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Document and Entity Information Document - shares	3 Months Ended
Document and Entity Information Document - shares	Mar. 31, 2011	Apr. 29, 2011
Entity Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2011
Document Fiscal Year Focus	2011
Document Fiscal Period Focus	Q1
Trading Symbol	POR
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		75,326,041

CONDENSED CONSOLIDATED STATEMENTS OF INCOME (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2011	Mar. 31, 2010
Statement [Line Items]
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	$ 0.26	$ 0.255

CONDENSED CONSOLIDATED BALANCE SHEETS (Unaudited) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2011	Dec. 31, 2010
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
Current liabilities
Accounts payable and accrued liabilites	144	169
Liabilities from price risk mangement activities - current	183	188
Short-term debt	0	19
Current portion of long-term debt	0	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 mangement 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)
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	$ 0	$ 0
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

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2011	Mar. 31, 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	0
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	0
Decrease in payables	(10)	(11)
Other working capital items, net	(16)	(13)
Other, net	0	(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	0	19
Other, net	0	(1)
Net cash used in investing activities	(70)	(73)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	0	191
Payments on long-term debt	(10)	(149)
Borrowings on short-term debt	0	4
Payments on commercial paper, net	(19)	0
Dividends paid	(20)	(19)
Debt issuance costs	0	(1)
Noncontrolling interests’ capital distributions	(4)	0
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	0
Non-cash investing and financing activities:
Accrued capital additions	9	68
Accrued dividends payable	$ 20	$ 20

NOTE 1. BASIS OF PRESENTATION	3 Months Ended
NOTE 1. BASIS OF PRESENTATION	Mar. 31, 2011
General Policies [Abstract]
BASIS OF PRESENTATION	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 cash flows.

NOTE 2. BALANCE SHEET COMPONENTS

3 Months Ended

Mar. 31, 2011

Balance Sheet Components Note [Abstract]

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.

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.

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 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

3 Months Ended

Mar. 31, 2011

Fair Value of Financial Instruments Note [Abstract]

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 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.



	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 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.

NOTE 4. PRICE RISK MANAGEMENT

3 Months Ended

Mar. 31, 2011

Price Risk Management Note [Abstract]

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

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 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.

NOTE 8. CONTINGENCIES	3 Months Ended
NOTE 8. CONTINGENCIES	Mar. 31, 2011
Contingencies Note [Abstract]
CONTINGENCIES	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. 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, 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 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 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.

NOTE 9. GUARANTEES	3 Months Ended
NOTE 9. GUARANTEES	Mar. 31, 2011
Guarantees Note [Abstract]
GUARANTEES	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.

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2011	Dec. 31, 2010
Statement [Line Items]
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares issued	75,325,603	75,316,419
Common stock, shares outstanding	75,325,603	75,316,419