Portland General Electric 10Q 2011 Q1 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q



[X]	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2011



[ ]	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). [x] Yes x [ ] 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 29, 2011 is 75,326,041 shares.

Table of Contents

PORTLAND GENERAL ELECTRIC COMPANY

FORM 10-Q

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2011

TABLE OF CONTENTS

Table of Contents

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
CAA		Clean Air Act
CERS		California Energy Resources Scheduling
Colstrip		Colstrip Units 3 and 4 coal plant
EPA		U.S. Environmental Protection Agency
FERC		Federal Energy Regulatory Commission
IRP		Integrated Resource Plan
ISFSI		Independent Spent Fuel Storage Installation
LLC		Limited Liability Company
Moody’s		Moody’s Investors Service
MW		Megawatts
MWa		Average megawatts
MWh		Megawatt hours
NVPC		Net Variable Power Costs
OPUC		Public Utility Commission of Oregon
PCAM		Power Cost Adjustment Mechanism
S&P		Standard & Poor’s Ratings Services
SB 408		Oregon Senate Bill 408 (Oregon Revised Statutes 757.268)
SEC		Securities and Exchange Commission
Trojan		Trojan Nuclear Plant
URP		Utility Reform Project
VIE		Variable Interest Entity

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PART I — FINANCIAL INFORMATION



Item 1.	Financial Statements.

PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF INCOME

(Dollars in millions, except per share amounts)

(Unaudited)



	Three Months Ended March 31,
	2011		2010
Revenues, net	$	484	$	449
Operating expenses:
Purchased power and fuel	194		224
Production and distribution	42		39
Administrative and other	52		45
Depreciation and amortization	56		57
Taxes other than income taxes	25		23
Total operating expenses	369		388
Income from operations	115		61
Other income:
Allowance for equity funds used during construction	1		4
Miscellaneous income, net	2		1
Other income, net	3		5
Interest expense	27		29
Income before income taxes	91		37
Income taxes	22		10
Net income and Net income attributable to Portland General Electric Company	$	69	$	27

Weighted-average shares outstanding (in thousands):
Basic	75,318		75,229
Diluted	75,337		75,246
Earnings per share:
Basic	$	0.92	$	0.36
Diluted	$	0.92	$	0.36
Dividends declared per common share	$	0.260	$	0.255

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(In millions)

(Unaudited)



	March 31, 2011		December 31, 2010
ASSETS
Current assets:
Cash and cash equivalents	$	27	$	4
Accounts receivable, net	156		137
Unbilled revenues	75		93
Inventories	56		56
Margin deposits	80		83
Regulatory assets - current	214		221
Other current assets	81		67
Total current assets	689		661
Electric utility plant, net	4,179		4,133
Regulatory assets - noncurrent	512		544
Non-qualified benefit plan trust	44		44
Nuclear decommissioning trust	34		34
Other noncurrent assets	77		75
Total assets	$	5,535	$	5,491

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS, continued

(Dollars in millions)

(Unaudited)



	March 31, 2011			December 31, 2010
LIABILITIES AND EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$	144		$	169
Liabilities from price risk management activities - current	183			188
Short-term debt	—			19
Current portion of long-term debt	—			10
Regulatory liabilities - current	25			25
Other current liabilities	95			78
Total current liabilities	447			489
Long-term debt, net of current portion	1,798			1,798
Regulatory liabilities - noncurrent	668			657
Deferred income taxes	469			445
Liabilities from price risk management activities - noncurrent	167			188
Unfunded status of pension and postretirement plans	140			140
Non-qualified benefit plan liabilities	98			97
Other noncurrent liabilities	103			78
Total liabilities	3,890			3,892
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, 2011 and December 31, 2010	—			—
Common stock, no par value, 160,000,000 shares authorized; 75,325,603 and 75,316,419 shares issued and outstanding as of March 31, 2011 and December 31, 2010, respectively	832			831
Accumulated other comprehensive loss	(5		)	(5		)
Retained earnings	815			766
Total Portland General Electric Company shareholders’ equity	1,642			1,592
Noncontrolling interests’ equity	3			7
Total equity	1,645			1,599
Total liabilities and equity	$	5,535		$	5,491

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(In millions)

(Unaudited)



	Three Months Ended March 31,
	2011			2010
Cash flows from operating activities:
Net income	$	69		$	27
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	56			57
(Decrease) increase in net liabilities from price risk management activities	(29		)	106
Regulatory deferral - price risk management activities	29			(106		)
Deferred income taxes	25			12
Senate Bill 408 deferrals, net	(3		)	(1		)
Allowance for equity funds used during construction	(1		)	(4		)
Power cost deferrals, net	4			—
Other non-cash income and expenses, net	12			9
Changes in working capital:
(Increase) decrease in receivables	(1		)	33
Decrease (increase) in margin deposits	3			(33		)
Income tax refund received	8			—
Decrease in payables	(10		)	(11		)
Other working capital items, net	(16		)	(13		)
Other, net	—			(8		)
Net cash provided by operating activities	146			68
Cash flows from investing activities:
Capital expenditures	(69		)	(92		)
Sales of Nuclear decommissioning trust securities	18			13
Purchases of Nuclear decommissioning trust securities	(19		)	(12		)
Distribution from Nuclear decommissioning trust	—			19
Other, net	—			(1		)
Net cash used in investing activities	(70		)	(73		)

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS, continued

(In millions)

(Unaudited)



	Three Months Ended March 31,
	2011			2010
Cash flows from financing activities:
Proceeds from issuance of long-term debt	$	—		$	191
Payments on long-term debt	(10		)	(149		)
Borrowings on short-term debt	—			4
Payments on commercial paper, net	(19		)	—
Dividends paid	(20		)	(19		)
Debt issuance costs	—			(1		)
Noncontrolling interests’ capital distributions	(4		)	—
Net cash (used in) provided by financing activities	(53		)	26
Increase in cash and cash equivalents	23			21
Cash and cash equivalents, beginning of period	4			31
Cash and cash equivalents, end of period	$	27		$	52
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	$	15		$	16
Cash paid for income taxes	1			—
Non-cash investing and financing activities:
Accrued capital additions	9			68
Accrued dividends payable	20			20

See accompanying notes to condensed consolidated financial statements.

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PORTLAND GENERAL ELECTRIC COMPANY

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 within the state of Oregon. The Company served 821,193 retail customers as of March 31, 2011.

Condensed Consolidated Financial Statements

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

The financial information included herein for the three months ended March 31, 2011 and 2010 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, 2010 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2010, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 25, 2011, 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 potential gain contingencies and 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 Pronouncement

Accounting Standards Update (ASU) 2010-06, Fair Value Measurements and Disclosures (Topic 820) - Improving Disclosures about Fair Value Measurements (ASU 2010-06) requires, among other matters, separate reporting about purchases, sales, issuances, and settlements for Level 3 fair value measurements. For additional information on Level 3, see Note 3, Fair Value of Financial Instruments. In accordance with the provisions of ASU 2010-06, PGE adopted this requirement of ASU 2010-06 on January 1, 2011, which did not have a material impact on PGE’s consolidated financial position, consolidated results of operations, or consolidated cash flows. All other requirements of ASU 2010-06 were adopted on January 1, 2010 in accordance with ASU 2010-06, which did not have a material impact on PGE’s consolidated financial position, consolidated results of operations, or consolidated

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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, 2011 and December 31, 2010.

The activity in the allowance for uncollectible accounts was as follows (in millions):



	Three Months Ended
	March 31,
	2011			2010
Balance as of beginning of period	$	5		$	5
Provision, net	2			1
Amounts written off, less recoveries	(2		)	(1		)
Balance as of end of period	$	5		$	5

Inventories

Inventories consist primarily of materials, supplies, and fuel. Materials and supplies inventories are used in operations and 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, 2011			December 31, 2010
Electric utility plant	$	6,340		$	6,279
Construction work in progress	153			125
Total cost	6,493			6,404
Less: accumulated depreciation and amortization	(2,314		)	(2,271		)
Electric utility plant, net	$	4,179		$	4,133

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $138 million and $133 million as of March 31, 2011 and December 31, 2010, respectively. Amortization expense related to intangible assets was $5 million and $3 million for the three months ended March 31, 2011 and 2010, respectively.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

Regulatory Assets and Liabilities

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



	March 31, 2011				December 31, 2010
	Current		Noncurrent		Current		Noncurrent
Regulatory assets:
Price risk management	$	169	$	163	$	175	$	185
Pension and other postretirement plans	—		210		—		213
Deferred income taxes	—		94		—		95
Deferred broker settlements	23		—		24		—
Renewable energy deferral	17		—		22		—
Debt reacquisition costs	—		23		—		23
Other	5		22		—		28
Total regulatory assets	$	214	$	512	$	221	$	544
Regulatory liabilities:
Asset retirement removal costs	$	—	$	598	$	—	$	588
Asset retirement obligations	—		34		—		33
Regulatory treatment of income taxes (SB 408)	11		—		5		9
Trojan ISFSI pollution control tax credits	13		5		18		4
Other	1		31		2		23
Total regulatory liabilities	$	25	$	668	$	25	$	657

Other Current Liabilities

Other current liabilities consist of the following (in millions):



	March 31, 2011		December 31, 2010
Accrued interest payable	$	36	$	26
Accrued taxes payable	25		22
Other	34		30
Total other current liabilities	$	95	$	78

Other Noncurrent Liabilities

During the first quarter of 2011, an updated decommissioning study for the Company’s Boardman coal-fired plant was completed. As a result, PGE increased its asset retirement obligation related to Boardman by approximately $23 million during the first quarter of 2011, with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the condensed consolidated balance sheet.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 2013.

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, 2011, PGE was in compliance with this covenant with a 52.3% debt ratio.

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 contains a standard provision which 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, 2011, PGE had $147 million of letters of credit and no commercial paper or borrowings outstanding under the credit facilities. As of March 31, 2011, the aggregate unused credit available under the credit facilities was $453 million.

Long-term Debt

During the three months ended March 31, 2011, PGE elected to have $10 million of Port of St. Helens Pollution Control Revenue Bonds redeemed and retired.

In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow, which was paid to Lehman Brothers Inc. (Lehman) as remarketing agent for the Bonds, who in turn paid off the beneficial owner of the Bonds. As a result of the payment, PGE became the beneficial owner of the Bonds and requested that Lehman safe-keep the Bonds in Lehman’s Depository Trust Company participant account until such time as the Bonds could be remarketed. After repurchase of the Bonds, PGE removed the liability for the Bonds from its financial statements.

In September 2008, Lehman filed for protection under Chapter 11 of the U.S. Bankruptcy Code in the United States Bankruptcy Court for the Southern District of New York. PGE subsequently filed a claim for return of the Bonds from Lehman. On November 9, 2009, the trustee appointed to liquidate the assets of Lehman (Trustee) allowed PGE’s claim as a net equity claim for securities. At the time, PGE believed it would receive back the entire amount of the Bonds at some point during the bankruptcy proceedings.

It is not certain that the Company will receive the full amount of the Bonds but could, along with other claimants, potentially receive a pro-rata share of certain assets. The timing and extent of distributions on claims are subject to the ultimate disposition of numerous claims in the proceedings and certain major contingencies which the Trustee

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

must resolve. PGE cannot currently estimate how much of the value of the Bonds will ultimately be returned to the Company or the timing of the distribution from Lehman. Management does not expect this to have a material effect on the Company’s financial position but it could have a material effect on results of operations for a future interim period.

Pension and Other Postretirement Benefits

Components of net periodic benefit cost are as follows for the three months ended March 31, (in millions):



	Defined Benefit Pension Plan						Other Postretirement Benefit Plans				Non-Qualified Benefit Plans
	2011			2010			2011		2010		2011		2010
Service cost	$	3		$	3		$	1	$	1	$	—	$	—
Interest cost	7			7			1		1		1		1
Expected return on plan assets	(10		)	(10		)	—		—		—		—
Amortization of net actuarial gain	2			1			—		—		—		—
Net periodic benefit cost	$	2		$	1		$	2	$	2	$	1	$	1

NOTE 3: FAIR VALUE OF FINANCIAL INSTRUMENTS

The Company determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in PGE’s condensed consolidated balance sheets, for which it is practicable to estimate fair value based on the following inputs as of March 31, 2011 and December 31, 2010:


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


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

•

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, 2011, the estimated aggregate fair value of PGE’s long-term debt was $1,944 million, compared to its $1,798 million carrying amount. As of December 31, 2010, the estimated aggregate fair value of PGE’s long-term debt was $1,968 million, compared to its $1,808 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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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 instruments 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):



	As of March 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust ⁽¹⁾:
Money market funds	$	—	$	13	$	—	$	13
Debt securities:
U.S. treasury securities	6		—		—		6
Corporate debt securities	—		6		—		6
Mortgage-backed securities	—		6		—		6
Municipal securities	—		2		—		2
Asset-backed securities	—		1		—		1
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Mutual funds	14		1		—		15
Common stocks	3		—		—		3
Debt securities - mutual funds	3		—		—		3
Assets from price risk management activities ^{(1) (3)}:
Electricity	—		7		1		8
Natural gas	—		10		1		11
	$	26	$	46	$	2	$	74
Liabilities - Liabilities from price risk management activities ^{(1) (3)}:
Electricity	$	—	$	107	$	23	$	130
Natural gas	—		125		95		220
	$	—	$	232	$	118	$	350


(1)	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.


(2)	Excludes insurance policies of $23 million, which are recorded at cash surrender value.


(3)	For further information, see Note 4, Price Risk Management.

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)



	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust ⁽¹⁾:
Money market funds	$	—	$	13	$	—	$	13
Debt securities:
U.S. treasury securities	3		—		—		3
Corporate debt securities	—		6		—		6
Mortgage-backed securities	—		7		—		7
Municipal securities	—		4		—		4
Asset-backed securities	—		1		—		1
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Mutual funds	16		1		—		17
Common stocks	2		—		—		2
Debt securities - mutual funds	2		—		—		2
Assets from price risk management activities ^{(1) (3)}:
Electricity	—		4		1		5
Natural gas	—		11		—		11
	$	23	$	47	$	1	$	71
Liabilities - Liabilities from price risk management activities ^{(1) (3)}:
Electricity	$	—	$	102	$	17	$	119
Natural gas	—		153		104		257
	$	—	$	255	$	121	$	376


(1)	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.


(2)	Excludes insurance policies of $23 million, which are recorded at cash surrender value.


(3)	For further information, see Note 4, Price Risk Management.

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.

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

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PORTLAND GENERAL ELECTRIC COMPANY

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS, continued

(Unaudited)

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, 2011:
Net liabilities from price risk management activities as of December 31, 2010	$	(120	)
Realized and unrealized gains and (losses), net	2
Purchases	1
Settlements	1
Net liabilities from price risk management activities as of March 31, 2011	$	(116	)
Three months ended March 31, 2010:
Net liabilities from price risk management activities as of December 31, 2009	$	(154	)
Realized and unrealized gains and (losses), net	(57		)
Purchases, issuances and settlements, net	(10		)
Net liabilities from price risk management activities as of March 31, 2010	$	(221	)

The Level 3 net realized and unrealized gains (losses) presented in the preceding table are recorded in Purchased power and fuel expense in the condensed consolidated statements of income and 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.

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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 Company-owned 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 affect the Company’s financial position, results of operations, or cash flow.

PGE utilizes derivative instruments in its wholesale electric utility activities to manage its exposure to commodity price risk and foreign currency exchange rate risk, mitigate the effects of market fluctuations, and minimize net power costs for service to its retail customers. These derivative instruments may include forward, swap, and option contracts for electricity, natural gas, oil, and foreign currency, and futures contracts for natural gas and oil and 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 gains and losses from derivative activity until realized, in accordance with the ratemaking and cost recovery process authorized by the OPUC. This accounting treatment defers the mark-to-market gains and losses on derivative activities until settlement. 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. As of March 31, 2011 and December 31, 2010, the Company had $23 million and $31 million, respectively, in collateral posted with these counterparties, consisting entirely of letters of credit.

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions were as follows (in millions):



	March 31, 2011			December 31, 2010
Commodity contracts:
Electricity	10		MWh	9		MWh
Natural gas	82		Decatherms	93		Decatherms
Foreign currency	$	8	Canadian	$	7	Canadian

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The fair value of PGE’s Assets and Liabilities from price risk management activities consists of the following (in millions):



	March 31, 2011			December 31, 2010
Current assets:
Commodity contracts:
Electricity	$	7		$	4
Natural gas	8			9
Total current derivative assets	15		⁽¹⁾	13		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity	1			1
Natural gas	3			2
Total noncurrent derivative assets	4		⁽²⁾	3		⁽²⁾
Total derivative assets not designated as hedging instruments	$	19		$	16
Total derivative assets	$	19		$	16
Current liabilities:
Commodity contracts:
Electricity	$	81		$	77
Natural gas	102			111
Total current derivative liabilities	183			188
Noncurrent liabilities:
Commodity contracts:
Electricity	49			42
Natural gas	118			146
Total noncurrent derivative liabilities	167			188
Total derivative liabilities not designated as hedging instruments	$	350		$	376
Total derivative liabilities	$	350		$	376


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


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

Net realized and unrealized gains (losses) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel, net of deferrals in the condensed consolidated statements of income and were as follows (in millions):



	Three Months Ended March 31,
	2011			2010
Commodity contracts:
Electricity	$	(31	)	$	(53	)
Natural Gas	6			(91		)

Unrealized gains and losses and certain realized gains and losses presented in the table above are offset within the statements of income by the effects of regulatory accounting. Of the net gain (loss) recognized in net income for the

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three months ended March 31, 2011 and 2010, net losses of $25 million and $141 million, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2011 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2011		2012		2013		2014		Total
Commodity contracts:
Electricity	$	64	$	36	$	16	$	6	$	122
Natural gas	71		91		41		6		209
Net unrealized loss	$	135	$	127	$	57	$	12	$	331

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 would 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, 2011 was $284 million, for which the Company has $126 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, 2011, the cash requirement to either post as collateral or settle the instruments immediately would have been $270 million.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities as of March 31, 2011 or December 31, 2010 were as follows:



	March 31, 2011		December 31, 2010
Assets from price risk management activities:
Counterparty A	24	%	22	%
Counterparty B	19		23
Counterparty C	8		10
Counterparty D	6		11
	57	%	66	%
Liabilities from price risk management activities:
Counterparty B	25	%	24	%
Counterparty E	12		12
	37	%	36	%

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

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NOTE 5: EARNINGS PER SHARE

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



	Three Months Ended March 31,
	2011		2010
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	69	$	27
Denominator (in thousands):
Weighted-average common shares outstanding - basic	75,318		75,229
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	19		17
Weighted-average common shares outstanding - diluted	75,337		75,246
Earnings per share - basic and diluted	$	0.92	$	0.36

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 and the vesting criteria have not been met as of the end of the reporting period presented.

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.

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NOTE 6: EQUITY

The activity in equity during the three months ended March 31, 2011 and 2010 is as follows (dollars in millions):



	Portland General Electric Company Shareholders’ Equity
	Common Stock			Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
	Shares	Amount		Accumulated Other Comprehensive Loss			Retained Earnings			Noncontrolling Interests’ Equity
Balances as of December 31, 2010	75,316,419	$	831	$	(5	)	$	766		$	7
Vesting of restricted stock units	9,184	—		—			—			—
Stock-based compensation	—	1		—			—			—
Dividends declared	—	—		—			(20		)	—
Capital distribution	—	—		—			—			(4		)
Net income	—	—		—			69			—
Balances as of March 31, 2011	75,325,603	$	832	$	(5	)	$	815		$	3

Balances as of December 31, 2009	75,210,580	$	829	$	(6	)	$	719		$	1
Vesting of restricted and performance stock units	64,932	—		—			—			—
Dividends declared	—	—		—			(19		)	—
Net income	—	—		—			27			—
Other comprehensive income	—	—		1			—			—
Balances as of March 31, 2010	75,275,512	$	829	$	(5	)	$	727		$	1

Effective April 1, 2011, PGE implemented a Dividend Reinvestment and Direct Stock Purchase Plan (the Plan), under which the Company may issue up to 2,500,000 shares of common stock. The Plan provides a way for all interested investors to invest in shares of common stock of the Company. Participation in the Plan is strictly voluntary and is open to all interested parties, regardless of whether they are already shareholders of the Company.

NOTE 7: COMPREHENSIVE INCOME

Comprehensive income is as follows (in millions):



	Three Months Ended March 31,
	2011			2010
Net income	$	69		$	27
Pension and other postretirement plans’ funded position, net of taxes	2			2
Reclassification of defined benefit pension plan and other benefits to a regulatory asset, net of taxes	(2		)	(1		)
Comprehensive income and Comprehensive income attributable to Portland General Electric Company	$	69		$	28

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NOTE 8: CONTINGENCIES

Trojan Investment Recovery

Background. In 1993, PGE closed the Trojan Nuclear Plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan 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.

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’s 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 Trojan. 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.

The OPUC then issued an order on September 30, 2008 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 Company recorded a charge of $33.1 million as of September 30, 2008 related to the refund and accrued additional interest expense on the liability until refunds to customers were completed in the first quarter of 2010. The URP and the plaintiffs in the class actions described below have separately appealed the September 30, 2008 order to the Oregon Court of Appeals. Appellants have filed their opening briefs, and in March 2011, PGE and the state Attorney General’s Office, on behalf of the OPUC, filed answering briefs. Amicus briefs in support of PGE’s position were subsequently filed by CUB and a group of northwest utilities. PGE anticipates that appellants will file reply briefs later this year, after which the court will set a date for oral argument.

Class Actions. In a separate legal proceeding, two class action lawsuits 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 lawsuits seek damages of $260 million, plus interest, as a result of PGE’s inclusion, in prices charged to customers, of a return on its investment in Trojan.

In August 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings until the OPUC responded 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.

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In October 2006, the Marion County Circuit Court abated the class actions in response to the ruling of the Oregon Supreme Court. In October 2007, the Class Action Plaintiffs filed a motion to lift the abatement. However, in February 2009, the Circuit Court denied the motion.

Management cannot predict the ultimate outcome of the above matters. Management believes, however, 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 in future reporting periods.

Complaint and Application for Deferral - Income Taxes

On October 5, 2005, the URP and another party (together, the Complainants) filed a Complaint and an Application for Deferred Accounting with the OPUC alleging that, since the September 2, 2005 effective date of SB 408, PGE’s rates were not just and reasonable and were in violation of SB 408 because they contained approximately $92.6 million in annual charges for state and federal income taxes that are not being paid to any governmental entity. The Complaint and Application for Deferred Accounting requested that the OPUC order the creation of a deferred account for all amounts charged to customers since September 2, 2005 for state and federal income taxes, less amounts actually paid for income taxes by or on behalf of PGE to the federal and state governments.

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 (Deferral Period). The OPUC’s order also dismissed the Complaint, on grounds that it was superfluous to the Complainants’ application for deferred accounting. The order required that PGE calculate the amounts applicable to the Deferral Period, along with calculations of PGE's earnings and the effect of the deferral on the Company’s return on equity.

In December 2007, PGE filed its report as required by the OPUC. In the report, PGE determined that: (i) the amount of any deferral would be between zero and $26.6 million; and (ii) PGE's earnings over the twelve-month period ended September 30, 2006 would preclude any refund.

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 over the twelve month period ended September 30, 2006.

On October 16, 2009, Complainants filed an appeal of the August 2009 order with the Oregon Court of Appeals, which remains pending.

Management cannot predict the ultimate outcome of this matter. Management believes, however, that 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.

Turlock subsequently 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.

PGE sought and received an order joining PRC as a necessary party to the litigation. PRC intervened as a plaintiff,

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also alleging breach of contract and damages in the amount alleged by Turlock, for the purpose of reimbursing Turlock for those expenses.

In the first quarter of 2011, the parties reached a settlement agreement that did not have a material adverse impact on the Company’s financial condition, results of operations or cash flows.

Lawsuit filed by Sierra Club and Other Environmental Groups

On September 30, 2008, the Sierra Club and other environmental groups filed suit against PGE in the U.S. District Court for the District of Oregon (Court) for alleged violations at PGE's Boardman Coal Plant of the federal Clean Air Act (CAA), Oregon’s Regional Haze State Implementation Plan (SIP), the plant’s CAA Title V permit, and additional alleged violations of various environmental related regulations.

The plaintiffs seek injunctive relief that includes permanently enjoining PGE from operating Boardman except in accordance with the CAA, Oregon’s SIP, and the plant’s Title V Permit. In addition, plaintiffs seek civil penalties against PGE including $27,500 per day per alleged violation for violations occurring before March 15, 2004 and $32,500 per day per alleged violation occurring thereafter. The total amount of monetary penalties and damages asserted in the complaint cannot be determined with certainty. However, based solely on the complaint, the Company estimates that the amount asserted could be up to approximately $60 million.

On September 30, 2009, the Court granted PGE’s motion with respect to certain of the plaintiff’s claims. The principal claims that remain are: (i) that PGE constructed Boardman without complying with the 1974 and 1977 federal pre-construction permitting requirements; (ii) that PGE modified Boardman in the 1990s without complying with Oregon’s pre-construction permitting requirements; and (iii) that certain modifications to Boardman triggered New Source Performance Standards (NSPS). Discovery in the case continues, with a tentative trial date set for December 2011.

Management cannot predict the ultimate outcome of the above matters or estimate a range of potential liability. Management believes, however, 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 in future reporting periods.

EPA Notice of Violation

In September 2010, PGE received a Notice of Violation (NOV) from the U.S. Environmental Protection Agency (EPA). The NOV states that the EPA has determined that PGE is violating the NSPS under the CAA, and Operating Permit requirements under Title V of the CAA, at the Boardman plant. In the NOV, the EPA asserts that certain projects at the Boardman plant in 1998 and in 2004 triggered the NSPS, that PGE did not meet the emissions standards required by the regulations and that, therefore, PGE has operated the boiler at the Boardman plant in violation of the CAA. The NOV states the maximum civil penalties the EPA is authorized to impose under the CAA for violations of the NSPS (which range from $25,000 to $37,500 per day), but does not impose any penalties, or specify the amount of any proposed penalties with respect to the alleged violations.

Accordingly, management cannot estimate the range of potential liability for the violations asserted in the NOV. However, based solely on the maximum penalties authorized under the CAA, management believes that the maximum penalty that could be imposed for the alleged violations is approximately $60 million. The projects alleged to have triggered the NSPS in the NOV are also included in the Sierra Club’s NSPS claim in the litigation described above. To the extent the Company incurs liability for such claims in connection with one of these proceedings, liability for the same claims could not be imposed pursuant to the other proceeding. PGE believes that it has strong defenses to these claims. During the first quarter of 2011, PGE met with the EPA to confer about the

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violations cited and to present information on the specific findings of the EPA. PGE and the EPA agreed to continue the discussions.

Management cannot predict the ultimate outcome of these matters. Management believes, however, 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 in future reporting periods.

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 in April 2009 issued a mandate giving immediate effect to its August 2007 order remanding the case to the FERC.

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

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 ultimate outcome of the Pacific Northwest Refund proceeding, whether the FERC will order refunds in this proceeding, which contracts would be subject to refunds, or how such refunds, if any, would be calculated. Management cannot estimate a range of potential loss. Management believes, however, 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.

EPA Investigation of Portland Harbor

A 1997 investigation by the EPA of a segment of the Willamette River known as the Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National

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Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site and listed 69 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.

In January 2008, the EPA requested information from various parties, including PGE, concerning properties in or near the 5.7 mile segment of the river being examined in the RI/FS, as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.

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

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 or estimate a range of potential loss. Management believes, however, 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.

EPA Investigation of 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. In September 2003, the EPA included the Harbor Oil facility 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. In May 2007, an AOC was signed by the EPA and six other parties, including PGE, to implement an RI/FS at the Harbor Oil site. The draft remedial investigation was completed with the resulting report submitted to the EPA.

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 or estimate a range of potential loss. Management believes, however, 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.

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NOTE 9: GUARANTEES

PGE enters into financial agreements and power and natural gas 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, 2011, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

NOTE 10: VARIABLE INTEREST ENTITIES

PGE has determined that its interests in three variable interest entities (VIEs) contain 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 within 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 Companies (LLCs), holding less than 1% equity interest in each entity, and a financial institution is the Investor Member, holding 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 agreements, PGE expects to absorb a majority of the expected losses of the LLCs.

Included in PGE’s condensed consolidated balance sheet are LLC net assets as follows (in millions):



	March 31,		December 31,
	2011		2010
Cash and cash equivalents	$	1	$	1
Accounts receivable	—		4
Electric utility plant, net	5		5

These assets can only be used to settle the obligations of the consolidated VIEs.

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

Forward-Looking Statements

The information in this report includes statements that are forward-looking within the meaning of the Private Securities Litigation Reform Act of 1995. Such forward-looking statements include, but are not limited to, statements that relate to expectations, beliefs, plans, assumptions and objectives concerning future operations, business prospects, expected changes in future loads, 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,” “estimates,” “expects,” “intends,” “plans,” “predicts,” “projects,” “will likely result,” “will continue,” “should,” 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 facilities and other assets, construction and operation of plant facilities, transmission of electricity, recovery of power costs and capital investments, and current or prospective wholesale and retail competition;


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


•	the outcome of legal and regulatory proceedings and issues including, but not limited to, the matters described in Note 8, Contingencies, in the Notes to Condensed Consolidated Financial Statements;


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


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


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


•	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

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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;


•	changes in wholesale prices for natural gas, coal, oil, and other fuels and the impact of such changes on the Company’s power costs and the availability and price of wholesale power in the western United States;


•	changes in residential, commercial, and industrial growth, and in 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 regulatory treatment of income taxes, which may result in earnings volatility and affect PGE’s results of operations;


•	declines in the fair value of equity securities held by defined benefit pension plans and other benefit plans, which could result in increased funding requirements for such 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 risks, such as earthquake, flood, drought, lightning, wind, and fire;


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


•	acts of war or terrorism.

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.

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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, 2010, 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 from seasonal weather conditions on demand for electricity, retail and wholesale price changes, customer usage patterns (which can be affected by the 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 - Retail energy deliveries for the first quarter of 2011 increased 10% from the same period last year primarily as a result of cooler temperatures. On a weather adjusted basis, energy deliveries to retail customers for the first quarter of 2011 increased 3.1%, due to the effects of production increases by paper and high tech industrial customers and an increase in the average number of customers of approximately 4,100.

The following table presents deliveries, by customer class, including those to customers who chose to purchase their energy from an Electricity Service Supplier (ESS), for the periods indicated:



	Three Months Ended March 31,
	2011		2010		Increase in Energy Deliveries
	Average Number of Customers	Energy Deliveries *	Average Number of Customers	Energy Deliveries *	Increase in Energy Deliveries
Residential	719,615	2,291	716,181	2,046	12.0	%
Commercial	101,018	1,831	100,378	1,736	5.5
Industrial	258	1,024	272	913	12.2
Total	820,891	5,146	816,831	4,695	9.6

____________________

* In thousands of MWh.

PGE projects that weather adjusted retail energy deliveries for 2011 will be approximately 1.0% above 2010 levels, including the anticipated effects of energy efficiency measures. The increase in deliveries reflects expected higher residential demand and growth in commercial and industrial deliveries, particularly paper production and high tech customers.

The average seasonally adjusted unemployment rates for the first quarters of 2011 and 2010 are as follows:



	United States		Oregon		Portland/ Salem
First quarter 2011	8.9	%	10.2	%	10.0	%
First quarter 2010	9.7		10.6		10.3

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Power Operations - To meet the energy needs of its customers, the Company utilizes a combination of its own generating resources and wholesale market transactions. Based on numerous factors, including plant availability, customer 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. As a result, 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. PGE’s total system load for the three months ended March 31, 2011 increased 6% relative to that for the three months ended March 31, 2010, while the relative volume of power generated decreased 38%. During the first quarter of 2011, a significant amount of thermal generation was economically displaced by purchased power and increased energy from hydro generating resources.

Energy received from PGE-owned hydroelectric plants and under contracts from mid-Columbia projects increased 40% in the first quarter of 2011 compared to the first quarter of 2010. These resources provided approximately 26% of the Company’s retail load requirement for the first quarter of 2011, compared to 20% for the first quarter of 2010. Energy received from these sources exceeded projections (or ‘normal’) included in the Company’s Annual Power Cost Update Tariff (AUT) by approximately 16% during the first quarter of 2011, compared to falling short of such projections by approximately 21% during the first quarter of 2010. 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. ‘Normal’ represents the level of energy forecasted to be received from hydroelectric resources for the year and is based on average regional hydro conditions. Any excess in hydro generation from that projected in the AUT generally displaces power from higher cost sources, while any shortfall is generally replaced with power from higher cost sources. Energy from hydro resources is expected to exceed normal for 2011.

Pursuant to the Company’s power cost adjustment mechanism (PCAM), actual NVPC for the first quarter of 2011 was approximately $19 million below baseline NVPC, with PGE recording an estimated refund to customers of approximately $4 million as of March 31, 2011. Actual NVPC for the first quarter of 2010 was approximately $7 million above baseline NVPC, with no collection from customers recorded as actual NVPC were within the established deadband range.

During the first quarter of 2011, the Company’s generating plants provided approximately 42% of its retail load requirement, compared to 68% in the first quarter of 2010. Availability of the plants PGE operates approximated 98% and 95% for the first quarters of 2011 and 2010, respectively, with the availability of Colstrip, which PGE does not operate, approximating 94% and 97%, respectively.

Capital Requirements and Financing - PGE’s capital requirements for 2011 are related primarily to ongoing expenditures for the upgrade, replacement, and expansion of transmission, distribution and generation infrastructure, and technology enhancements, as well as expenditures related to hydro licensing and construction. Capital and preliminary engineering expenditures are expected to approximate $328 million in 2011, of which $69 million has been incurred during the first quarter. See the Capital Requirements section of this Item 2.

For 2011, the Company expects to meet capital requirements with cash from ongoing operations, with no issuances of long-term debt or equity expected. In subsequent years, the Company expects to fund its capital requirements with a combination of cash from operations and funds from the capital markets as internal liquidity needs and market conditions warrant. The Company also expects that the borrowing capacity under credit facilities will continue to be available to manage working capital requirements during those periods. For further information, see the Debt and Equity Financings section of this Item 2.

PGE’s 2009 Integrated Resource Plan (IRP), as amended, was acknowledged by the OPUC in November 2010 and includes the Company’s strategy for acquiring new resources through 2015 and a 20-year strategy outlining long-term expectations for resource needs and portfolio management. To meet projected energy requirements, the IRP includes energy efficiency measures, new renewable resources, new transmission capability, new generating plants, and improvements to existing generating plants.

In accordance with the IRP acknowledgement and pursuant to the OPUC’s competitive bidding guidelines, the

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Company will begin to implement the IRP by issuing up to three requests for proposals (RFPs) in 2011 for additional resources. In April 2011, the OPUC approved the selection of an Independent Evaluator for the RFPs to be issued in 2011.

The first RFP will seek approximately 200 MW of year-round flexible and peaking resources to help supply customers with electricity during peak demand periods and integrate increasing system levels of variable energy resources such as wind and solar power. In addition, the RFP will seek two seasonal peaking resources:


•	approximately 200 MW of bi-seasonal (winter and summer) peaking supply; and


•	approximately 150 MW of winter-only peaking supply.

The OPUC has issued a schedule that calls for PGE to submit a final draft RFP to the OPUC in late May 2011. The OPUC will accept comments and a recommendation from its staff before deciding whether to allow the RFP to proceed in late July 2011. Subject to the OPUC decision, PGE anticipates selection of successful bidders would be completed by the first quarter of 2012 with these resources available in the 2013 to 2015 time frame.

The two additional RFPs consist of:


•	approximately 120 MWa of new renewable resources to help meet Oregon’s renewable energy standard, for which the RFP is expected to be issued in the 2011 or 2012 time frame; and


•	approximately 300 to 500 MW of baseload energy resources, for which the RFP is expected to be issued in 2011.

PGE expects to submit self-build proposals in each competitive bidding process for new resources and, if awarded the bids, would expect to need significant capital to fund the projects. For additional information, see the Capital Requirements section of Liquidity and Capital Resources in this Item 2.

PGE’s current IRP includes a proposal for a double-circuit, 200-mile, 500 kV transmission project, the Cascade Crossing Transmission Project, or Cascade Crossing, that would help meet growing electricity demand and ensure future grid reliability by interconnecting new and existing energy resources in eastern Oregon to the Company’s service territory. PGE continues to work with other stakeholders in the region in planning the project and is actively engaged in the federal, state, and tribal permitting process. The Company has signed Memorandums of Understanding with certain parties, including the Bonneville Power Administration, PacifiCorp, and Idaho Power Company concerning Cascade Crossing.

Legal, Regulatory, and Environmental Matters - PGE is a party to certain proceedings, the ultimate outcome of which may have a material impact on the results of operations and cash flows in future reporting periods. Such proceedings include, but are not limited to, matters related to:


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


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


•	Investigation of environmental matters at Portland Harbor;


•	Claims asserted by the Sierra Club and other plaintiffs regarding the operation of Boardman; and


•	A notice of violation issued by the EPA in September 2010, alleging that Boardman operation has violated various environmental regulations.

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

Certain regulatory items, including those discussed below, impacted the Company’s revenues, results of operations,

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or cash flows for the three months ended March 31, 2011 and in some cases have affected customer prices, as authorized by the OPUC. In some cases, the Company deferred the related expenses or benefits as regulatory assets or liabilities, respectively, for later amortization and inclusion in customer prices, pending OPUC review and authorization.


•	General Rate Case—Effective January 1, 2011, the OPUC approved an increase in PGE’s annual revenues of $65 million, which includes a reduction in NVPC of $35 million and represents an approximate 3.9% overall increase in customer prices.

The OPUC also approved a tariff that provides a mechanism for future consideration of customer price changes related to the recovery of the Company’s remaining investment in the Boardman generating plant over a shortened operating life. The Company anticipates ceasing coal-fired operation at Boardman in 2020, consistent with revised rules approved by the Oregon Environmental Quality Commission in December 2010. The revised rules are subject to EPA approval, with its decision expected in May 2011.

On April 4, 2011, the Company submitted an advice filing to the OPUC requesting recovery of increased depreciation expense reflecting a change in the retirement date of Boardman from 2040 to 2020. The advice filing also incorporates the results of a new site-specific decommissioning study that increases the estimated asset retirement obligation by $23 million. The Company is expecting an effective date of July 1, 2011, with an incremental revenue requirement for the last six months of 2011 of approximately $8 million.

•

Power Costs—Pursuant to the AUT process, PGE files an annual estimate of power costs for the following year, with new prices to become effective January 1st each year. As required, the Company’s initial forecast of 2012 power costs was submitted to the OPUC on April 1, 2011. Such forecast will be updated during the year and finalized in November. Based upon the final forecast, new prices, as approved by the OPUC, would become effective January 1, 2012.

•

Renewable Resource Costs—Pursuant to a renewable adjustment clause mechanism (RAC), PGE can recover in customer prices prudently incurred costs of renewable resources that are expected to be placed in service in the current year. The Company may submit a filing to the OPUC by April 1st each year, with prices to become effective January 1st of the following year. Under the RAC, in 2010, PGE filed for recovery of, among other things, the deferral of eligible costs and a return on its investment related to Biglow Canyon Phase III. The OPUC approved recovery over a one-year period beginning January 1, 2011 of $22.1 million, which includes a residual balance from the deferral of Biglow Canyon Phase II. In addition, effective January 1, 2011, the annual revenue requirement related to the investment in Biglow Canyon Phase III is reflected in retail prices through the Company’s 2011 General Rate Case. The Company did not submit a RAC filing in April 2011 as it did not, at that time, have an approved renewable resource addition that would be placed into service during 2011.


•	Regulatory Treatment of Income Taxes (SB 408)—


•	In April 2011, the OPUC issued its order on the Company’s 2009 SB 408 report, authorizing the previously stipulated refund to customers of $9 million, including interest, over a one-year period beginning June 1, 2011.

•

For 2010, PGE has estimated a collection from customers of less than $1 million based on temporary rules issued by the OPUC in February 2011, which are effective for 180 days. The OPUC is currently conducting a permanent rulemaking proceeding to replace the temporary rules, with a decision expected in the third quarter of 2011. The 2010 SB 408 report is expected to be filed with the OPUC no later than October 15, 2011, with the OPUC’s decision on such report expected no later than April 2012 and any resulting change in customer prices effective June 1, 2012. The Company has not recorded any amount for SB 408 related to 2010; and


•	For 2011, PGE has estimated a collection from customers of less than $1 million based on the temporary rules, but has not recorded any amount under SB 408.

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In March 2011, Oregon Senate Bill 967 (SB 967) was introduced, which, if enacted into law, would repeal existing statutes governing the adjustment of public utility rates to account for differences in taxes paid by electricity and natural gas utilities and amounts collected from customers for taxes (collectively, known as ‘SB 408’), effective with the 2010 calendar year. Among other matters, SB 967 would require the OPUC to consider taxes paid by electricity and natural gas utilities when conducting ratemaking proceedings.

If SB 967 as currently written is enacted into law and made effective for the 2010 and 2011 SB 408 reports, the filing of such reports would no longer be required and no price adjustment would occur relating to these years. SB 967 would not affect the Company’s 2009 SB 408 report. PGE cannot predict whether SB 967 will ultimately be enacted into law, but will monitor the status of the bill as it progresses through the legislative process.

•

Decoupling—The decoupling mechanism 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. The mechanism provides for customer collection or refund if weather adjusted use per customer is less than or more than the levels approved in the Company’s most recent general rate case.


•	In 2010, the Company recorded an estimated collection of $8 million, as weather adjusted use per customer was less than levels included in the 2009 General Rate Case. Pending review and approval by the OPUC, any resulting collections from customers would be expected over a one-year period beginning June 1, 2011.


•	In the first quarter of 2011, the Company recorded an estimated collection of less than $1 million primarily related to a true-up for 2010.

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, 2010, filed with the SEC on February 25, 2011.

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Results of Operations

The following table contains condensed consolidated statements of income information for the periods presented (dollars in millions):



	Three Months Ended March 31,
	2011				2010
Revenues, net	$	484	100	%	$	449	100	%
Purchased power and fuel	194		40		224		50
Gross margin	290		60		225		50
Operating expenses:
Production and distribution	42		9		39		8
Administrative and other	52		11		45		10
Depreciation and amortization	56		11		57		13
Taxes other than income taxes	25		5		23		5
Total operating expenses	175		36		164		36
Income from operations	115		24		61		14
Other income:
Allowance for equity funds used during construction	1		—		4		1
Miscellaneous income, net	2		1		1		—
Other income, net	3		1		5		1
Interest expense	27		6		29		7
Income before income taxes	91		19		37		8
Income taxes	22		5		10		2
Net income and Net income attributable to Portland General Electric Company	$	69	14	%	$	27	6	%

Net income attributable to Portland General Electric Company was $69 million, or $0.92 per diluted share, for the first quarter of 2011 compared to $27 million, or $0.36 per diluted share, for the first quarter of 2010. The $42 million increase in net income was largely driven by the combination of a 10% increase in total retail energy deliveries and a 19% decrease in average variable power cost. Increased retail energy deliveries were driven by colder temperatures in the first quarter of 2011 relative to the first quarter of 2010 and increased production by certain customers in the paper and high technology sectors.

The decrease in average variable power cost resulted from a 41% decline in the average price of purchased power and a 40% increase in energy from hydro resources in the first quarter of 2011 relative to the first quarter of 2010. During the first quarter of 2011, a significant amount of thermal generation was economically displaced with lower-cost power purchased in the wholesale market and the increased energy received from hydro and wind generation. During the first quarter of 2011, favorable hydro conditions resulted in a 16% increase from normal in power received from hydro resources, while during the first quarter of 2010 unfavorable hydro conditions resulted in a 21% decline from normal.

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Revenues, energy deliveries (based in MWh), and average number of retail customers consist of the following for the periods presented:



	Three Months Ended March 31,
	2011					2010
Revenues ⁽¹⁾ (dollars in millions):
Retail:
Residential	$	256		53	%	$	219	49	%
Commercial	156			32		144		32
Industrial	54			11		50		11
Subtotal	466			96		413		92
Other - accrued revenues	(3		)	(1	)	7		2
Total retail revenues	463			95		420		94
Wholesale revenues	13			3		21		4
Other operating revenues	8			2		8		2
Total revenues	$	484		100	%	$	449	100	%
Energy deliveries ⁽²⁾ (MWh in thousands):
Retail:
Residential	2,291			41	%	2,046		39	%
Commercial	1,831			33		1,736		33
Industrial	1,024			18		913		17
Total retail energy deliveries	5,146			92		4,695		89
Wholesale energy deliveries	477			8		580		11
Total energy deliveries	5,623			100	%	5,275		100	%
Average number of retail customers:
Residential	719,615			88	%	716,181		88	%
Commercial	101,018			12		100,378		12
Industrial	258			—		272		—
Total	820,891			100	%	816,831		100	%


(1)	Includes both revenues from customers who purchase their energy supplies from the Company and revenues from the delivery of energy to those commercial and industrial customers that purchase their energy from ESSs.


(2)	Includes both energy sold to retail customers and energy deliveries to those commercial and industrial customers that purchase their energy from ESSs.

Revenues increased $35 million, or 8%, in the first quarter of 2011 compared to the first quarter of 2010 primarily as a result of the items described below.

Retail revenues are generated by the sale and delivery of energy to retail customers as well as from the delivery of energy that certain commercial and industrial customers purchase from ESSs. Retail revenues also include certain accrued revenues, comprised primarily of amounts related to SB 408, the decoupling mechanism, the PCAM, and deferrals related to the Company’s RAC filings.

Total retail revenues increased $43 million, or 10%, in the first quarter of 2011 compared to the first quarter of 2010, primarily due to the net effect of the following:


•	A $41 million increase resulted from the increase in volume of energy sold consisting of:


◦	A 12% increase in residential energy deliveries primarily driven by the impact of cooler temperatures and the addition of 3,400 customers; and


◦	An 8% increase in commercial and industrial energy deliveries largely due to improvement by

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certain customers in the paper production and technology sectors and the addition of 600 customers.


•	A $14 million increase related to a 3% increase in the average retail price, resulting primarily from the January 1, 2011 price increase authorized by the OPUC in the Company’s 2011 General Rate Case;


•	A $6 million decrease attributable to certain customer credits, primarily driven by the refund in customer prices, which began January 1, 2011, of a previously recorded deferred liability for Trojan ISFSI pollution control tax credits. The overall reduction in revenues is offset by a $5 million reduction in Depreciation and amortization expense and a $1 million reduction in Income taxes;


•	A $5 million decrease related to the decoupling mechanism as a $5 million collection from customers was recorded in the first quarter of 2010, which is included in Other - accrued revenues. For further information on the decoupling mechanism, see “Legal, Regulatory and Environmental Matters” in “Overview” of this Item 2; and


•	A $4 million decrease related to an estimated refund to customers, pursuant to the PCAM, recorded in the first quarter of 2011 and included in Other - accrued revenues.

Heating degree-days are an indication of the likelihood that customers will use heating and are used to measure the effects of weather on the demand for electricity. During the first quarter of 2011, cooler than normal temperatures increased the demand for electricity over 2010, as heating degree-days were 21% higher than the first quarter of 2010, which was warmer than normal.

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



	Heating Degree-days
	2011	2010
January	714	609
February	683	510
March	577	510
1st quarter	1,974	1,629
15-year average for the quarter	1,845	1,849

On a weather adjusted basis, energy deliveries to retail customers increased by 3.1% in the first quarter of 2011 compared to the first quarter of 2010.

Wholesale revenues result from sales of electricity to utilities and power marketers, which are made in conjunction with the Company’s effort to secure reasonably priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. Such sales can vary significantly period to period. Wholesale revenues in the first quarter of 2011 declined $8 million, or 38%, compared to the first quarter of 2010, as the result of both an 18% decrease in sales volume and a 32% decrease in average price.

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Purchased power and fuel expense decreased $30 million, or 13%, in the first quarter of 2011 compared to the first quarter of 2010, with $43 million related to a 19% decrease in average variable power cost, partially offset by $13 million related to a 6% increase in total system load. The average variable power cost was $33.94 per MWh in the first quarter of 2011 compared to $41.65 per MWh in the first quarter of 2010.

The decrease in Purchased power and fuel expense consisted of:

•

A $28 million decrease in the cost of generation, primarily driven by a decrease in the proportion of power provided by Company-owned thermal generating resources. A significant amount of thermal generation was economically displaced during the first quarter of 2011 by purchased power and increased energy from hydro and wind generating resources. The average cost of power generated increased 4% in the first quarter of 2011 relative to the first quarter of 2010; and


•	A $2 million decrease in the cost of purchased power, consisting of $92 million related to a 41% decrease in average cost, partially offset by $90 million related to a 68% increase in total energy purchases. The decrease in average cost was primarily driven by lower wholesale power prices resulting from favorable hydro conditions.

PGE’s sources of energy, including total system load and retail load requirement, are as follows for the periods presented:



	Three Months Ended March 31,
	2011				2010
Sources of energy (MWh in thousands):
Generation:
Thermal:
Coal	1,133		20	%	1,397		26	%
Natural gas	268		4		1,322		24
Total thermal	1,401		24		2,719		50
Hydro	570		10		479		9
Wind	217		4		88		2
Total generation	2,188		38		3,286		61
Purchased power:
Term	1,561		28		1,201		22
Hydro	802		14		503		9
Wind	73		1		56		1
Spot	1,088		19		343		7
Total purchased power	3,524		62		2,103		39
Total system load	5,712		100	%	5,389		100	%
Less: wholesale sales	(477	)			(580	)
Retail load requirement	5,235				4,809

Energy from PGE-owned wind generating resources (Biglow Canyon Wind Farm), increased 147%, and represented 4% of the Company’s retail load requirement in the first quarter of 2011, compared to 2% in the first quarter of 2010. The increase was due to the completion of the third and last phase of Biglow Canyon in August 2010.

Hydroelectric energy during the first quarter of 2011, from both PGE-owned plants and from mid-Columbia projects, exceeded both normal levels and the first quarter of 2010 by 16% and 40%, respectively. Although total hydroelectric energy in the first quarter of 2010 was 21% below normal, improved regional hydro conditions during the remainder of 2010 resulted in only an 8% reduction from normal for the year. Energy from hydro resources is

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expected to be above normal for 2011.

The following table presents the forecast of the April-to-September 2011 runoffs (issued April 21, 2011) at particular points of major rivers relevant to PGE’s hydro resources, with actual runoffs for 2010 (as a percentage of normal, as measured over the 30-year period from 1971 through 2000):



	Runoff as a Percent of Normal *
Location	2011 Forecast		2010 Actual
Columbia River at The Dalles, Oregon	121	%	79	%
Mid-Columbia River at Grand Coulee, Washington	118		78
Clackamas River at Estacada, Oregon	120		124
Deschutes River at Moody, Oregon	112		104

* 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, customer prices can be adjusted to reflect a portion of the difference between each year’s forecasted NVPC included in prices (baseline NVPC) and actual NVPC for the year, to the extent such difference is outside of a pre-determined “deadband,” subject to a regulated earnings test. For 2011, the deadband ranges from $15 million below to $30 million above baseline NVPC. For 2010, the deadband ranged from $17 million below to $35 million above baseline NVPC. Pursuant to the PCAM, 90% of the actual NVPC above or below the deadband is to be collected from or refunded to, respectively, retail customers when the Company meets or exceeds the regulated earnings test.

Actual NVPC for the first quarter of 2011 was approximately $19 million below baseline NVPC, with PGE recording an estimated refund to customers of approximately $4 million as of March 31, 2011. Actual NVPC for the year ending December 31, 2011 is currently estimated to be below the baseline NVPC and the lower deadband threshold, with the Company exceeding its regulated earnings test. Actual NVPC was approximately $7 million above baseline NVPC in the first quarter of 2010. Actual NVPC for 2010 was $12 million below baseline NVPC, but within the established deadband range; accordingly, no refund to customers was recorded in 2010.

Gross margin, which represents the difference between Revenues, net and Purchased power and fuel expense, is among those performance indicators utilized by management in the analysis of financial and operating results and is intended to supplement the understanding of PGE’s operating performance. It provides a measure of income available to support other operating activities and expenses of the Company and serves as a useful measure for understanding and analyzing changes in operating performance between reporting periods. It is considered a “non-GAAP financial measure,” as defined in accordance with SEC rules, and is not intended to replace operating income as determined in accordance with GAAP.

Gross margin was 60% in the first quarter of 2011, compared to 50% in the first quarter of 2010. The increase in Gross margin was driven by the increase in customer retail prices resulting from the 2011 General Rate Case which became effective January 1, 2011, combined with lower wholesale electricity prices and favorable hydro conditions, the effects of which economically displaced thermal generation.

Production and distribution expense increased $3 million, or 8%, in the first quarter of 2011 compared to the first quarter of 2010. The increase was due primarily to increased distribution repair and restoration activities as well as higher tree trimming and other delivery system expenses. Also contributing to the increase were higher operating and maintenance expenses at the Company’s generating plants, including Biglow Canyon, the final phase of which was completed in August 2010. Such increased expenses were partially offset by the insurance recovery of $3 million in certain prior year costs related to the Selective Water Withdrawal system on the Company’s Pelton/Round Butte project on the Deschutes River.

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Administrative and other expense increased $7 million, or 16%, in the first quarter of 2011 compared to the first quarter of 2010. A $4 million increase in incentive compensation, related to improved corporate financial performance in the first quarter of 2011, was accompanied by higher pension and information technology costs.

Depreciation and amortization expense decreased $1 million, or 2%, in the first quarter of 2011 compared to the first quarter of 2010. A $5 million decrease related to the amortization of certain Oregon tax credits (offset in Revenues) was partially offset by an increase in depreciation related to Biglow Canyon and the smart meter project.

Taxes other than income taxes increased $2 million, or 9%, in the first quarter of 2011 compared to the first quarter of 2010, due primarily to higher property taxes (resulting from both increased property values and tax rates) and higher city franchise fees.

Other income, net was $3 million in the first quarter of 2011 compared to $5 million in the first quarter of 2010. The decrease was due primarily to a reduction in the allowance for equity funds used during construction, as a result of lower construction work in progress balances during the first quarter of 2011, related primarily to the August 2010 completion of Phase III of Biglow Canyon.

Interest expense decreased $2 million, or 7%, in the first quarter of 2011 compared to the first quarter of 2010. The decrease was due primarily to a lower average interest rate on outstanding long-term debt and lower interest on regulatory liabilities, consisting primarily of customer refunds related to the Trojan regulatory proceeding.

Income taxes increased $12 million in the first quarter of 2011 compared to the first quarter of 2010, primarily due to higher income before taxes in 2011. The effective tax rates (24% and 27% in the first quarters of 2011 and 2010, respectively) are lower than the federal statutory rate primarily due to benefits from federal wind production tax credits, related to increased generation from Biglow Canyon, and state tax credits.

Liquidity and Capital Resources

Capital Requirements

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



	2011			2012		2013		2014		2015
Ongoing capital expenditures	$	250		$	225	$	216	$	237	$	268
Boardman emissions controls ⁽¹⁾	22			1		15		3		—
Hydro licensing and construction	35			20		13		27		28
Total capital expenditures	$	307	⁽²⁾	$	246	$	244	$	267	$	296
Preliminary engineering	$	21		$	2	$	—	$	—	$	—
Long-term debt maturities	$	10		$	100	$	100	$	63	$	70

(1)

Represents 80% of estimated total costs based on installation of nitrogen oxide and mercury controls to meet regulatory requirements. In 1985, PGE sold an 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 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.

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Boardman emissions controls—In accordance with federal regional haze rules, PGE submitted an initial analysis and control plan for Boardman to the Oregon Department of Environmental Quality after it was determined that Boardman would be subject to a Regional Haze Best Available Retrofit Technology (BART) Determination, as required under the Clean Air Act.

In December 2010, the Oregon Environmental Quality Commission approved revised BART rules that establish emission limits and provide for coal-fired operation at Boardman to cease no later than December 31, 2020. The revised rules have been submitted to the EPA for consideration and approval, which is expected during the second quarter 2011.

The emission limits imposed under the revised rules will require the addition of certain controls. The total cost of these controls, together with mercury controls required under a separate rulemaking process, is estimated at approximately $60 million (100% of total costs, excluding AFDC), and is reflected in the table above.

In March 2011, the EPA issued proposed rules under the Clean Air Act’s National Emission Standards for Hazardous Air Pollutants to reduce emissions of Hazardous Air Pollutants (HAPs), which include heavy metals, acid gases, and other substances as defined in the proposal, from coal- and oil-fired electric utility steam generating units. These proposed rules, which reflect the application of maximum achievable control technology (MACT),

are expected to be final by the end of 2011. The Company has not yet determined whether it can meet all the HAPs limits with current and planned control technologies. If the HAPs limits, as proposed, cannot be met with current and planned control technologies, the Company may find it necessary to install additional controls, unless the proposed rules are modified to provide additional flexibility for a federally enforceable shutdown plan.

Hydro licensing and construction—In December 2010, the FERC issued a new 40-year operating license for the Company’s Clackamas River project. On March 17, 2011, the FERC issued an Order on Rehearing that increased the license period to 45 years. Capital spending requirements reflected in the table above relate primarily to modifications to the Company’s hydro facilities to enhance fish passage and survival, as required by conditions contained in the licenses.

Preliminary engineering—Preliminary engineering costs consist of expenditures for preliminary surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects under consideration, as indicated below. If PGE moves forward with construction of the project, such costs are reclassified to Electric utility plant. If the capital project is abandoned, such costs are expensed in the period such determination is made. If any preliminary engineering costs are expensed, the Company may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. As of March 31, 2011 and December 31, 2010, PGE has recorded preliminary engineering costs of $15 million and $13 million, respectively, which are included in Other noncurrent assets in the condensed consolidated balance sheets.

Integrated Resource Plan—Estimated future expenditures related to certain projects included in PGE’s IRP are not included in the table above due to the uncertainty as to the timing and cost, and whether the bid for construction would be awarded to the Company. These include:


•	The construction of the Cascade Crossing Transmission Project at an estimated total cost (in 2011 dollars) of $800 million to $1.0 billion, with an estimated in-service date of 2015. The Company is currently in discussions with potential partners for this project; and


•	The addition of new generating plants and improvements to existing plants. The timing and total cost of the new capacity, energy, and renewable resources described in the IRP will be determined based on the results of the related RFPs, which will determine the successful bidders.

Certain costs that the Company expects to incur in connection with investigating the potential construction of these projects are currently included in Preliminary engineering in the table above. For further information on the Company’s IRP, see the Capital Requirements section of the Overview in this Item 2.

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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,
	2011			2010
Cash and cash equivalents, beginning of period	$	4		$	31
Net cash provided by (used in):
Operating activities	146			68
Investing activities	(70		)	(73		)
Financing activities	(53		)	26
Increase in cash and cash equivalents	23			21
Cash and cash equivalents, end of period	$	27		$	52

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 $78 million increase in cash provided by operating activities in the first quarter of 2011 compared to the first quarter of 2010 was largely due to an increase in net income, after the consideration of noncash operating items, as well as a $36 million decrease in margin deposit requirements pursuant to power and natural gas purchase and sale agreements, driven primarily by decreases in the forward market prices of power and natural gas, and an $8 million income tax refund received in the first quarter of 2011.

A significant portion of cash provided by operations consists of recovery in customer prices of non-cash charges for depreciation and amortization, which PGE estimates to be approximately $220 million in 2011.

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. The $3 million decrease in net cash used in investing activities in the first quarter of 2011 compared to the first quarter of 2010 was primarily due to lower capital expenditures resulting from the completion of Biglow Canyon Phase III in August 2010 and a $19 million distribution in the first quarter of 2010 from the Nuclear decommissioning trust to PGE as a result of an OPUC order issued in connection with a deferral of Boardman power costs.

The Company plans approximately $328 million of capital and preliminary engineering expenditures in 2011 related to 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 2011, cash used in such activities consisted of the payment of dividends of $20 million, the repayment of commercial paper of $19 million, the repayment of long-term debt of $10 million, and capital distributions to noncontrolling interests of $4 million. During the first quarter of 2010, net cash provided by financing activities primarily consisted of proceeds received from the issuance of long-term debt of $191 million, the repayment of long-term debt of $149 million and the

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payment of dividends of $19 million.

As of March 31, 2011, PGE does not expect to issue any long-term debt securities in 2011.

Dividends on Common Stock

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

During the first quarter of 2011, the Board of Directors declared a dividend of $0.26 per common share, for a total of $20 million, with payments made on April 15, 2011 to shareholders of record on March 25, 2011.

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 financial condition and 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 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 2013.

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, 2011, PGE had $147 million of letters of credit and no commercial paper or borrowings outstanding under the credit facilities. As of March 31, 2011, the aggregate unused credit available under the credit facilities was $453 million.

Long-term Debt. To fund current capital expenditures and maturities of long-term debt, PGE generally relies on the issuance of long-term debt. For 2011, PGE expects cash to be provided by operating activities will fund total capital and preliminary engineering expenditures, which are expected to amount to approximately $328 million. Accordingly, the Company does not anticipate issuing any long-term debt in 2011. During the first quarter of 2011, PGE elected to have $10 million of Port of St. Helens pollution control revenue bonds redeemed and retired. PGE has no other long-term debt that is scheduled to mature in 2011.

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,

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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 optimal interest rates. PGE’s common equity ratios were 47.8% and 46.7% as of March 31, 2011 and December 31, 2010, 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	Stable	Stable

The Company could be subject to requests by certain of its wholesale, commodity and related transmission counterparties to post additional performance assurance collateral in connection with its price risk management activities should Moody’s and/or S&P reduce their credit rating on PGE’s unsecured debt to below investment grade. The performance assurance collateral can be in the form of cash deposits or letters of credit, depending on the terms of the underlying agreements, and are based on the contract terms and commodity prices and can vary from period to period. These cash deposits are classified as Margin deposits in PGE’s condensed consolidated balance sheet, while any letters of credit issued are not reflected in the Company’s condensed consolidated balance sheet. As of March 31, 2011, PGE had posted approximately $206 million of collateral with these counterparties, consisting of $80 million in cash and $126 million in letters of credit, $23 million of which is affiliated with master netting agreements. Based on the Company’s energy portfolio, estimates of energy market prices, and the level of collateral outstanding as of March 31, 2011, the approximate amount of additional collateral that could be requested upon a single agency downgrade to below investment grade is approximately $125 million and decreases to approximately $66 million by December 31, 2011. The amount of additional collateral that could be requested upon a dual agency downgrade to below investment grade is approximately $246 million at March 31, 2011 and decreases to approximately $117 million by December 31, 2011.

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 certain provisions set forth in the Indenture of Mortgage and Deed of Trust (the Indenture) securing the bonds. PGE estimated that on March 31, 2011, under the most restrictive issuance test in the Indenture, the Company could have issued up to approximately $462 million of additional First Mortgage Bonds. Any additional issuances of first mortgage bonds would be subject to market conditions at the time of issuance. Furthermore, amounts could be further limited by regulatory authorizations or by covenants and tests contained in other financing agreements. PGE has the ability under certain circumstances to release property from the lien of the Indenture 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, 2011, the Company’s debt ratio, as calculated under the credit agreements, was 52.3%.

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Off-Balance Sheet Arrangements

PGE has no off-balance sheet arrangements other than outstanding letters of credit 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 2011 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, 2010, filed with the SEC on February 25, 2011. Such obligations have not changed materially as of March 31, 2011.



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, 2010, filed with the SEC on February 25, 2011.



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, 2011, these disclosure controls and procedures were effective.

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

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PART II - OTHER INFORMATION



Item 1.	Legal Proceedings.

For information regarding PGE’s legal proceedings, see 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, 2010, filed with the SEC on February 25, 2011.



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, 2010, filed with the SEC on February 25, 2011.



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).
31.1	Certification of Chief Executive Officer.
31.2	Certification of Chief Financial Officer.
32	Certifications of Chief Executive Officer and Chief Financial Officer.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

* In accordance with Regulation S-T, the XBRL-related information in Exhibit 101 to this Quarterly Report on Form 10-Q shall be deemed “furnished” and not “filed.”

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

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SIGNATURE

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.



		PORTLAND GENERAL ELECTRIC COMPANY
		(Registrant)


Date:	May 4, 2011	By:	/s/ Maria M. Pope
			Maria M. Pope
			Senior Vice President, Finance, Chief Financial Officer, and Treasurer
			(duly authorized officer and principal financial officer)

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Portland General Electric (POR) 10-Q2011 Q1 Quarterly report

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