (SCR) for additional NO_X control, with completion by July 1, 2017, which would meet regulatory requirements for reasonable progress towards haze emissions reduction goals. PGE estimates the total cost of the SCR would be approximately $180 million.

In addition, under a separate rulemaking procedure with the DEQ, PGE has agreed to install controls that are expected to eliminate 90 percent of the mercury emissions from the plant by 2012, to meet the requirements of the Oregon Utility Mercury Rule. Current acquisition and construction schedules should allow the Company to meet this deadline a year early at an estimated total cost of approximately $8 million.

IRP addendum and BART II petition - PGE submitted its 2009 IRP to the OPUC in November 2009. In that plan, given the options available to PGE under the current Regional Haze Rule of either installing NOx controls required by July 1, 2011 and ceasing operation of Boardman in 2014, or installing the additional controls called for in the regional haze rule and continuing operations, the Company recommended the long-term continued operation of Boardman through at least 2040 with the additional controls.

Discussions with IRP stakeholders indicated support for the analysis of an alternative strategy regarding Boardman. On April 9, 2010, the Company filed an IRP addendum with the OPUC seeking approval to cease coal-fired operations at Boardman in 2020, subject to the occurrence of the following three conditions by March 31, 2011:

i)	the OEQC must approve the Company’s BART II petition for Boardman, submitted to the DEQ on April 2, 2010, subject to certain regulatory and legal issues that must be resolved. Under the petition, PGE would:

•

install the NOx controls called for under the current BART rule by July 1, 2011;

•

use a lower sulfur coal to fire the plant’s boiler; and

•

close the plant in 2020, ending all coal-related emissions at least 20 years ahead of schedule while significantly reducing Oregon’s contribution to greenhouse gas.

ii)	PGE must have reasonable assurance that Boardman will be compliant with forthcoming federal standards under the Clean Air Act without further requirement to install additional controls at Boardman beyond those under the Company’s BART II petition; and

iii)

the pending litigation with the Sierra Club (see “Sierra Club et al. v. Portland General Electric Company” in Item 3. - “Legal Proceedings” contained in the Company’s 2009 Annual Report on Form 10-K filed with the SEC on February 25, 2010) must be resolved in such a way that PGE will not be required to install controls at Boardman beyond those required under the Company’s BART II petition.

The IRP addendum requests OPUC acknowledgment to proceed with installing all required emission controls and operating Boardman through at least 2040 if any of the above three conditions is not met by March 31, 2011.

Regardless of whether the plant ceases operation in 2020 or continues to operate through at least 2040, the Company intends to install emissions controls for NO_x by July 1, 2011 and mercury by 2012 at a total cost of approximately $36 million, excluding AFDC. The Company’s share of these costs of approximately $29 million is included in the table above. Costs of controls to reduce the SO₂and particulate matter emissions, and the SCR controls, are not included in the capital requirements table above due to uncertainties with respect to their installation.

In the event of a 2020 closure, the Company would seek to recover in future rates its remaining investment in Boardman (approximately $126 million as of March 31, 2010), plus the cost of the NO_x and mercury controls, and decommissioning and other costs related to the plant’s closure, as well as the construction or acquisition costs of replacement generating capacity. It is estimated that accelerating the recovery of such costs from 30 years to ten years would result in an approximate 1% increase in customer prices.

Liquidity

PGE’s access to short-term debt markets, including revolving credit from banks, helps provide necessary liquidity to support the Company’s current operating activities, including the purchase of power and fuel. 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 deposit requirements related to wholesale market activities, which can vary depending upon the Company’s forward positions and the corresponding price curves.

The following summarizes PGE’s cash flows for the periods presented (in millions):


	Three Months Ended March 31,
	2010			2009
Cash and cash equivalents, beginning of period	$	31		$	10
Net cash provided by (used in):
Operating activities		68			40
Investing activities		(73	)		(91	)
Financing activities		26			88

Net increase in cash and cash equivalents		21			37

Cash and cash equivalents, end of period	$	52		$	47

Cash Flows from Operating Activities - Cash flows from operating activities are generally determined by the amount and timing of cash received from customers and payments made to vendors, as well as the nature and amount of non-cash items, including depreciation and amortization, included in net income during a given period. The $28 million increase in cash provided by operating activities in the first quarter of 2010 compared to the first quarter of 2009 was largely due to a decrease in payments made to

vendors and an increase in cash received from customers, partially offset by an increase in margin deposit requirements pursuant to power and natural gas purchase agreements.

A significant portion of cash provided by operations consists of recovery in customer prices of non-cash charges for depreciation and amortization. PGE estimates that depreciation and amortization charges will approximate $225 million in 2010. Such recovery, combined with all other sources of cash from operations, is estimated to be approximately $475 million in 2010.

Cash Flows from Investing Activities - Cash flows used in investing activities consist primarily of capital expenditures related to new construction and improvements to PGE’s distribution, transmission, and generation facilities. Capital expenditures in the first quarter of 2010 were comparable to the first quarter of 2009. The decrease in net cash used in investing activities is due to a distribution from the Nuclear decommissioning trust to PGE in the first quarter of 2010.

The Company plans $495 million of capital expenditures in 2010 related to Biglow Canyon Phase III, the smart meter project, hydro licensing and construction, and upgrades and replacement of transmission, distribution and generation infrastructure. See “Capital Requirements” section above for additional information.

Cash Flows from Financing Activities - Financing activities provide supplemental cash for both day-to-day operations and capital requirements as needed. During the first quarter of 2010, net cash provided by such activities consisted primarily of proceeds from the issuance of long-term debt of $191 million, partially offset by the repayment of long-term debt of $149 million and the payment of dividends of $19 million. During the first quarter of 2009, net cash provided by financing activities consisted of the issuance of common stock for net proceeds of $170 million, proceeds from the issuance of long-term debt of $130 million, the net repayment of short-term debt 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 capital contributions from noncontrolling interests in the solar projects.

PGE expects to issue approximately $250 million of debt securities in 2010, of which $191 million was issued in the first quarter of 2010.

Dividends on Common Stock

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

In the first quarter of 2010, the Board of Directors declared a dividend of $0.255 per common share, for a total of $20 million, with payments made on April 15, 2010 to shareholders of record on March 25, 2010.

Debt and Equity Financings

PGE’s ability to secure sufficient long-term capital at a reasonable cost is determined by its financial performance and outlook, capital expenditure requirements, alternatives available to investors, and other factors. 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 expected to be generated from operations provide sufficient liquidity to meet the Company’s anticipated capital and operating requirements. However, the Company’s ability to issue long-term debt and equity could be adversely affected by changes in capital market conditions.

Short-term Debt. PGE has approval from the FERC to issue short-term debt of up to a total of $750 million through February 6, 2012 and currently has the following unsecured revolving credit facilities:

•

A $370 million syndicated credit facility, with $10 million and $360 million scheduled to terminate July 2012 and July 2013, respectively;

•

A $200 million syndicated credit facility, which is scheduled to terminate in December 2012; and

•

A $30 million credit facility, which is scheduled to terminate in June 2012.

These credit facilities supplement operating cash flow and provide a primary source of liquidity. Pursuant to the individual terms of the agreements, the credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings. The $370 million and $30 million credit facilities also permit the issuance of standby letters of credit. As of March 31, 2010, PGE had no borrowings or commercial paper outstanding and had $233 million of letters of credit outstanding. As of March 31, 2010, the aggregate unused available credit under the credit facilities was $367 million.

Long-term Debt. To fund current capital expenditures and current maturities of long-term debt, PGE anticipates issuing a total of approximately $250 million of long-term debt in 2010, of which $191 million was issued in the first quarter of 2010, as follows:

•

On January 15th, issued $70 million of 3.46% Series First Mortgage Bonds due January 2015, with interest payable semi-annually on January 15th and July 15th; and

•

On March 11th, remarketed $121 million of Pollution Control Bonds at 5% due May 2033 with interest payable semi-annually on March 1st and September 1st. The Pollution Control Bonds are backed by first mortgage bonds.

As of March 31, 2010, the Company holds $21 million of repurchased Pollution Control Bonds, which can be remarketed through 2033.

In addition to the above issuances of long-term debt, PGE repaid $149 million of 7.875% unsecured notes in March 2010.

Capital Structure. PGE’s financial objectives include the balancing of debt and equity to maintain an optimal 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 46.5% and 46.9% as of March 31, 2010 and December 31, 2009, 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 Ratings Services (S&P). PGE’s current credit ratings and outlook are as follows:


	Moody’s	S&P
First Mortgage Bonds	A3	A-
Senior unsecured debt	Baa2	BBB
Commercial paper	Prime-2	A-2
Outlook	Positive	Stable

Should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade, the Company could be subject to requests by 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 contract terms and commodity prices and can vary from period to period. As of March 31, 2010, PGE had posted approximately $302 million of collateral with these counterparties, consisting of $89 million in cash and $213 million in letters of credit, of which $45 million is affiliated with master netting agreements. Provided that market prices remain unchanged, the Company anticipates that approximately 42% of the posted collateral would no longer be required by the end of 2010 as the related contracts are settled, with 81% expected to roll off by the end of 2011.

Based on the Company’s energy portfolio, estimates of current energy market prices, and the level of collateral outstanding as of March 31, 2010, the amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $76 million and decreases to approximately $27 million by December 31, 2010. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $171 million at March 31, 2010 and decreases to approximately $80 million by December 31, 2010.

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 interest coverage and security provisions set forth in the Indenture of Mortgage and Deed of Trust securing the bonds. PGE estimates that, under the most restrictive issuance test in the Indenture of Mortgage and Deed of Trust, the Company could have issued up to approximately $189 million of additional first mortgage bonds on February 28, 2010. Future issuances of first mortgage bonds are 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, 2010, the Company was in compliance with the covenant.

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 2010 and beyond are set forth in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the year ended December 31, 2009, filed with the SEC on February 25, 2010. Such obligations have not changed materially as of March 31, 2010, with the following exceptions:

•

In January 2010, PGE issued $70 million of 3.46% Series First Mortgage Bonds, maturing January 2015;

•

In March 2010, PGE remarketed $121 million of Pollution Control Bonds due May 2033 at 5.0%; and

•

An increase of $38 million for several new capital projects, consisting of $17 million and $21 million in 2010 and 2011, respectively.

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, 2009, filed with the SEC on February 25, 2010.

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, 2010, 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 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, 2009, filed with the SEC on February 25, 2010.

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, 2009, filed with the SEC on February 25, 2010.

Item 6.

Exhibits.


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

3.2		Seventh 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 February 19, 2010).

10.1		Form of Agreement Concerning Indemnification and Related Matters for officers and key employees (incorporated by reference to the Company’s Current Report on Form 8-K filed February 19, 2010).

31.1		Certification of Chief Executive Officer.

31.2		Certification of Chief Financial Officer.

32.2		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 3, 2010	By:	/s/ Maria M. Pope
		Maria M. Pope
		Senior Vice President, Finance, Chief Financial Officer, and Treasurer
		(duly authorized officer and principal financial officer)