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Document and Entity Information - USD ($)	12 Months Ended
Document and Entity Information - USD ($)	Dec. 31, 2011	Feb. 17, 2012	Jun. 30, 2011
Document Information [Line Items]
EntityRegistrantName	PORTLAND GENERAL ELECTRIC CO /OR/
EntityCentralIndexKey	0000784977
DocumentType	10-K
DocumentPeriodEndDate	Dec. 31, 2011
AmendmentFlag	false
DocumentFiscalYearFocus	2011
DocumentFiscalPeriodFocus	FY
CurrentFiscalYearEndDate	--12-31
EntityWellKnownSeasonedIssuer	Yes
EntityCurrentReportingStatus	Yes
EntityVoluntaryFilers	No
EntityFilerCategory	Large Accelerated Filer
EntityCommonStockSharesOutstanding		75,367,284
EntityPublicFloat			$ 1,900,588,219
TradingSymbol	POR

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Revenues, net	$ 1,813	$ 1,783	$ 1,804
Operating expenses:
Purchased power and fuel	760	829	944
Production and distribution	201	174	178
Administrative and other	218	186	179
Depreciation and amortization	227	238	211
Taxes other than income taxes	98	89	84
Total operating expenses	1,504	1,516	1,596
Income from operations	309	267	208
Other income:
Allowance for equity funds used during construction	5	13	18
Miscellaneous income, net	1	4	3
Other income, net	6	17	21
Interest expense	110	110	104
Income before income taxes	205	174	125
Income taxes	58	53	36
Net income (loss)	147	121	89
Less: net income (loss) attributable to noncontrolling interests	0	(4)	(6)
Net income attributable to Portland General Electric Company	$ 147	$ 125	$ 95
Weighted-average shares outstanding (in thousands):
Basic	75,333	75,275	72,790
Diluted	75,350	75,291	72,852
Earnings per share—basic and diluted	$ 1.95	$ 1.66	$ 1.31
Dividends declared per common share	$ 1.055	$ 1.035	$ 1.01

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net income (loss)	$ 147	$ 121	$ 89
Other comprehensive income - Change in compensation retirement benefits liability and amortization, net of taxes of $1 in 2011 and 2010	(1)	1	(1)
Comprehensive income	146	122	88
Less: comprehensive loss attributable to the noncontrolling interests	0	(4)	(6)
Comprehensive income attributable to Portland General Electric Company	$ 146	$ 126	$ 94

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the reporting entity. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, but excludes any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References

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-Publisher AICPA
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+ Details

- Definition

The change in equity [net assets] of a business enterprise during a period from transactions and other events and circumstances from non-owner sources which are attributable to the economic entity, including both controlling (parent) and noncontrolling interests. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners, including any and all transactions which are directly or indirectly attributable to that ownership interest in subsidiary equity which is not attributable to the parent.

+ References + Details

- Definition

The portion of net Income or Loss attributable to the noncontrolling interest (if any) deducted in order to derive the portion attributable to the parent.

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- Definition

The accumulated change in the value of either the projected benefit obligation or the plan assets resulting from experience different from that assumed or from a change in an actuarial assumption that has not been recognized in net periodic benefit cost, after tax.

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- Definition

The consolidated profit or loss for the period, net of income taxes, including the portion attributable to the noncontrolling interest.

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+ Details

Consolidated Statements of Comprehensive Income Parenthetical - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Net Taxes on change in compensation retirement benefits liability and amortization	$ 1	$ 1	$ 0

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Current assets:
Cash and cash equivalents	$ 6	$ 4
Accounts receivable, net	144	137
Unbilled revenues	101	93
Inventories, at average cost:
Materials and supplies	37	34
Fuel	34	22
Margin deposit	80	83
Regulatory assets--current	216	221
Other current assets	98	67
Total current assets	716	661
Electric utility plant:
Production	2,854	2,745
Transmission	393	372
Distribution	2,704	2,582
General	314	294
Intangible	331	286
Construction work in progress	120	125
Total electric utility plant	6,716	6,404
Accumulated depreciation and amortization	(2,431)	(2,271)
Electric utility plant, net	4,285	4,133
Regulatory assets--noncurrent	594	544
Nuclear decommissioning trust	37	34
Non-qualified benefit plan trust	36	44
Other noncurrent assets	65	75
Total assets	5,733	5,491
Current liabilities:
Accounts payable	111	102
Liabilities from price risk management activities-current	216	188
Short-term debt	30	19
Current portion of long-term debt	100	10
Regulatory liabilities--current	6	25
Accrued expenses and other current liabilities	151	145
Total current liabilities	614	489
Long-term debt, net of current portion	1,635	1,798
Regulatory liabilities--noncurrent	720	657
Deferred income taxes	529	445
Liabilities from price risk management activities--noncurrent	172	188
Unfunded status of pension and postretirement plans	195	140
Non-qualified benefit plan liabilities	101	97
Other noncurrent liabilities	101	78
Total liabilities	4,067	3,892
Commitments and Contingencies
Portland General Electric Company shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	0	0
Common stock, no par value, 160,000,000 shares authorized; 75,362,956 and 75,316,419 shares issued and outstanding as of December 31, 2011 and 2010, respectively	836	831
Accumulated other comprehensive loss	(6)	(5)
Retained earnings	833	766
Total Portland General Electric Company shareholders’ equity	1,663	1,592
Noncontrolling interests' equity	3	7
Total equity	1,666	1,599
Total liabilities and equity	$ 5,733	$ 5,491

Consolidated Balance Sheets Parentheticals - $ / shares	Dec. 31, 2011	Dec. 31, 2010
Stockholders' equity:
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	75,362,956	75,316,419
Common stock, shares outstanding	75,362,956	75,316,419

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock [Member]	Common Stock Including Additional Paid in Capital [Member]	Accumulated Other Comprehensive Income (Loss) [Member]	Retained Earnings [Member]	Noncontrolling Interest [Member]
Balance, shares at Dec. 31, 2008		62,575,257
Balance at Dec. 31, 2008			$ 659	$ (5)	$ 700	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock, net of issuance costs, shares		12,477,500
Issuance of common stock, net of issuance costs, value	$ 170		170	0	0	0
Vesting of restricted stock units, shares		128,175
Vesting of restricted stock units, value			0	0	0	0
Issuance of shares pursuant to employee stock purchase plan, shares		29,648
Issuance of shares pursuant to employee stock purchase plan, value			0	0	0	0
Noncontrolling interests' capital contributions, value			0	0	0	7
Dividends declared			0	0	76	0
Net income (loss)	89		0	0	95	(6)
Net Income (Loss) Attributable to Parent	95
Other comprehensive income (loss)			0	(1)	0	0
Balance, shares at Dec. 31, 2009		75,210,580
Balance at Dec. 31, 2009			829	(6)	719	1
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock, net of issuance costs, value	0
Vesting of restricted and performance stock units, shares		77,281
Vesting of restricted and performance stock units, value			0	0	0	0
Issuance of shares pursuant to employee stock purchase plan, shares		28,558
Issuance of shares pursuant to employee stock purchase plan, value			1	0	0	0
Noncontrolling interests' capital contributions, value			0	0	0	10
Stock-based compensation			1	0	0	0
Dividends declared			0	0	78	0
Net income (loss)	121		0	0	125	(4)
Net Income (Loss) Attributable to Parent	125
Other comprehensive income (loss)			0	1	0	0
Balance, shares at Dec. 31, 2010		75,316,419
Balance at Dec. 31, 2010	1,599		831	(5)	766	7
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Issuance of common stock, net of issuance costs, value	$ 0
Vesting of restricted and performance stock units, shares		17,944
Vesting of restricted and performance stock units, value			0	0	0	0
Issuance of shares pursuant to employee stock purchase plan, shares		25,435
Issuance of shares pursuant to employee stock purchase plan, value			1	0	0	0
Issuance of shares pursuant to dividend reinvestment and direct stock purchase plan, shares	3,158
Noncontrolling interests' capital contributions, value			0	0	0	(4)
Stock-based compensation			4	0	0	0
Dividends declared			0	0	80	0
Net income (loss)	$ 147		0	0		0
Net Income (Loss) Attributable to Parent	147
Other comprehensive income (loss)	(1)
Balance, shares at Dec. 31, 2011		75,362,956
Balance at Dec. 31, 2011	$ 1,666		$ 836	$ (6)	$ 833	$ 3

Consolidated Statement of Equity Parentheticals $ in Millions	12 Months Ended
	Dec. 31, 2009 USD ($)
Issuance costs	$ 6

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Cash flows from operating activities:
Net income (loss)	$ 147	$ 121	$ 89
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	227	238	211
Deferred income taxes	56	67	82
Renewable adjustment clause deferrals	22	(12)	(11)
Regulatory deferral of settled derivative instruments	12	26	(31)
Power cost deferrals, net of amortization	10	(1)	(18)
Increase (decrease) in net liabilities from price risk management activities	9	118	(145)
Regulatory deferrals--price risk management activities	(6)	(118)	145
Senate Bill 408 amortization	(7)	(13)	0
Allowance for equity funds used during construction	(5)	(13)	(18)
Decoupling mechanism deferrals, net of amortization	3	(10)	7
Unrealized gains on non-qualified benefit plan trust assets	0	(5)	(8)
Other non-cash income and expenses, net	38	27	43
Changes in working capital:
(Increase) decrease in receivables and unbilled revenues	(15)	24	11
Decrease (increase) in margin deposits	3	(27)	133
Income tax refund received	9	53	0
Increase in income taxes receivable	0	(22)	(53)
Increase (decrease) in payables and accrued liabilities	5	(11)	(16)
Other working capital items, net	(7)	0	2
Contribution to pension plan	(26)	(30)	0
Contribution to voluntary employees’ benefit association trust	(16)	(1)	0
Distribution of Trojan refund liability	0	0	(34)
Other, net	(6)	(20)	(3)
Net cash provided by operating activities	453	391	386
Cash flows from investing activities:
Capital expenditures	(300)	(450)	(696)
Purchases of nuclear decommissioning trust securities	50	46	36
Sales of nuclear decommissioning trust securities	46	50	36
Distribution from nuclear decommissioning fund	0	19	0
Other, net	5	(3)	(4)
Net cash used in investing activities	(299)	(430)	(700)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	0	249	580
Payments on long-term debt	(73)	(186)	(142)
Proceeds from Issuance of Common Stock, net of issuance cost	0	0	170
Issuances (maturities) of commercial paper, net	11	19	(65)
Borrowings on short-term debt	0	11	0
Payments on short-term debt	0	(11)	(7)
Borrowings on revolving lines of credit	0	0	82
Payments on revolving lines of credit	0	0	(213)
Dividends paid	(79)	(78)	(72)
Premium paid on repayment of long-term debt	(7)	0	0
Debt issuance costs	0	(2)	(5)
Noncontrolling interests’ capital (distributions) contributions	(4)	10	7
Net cash (used in) provided by financing activities	(152)	12	335
Change in cash and cash equivalents	2	(27)	21
Cash and cash equivalents, beginning of year	4	31	10
Cash and cash equivalents, end of year	6	4	31
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	103	98	74
Cash paid for income taxes	3	0	2
Non-cash investing and financing activities:
Accrued capital additions	19	12	17
Accrued dividends payable	21	20	20
Preliminary engineering transferred to Construction work in progress from Other noncurrent assets	$ 7	$ 0	$ 0

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2011
Basis of Presentation [Abstract]
Basis of Presentation	BASIS OF PRESENTATION Nature of Operations 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 marketers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. PGE’s corporate headquarters is located in Portland, Oregon and its service area is located entirely within Oregon. PGE’s service area includes 52 incorporated cities, of which Portland and Salem are the largest, within a state-approved service area allocation of approximately 4,000 square miles. As of December 31, 2011, PGE served 822,466 retail customers with a service area population of approximately 1.7 million, comprising approximately 44% of the state’s population. As of December 31, 2011, PGE had 2,634 employees, with 840 employees covered under two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 804 and 36 employees and expire in February 2015 and August 2014, respectively. PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. Consolidation Principles The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries and those variable interest entities (VIEs) where PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. Intercompany balances and transactions have been eliminated. For entities that are determined to meet the definition of a VIE and where the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. For further information, see Note 16, Variable Interest Entities. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Reclassifications To conform with the 2011 presentation, PGE reclassified $67 million of accrued expenses in the 2010 consolidated balance sheet, consisting of accrued employee compensation and benefits and other, from Accounts payable to Accrued expenses and other current liabilities, and segregated Renewable adjustment clause deferrals from Other non-cash income and expenses, net in the operating activities section in the 2010 and 2009 consolidated statements of cash flows.

- Definition

The entire disclosure for organization, consolidation and basis of presentation of financial statements disclosure.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
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+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies Note [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash and Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had none as of December 31, 2011 and 2010.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts and do not bear interest when recorded. Late payment fees on balances in arrears are first assessed 16 business days after the due date. An inactive account balance is charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the final due date.

Estimated provisions for uncollectible accounts receivable related to retail sales, charged to Administrative and other expense, are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection of customer accounts, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors.

Provisions related to wholesale accounts receivable and unsettled positions, charged to Purchased power and fuel expense, are based on a periodic review and evaluation that includes counterparty non-performance risk and contractual rights of offset when applicable. Actual amounts written off are charged to the allowance for uncollectible accounts.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities, unless they qualify for the normal purchases and normal sales exception. Changes in fair value are recognized in the statement of income, offset by the effects of regulatory accounting.

Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load meet the requirements for treatment under the normal purchases and normal sales exception. Other activities consist of certain electricity forwards, options and swaps, certain natural gas forwards, options, and swaps, and forward contracts for acquiring Canadian dollars. Such activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers.

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. Contracts that qualify for the normal purchases and normal sales exception are not required to be recorded at fair value. Unrealized gains and losses from contracts that qualify as cash flow hedges are recorded net in Other comprehensive income and contracts not designated as cash flow hedges are recorded net in Purchased power and fuel expense on the statements of income.

Physical electricity sale and purchase transactions are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while financial transactions are recorded on a net basis in Purchased power and fuel expense upon settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are classified as Margin deposits in the accompanying consolidated balance sheets and were $80 million and $83 million as of December 31, 2011 and 2010, respectively. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet and were $104 million and $180 million as of December 31, 2011 and 2010, respectively.

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, oil, and coal. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.

Electric Utility Plant

Capitalization Policy

Electric utility plant is capitalized at its original cost. Costs include direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period.

PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 8% in 2011 and 2010, and 7% in 2009. AFDC from borrowed funds was $3 million in 2011, $9 million in 2010, and $12 million in 2009 and is reflected as a reduction to Interest expense. AFDC from equity funds was $5 million in 2011, $13 million in 2010, and $18 million in 2009 and is reflected as a component of Other income, net.

Costs which are disallowed for recovery in customer prices are charged to expense at the time such disallowance is probable.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.7% in 2011, 3.9% in 2010, and 3.8% in 2009. Estimated asset retirement removal costs included in depreciation expense were $49 million in the year ended December 31, 2011 and $47 million in each of the years ended December 31, 2010 and 2009.

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. On September 13, 2010, PGE received an order from the OPUC authorizing new depreciation rates to be effective January 2011.

Thermal production plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2050. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):



Production, excluding thermal:
Hydro	86
Wind	27
Transmission	53
Distribution	40
General	14

The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are charged to AROs for assets that meet the definition of a legal obligation and to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs.

On June 21, 2011, PGE received an order from the OPUC authorizing an increase in customer prices effective July 1, 2011 for depreciation expense and decommissioning costs related to the Company’s commitment to cease coal-fired operations at Boardman at the end of 2020.

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $153 million and $133 million as of December 31, 2011 and 2010, respectively, with amortization expense of $19 million in 2011, $17 million in 2010, and $16 million in 2009. Future estimated amortization expense as of December 31, 2011 is as follows: $20 million in 2012; $14 million in 2013; $12 million in 2014; $11 million in 2015; and $8 million in 2016.

Marketable Securities

All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.

Regulatory Accounting

Regulatory Assets and Liabilities

As a rate-regulated enterprise, the Company applies regulatory accounting, resulting in regulatory assets or regulatory liabilities. Regulatory assets represent (i) probable future revenue associated with certain costs that are expected to be recovered from customers through the ratemaking process, or (ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established by or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the statement of income over the period in which it is included in prices.

Circumstances that could result in the discontinuance of regulatory accounting include (i) increased competition that restricts the Company’s ability to establish prices to recover specific costs, and (ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of the Company’s regulatory assets is probable.

For additional information concerning the Company’s regulatory assets and liabilities, see Note 6, Regulatory Assets and Liabilities.

Power Cost Adjustment Mechanism

PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband.” If the difference between actual NVPC and baseline NVPC falls within the established deadband range, PGE absorbs the incremental cost or benefit, with the difference falling outside the lower and upper thresholds of the deadband range being shared 90/10 between customers and the Company, respectively. Any customer refund or collection is also subject to a regulated earnings test. A refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE. A collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s last authorized ROE. PGE’s authorized ROE was 10% for 2011, 2010, and 2009. A final determination of any customer refund or collection is made by the OPUC through an annual public filing and review.

PGE estimates and records amounts related to the PCAM on a quarterly basis during the year. If the projected difference between baseline and actual NVPC for the year exceeds the established deadband, and if forecasted earnings exceed the level required by the regulated earnings test, a regulatory liability is recorded for any future amount payable to retail customers, with offsetting amounts recorded to Purchased power and fuel expense. If the difference is below the lower end of the deadband, a regulatory asset is recorded for any future amount due from retail customers.

For 2011, the deadband ranged from $15 million below to $30 million above baseline NVPC. PGE’s actual NVPC as determined pursuant to the PCAM for 2011 was below baseline NVPC by $34 million, which is $19 million below the lower deadband threshold. For 2011, PGE recorded an estimated refund to customers of $10 million, reduced from the $17 million potential refund to customers as a result of the regulated earnings test. A final determination regarding the 2011 PCAM results will be made by the OPUC through a public filing and review in 2012.

For 2010, the deadband ranged from $17 million below to $35 million above baseline NVPC. Although PGE’s actual NVPC as determined pursuant to the PCAM for 2010 was below baseline NVPC by $12 million, it was within the established deadband range and, accordingly, no customer refund was recorded in 2010. A final determination regarding the 2010 PCAM results was made by the OPUC through a public filing and review in 2011, which concluded that no customer refund was warranted for 2010.

For 2009, the deadband ranged from $15 million below to $29 million above baseline NVPC. Although PGE’s actual NVPC as determined pursuant to the PCAM for 2009 exceeded baseline NVPC by $22 million, it was within the established deadband range and, accordingly, no customer collection was recorded in 2009. A final determination regarding the 2009 PCAM results was made by the OPUC through a public filing and review in 2010, which concluded that no customer collection was warranted for 2009.

Asset Retirement Obligations

An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. PGE recognizes those legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future removal expenditures is capitalized as an ARO on the consolidated balance sheets and revised periodically, with actual expenditures charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income.

Contingencies

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred.

A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons.

If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period.

Gain contingencies are recognized when realized and are disclosed when material.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position as of December 31, 2011 and 2010.

Revenue Recognition

Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $41 million in 2011, $39 million in 2010, and $38 million in 2009.

Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices.

As a rate-regulated utility, there are situations in which PGE accrues revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “Regulatory Assets and Liabilities” in this Note 2.

Stock-Based Compensation

The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.

Income Taxes

Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.

As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. These amounts were recognized as net regulatory assets of $87 million and $95 million as of December 31, 2011 and 2010, respectively, and will be included in prices when the temporary differences reverse.

Investment tax credits utilized were deferred and amortized to income over the lives of the related properties, and were fully amortized by the end of 2011.

Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet.

PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Recent Accounting Pronouncements

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 4, 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 the Company’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.

In May 2011, ASU 2011-04, Fair Value Measurements and Disclosures (Topic 820) - Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs (ASU 2011-04) was issued. Many of the amendments in ASU 2011-04 change the wording used to describe principles and requirements to align with International Financial Reporting Standards as issued by the International Accounting Standards Board, and are not intended to change the application of Topic 820. Some of the amendments clarify the Financial Accounting Standards Board’s intent on the application of existing fair value guidance or change a particular principle or requirement for measuring fair value or fair value disclosures. The amendments in ASU 2011-04 are to be applied prospectively and are effective for interim and annual periods beginning after December 15, 2011 for public entities, with early application not permitted. PGE will adopt the amendments contained in ASU 2011-04 on January 1, 2012, which are not expected to have a material impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In June 2011, ASU 2011-05, Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU 2011-05) was issued. The amendments of ASU 2011-05 require, among other things, that an entity report items of other comprehensive income in one of two ways: (i) a single statement with components of net income and total net income, the components of other comprehensive income and total other comprehensive income, and a total for comprehensive income; or (ii) two statements with components of net income and total net income in the first statement, immediately followed by a statement that presents the components of other comprehensive income, a total for other comprehensive income, and a total for comprehensive income. The amendments in ASU 2011-05 are to be applied retrospectively and are effective for interim and annual periods beginning after December 15, 2011, with early application permitted. PGE adopted the amendments contained in ASU 2011-05 on December 31, 2011, which had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

In December 2011, ASU 2011-12, Comprehensive Income (Topic 220) - Presentation of Comprehensive Income (ASU 2011-12) was issued and defers only the changes in ASU 2011-05 that relate to the presentation of reclassification adjustments, which pertain to how and where reclassification adjustments are presented. ASU 2011-12 is effective at the same time as ASU 2011-05. Accordingly, PGE adopted the amendments contained in ASU 2011-12 on December 31, 2011, which had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

Balance Sheet Components

12 Months Ended

Dec. 31, 2011

Balance Sheet Components Note [Abstract]

Balance Sheet Components

BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable is net of an allowance for uncollectible accounts of $6 million and $5 million as of December 31, 2011 and 2010, respectively. The following is the activity in the allowance for uncollectible accounts (in millions):



	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	5		$	5		$	4
Increase in provision	11			7			9
Amounts written off, less recoveries	(10		)	(7		)	(8		)
Balance as of end of year	$	6		$	5		$	5

Trust Accounts

PGE maintains two trust accounts as follows:

Nuclear decommissioning trust—Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) and represent amounts collected from customers less qualified expenditures plus any realized and unrealized gains and losses on the investments held therein.

Non-qualified benefit plan trust—Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans and represents contributions made by the Company less qualified expenditures plus any realized and unrealized gains and losses on the investment held therein.

The trusts are comprised of the following investments as of December 31 (in millions):



	Nuclear Decommissioning Trust				Non-Qualified Benefit Plan Trust
	2011		2010		2011		2010
Cash equivalents	$	14	$	13	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		10		19
Debt securities	23		21		3		2
Insurance contracts, at cash surrender value	—		—		23		23
	$	37	$	34	$	36	$	44

For information concerning the fair value measurement of those assets recorded at fair value held in the trusts, see Note 4, Fair Value of Financial Instruments.

Other Current Assets and Accrued Expenses and Other Current Liabilities

Other current assets and Accrued expenses and other current liabilities consist of the following (in millions):



	As of December 31,
	2011		2010
Other current assets:
Current deferred income tax asset	$	33	$	—
Assets from price risk management activities	19		13
Income taxes receivable	12		22
Other	34		32
	$	98	$	67

Accrued expenses and other current liabilities:
Accrued employee compensation and benefits	$	44	$	36
Accrued interest payable	24		26
Dividends payable	21		20
Other	62		63
	$	151	$	145

Other Noncurrent Assets

The Company incurs preliminary engineering costs related to potential future capital projects, which are capitalized in Other noncurrent assets in the consolidated balance sheets. Preliminary engineering costs consist of expenditures for preliminary surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects being considered. Once the project is approved for construction, such costs are reclassified to Electric utility plant. If the project is abandoned, such costs are expensed to Production and distribution expense 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 December 31, 2011 and 2010, PGE has recorded preliminary engineering costs of $10 million and $13 million, respectively. For the years ended December 31, 2011, 2010, and 2009, no material preliminary engineering costs were expensed.

Fair Value of FInancial Instruments

12 Months Ended

Dec. 31, 2011

Fair Value of Financial Instruments Note [Abstract]

Fair Value of FInancial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2011 and 2010, and then classified based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below.

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date.

Level 2—Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date.

Level 3—Pricing inputs include significant inputs which are unobservable for the asset or liability.

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.

PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels, except those net transfers out of Level 3 to Level 2 presented in this note, for the years ended December 31, 2011 and 2010.

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 December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust ⁽¹⁾:
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		11		—		11
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	7		2		—		9
International	1		—		—		1
Debt securities - domestic government	3		—		—		3
Assets from price risk management activities ^{(1) (3)}:
Electricity	—		2		—		2
Natural gas	—		17		—		17
	$	14	$	55	$	—	$	69
Liabilities - Liabilities from price risk management activities ^{(1) (3)}:
Electricity	$	—	$	108	$	29	$	137
Natural gas	—		201		50		251
	$	—	$	309	$	79	$	388


(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 5, 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:
Domestic government	3		9		—		12
Corporate credit	—		9		—		9
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	16		—		—		16
International	2		1		—		3
Debt securities - domestic government	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 5, Price Risk Management.

Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and allocated to securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors:

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds held in the Nuclear decommissioning trust are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices.

Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These securities are classified as Level 1 in the fair value hierarchy due to the highly observable nature of the pricing in an active market.

Fair values for municipal debt and corporate credit securities are classified as Level 2 as prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable.

Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE), both American stock exchanges. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs may not be directly observable in the marketplace.

Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign exchange rate risk, mitigate the effects of market fluctuations, and manage volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Price Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as quoted forward prices for commodities and interest rates. 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 over-the-counter forwards and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term over-the-counter forward and swap derivatives. Commodity option contracts whose fair value is derived using standardized valuation techniques, such as Black-Scholes, are also classified as Level 3. Inputs into the valuation of commodity option contracts include forward commodity pricing, forward interest rates, and historic volatilities and correlations.

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 for the year ended December 31, 2011 (in millions):



Net liabilities from price risk management activities as of December 31, 2010	$	120
Net realized and unrealized losses ⁽¹⁾	86
Purchases	3
Settlements	(1		)
Net transfers out of Level 3 to Level 2	(129		)
Net liabilities from price risk management activities as of December 31, 2011	$	79

Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	88


(1)	Contains nominal amounts of realized losses, net.

The comparable information contained in the preceding table was as follows for the years ended December 31 (in millions):



	2010			2009
Net liabilities from price risk management activities as of beginning of year	$	154		$	123
Net realized and unrealized losses ⁽¹⁾	65			47
Purchases, issuances, and settlements, net	27			—
Net transfers out of Level 3 to Level 2	(126		)	(16		)
Net liabilities from price risk management activities as of end of year	$	120		$	154

Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	95		$	49


(1)	Contains nominal amounts of realized losses, net.

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.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. 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 December 31, 2011, the estimated aggregate fair value of PGE’s long-term debt was $2,091 million, compared to its $1,735 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.

For fair value information concerning the Company’s pension plan assets, see Note 10, Employee Benefits.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44A, 44B
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15C, 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15A
-Subparagraph a-d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 15B
-Subparagraph a, b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 107
-Paragraph 3, 10, 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 157
-Paragraph 32, 33, 34
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
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Reference 8: http://www.xbrl.org/2003/role/presentationRef
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+ Details

Price Risk Management

12 Months Ended

Dec. 31, 2011

Price Risk Management Note [Abstract]

Price Risk Management

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 fuel and power purchases and sales resulting from economic dispatch decisions for its own generation. As a result of this ongoing business activity, PGE is exposed to commodity price risk and foreign currency exchange rate risk, where adverse changes in prices and/or rates may affect the Company’s financial position, performance, or cash flow.

PGE utilizes derivative instruments in its wholesale electric utility activities to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in net power costs for its retail customers. These derivative instruments may include forward, swap, and option contracts for electricity, natural gas, oil and foreign currency, which are recorded at fair value on the consolidated balance sheet, with changes in fair value recorded in the statement of income. In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative activity until realized. This accounting treatment defers the fair value gains and losses on derivative activities until settlement of the associated derivative instrument. PGE may designate certain derivative instruments as cash flow hedges or may use derivative instruments as economic hedges. PGE does not engage in trading activities for non-retail purposes.

PGE has elected to report gross 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 December 31, 2011 and 2010, the Company had $26 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, which are expected to deliver or settle at various dates through 2015, were as follows (in millions):



	As of December 31,
	2011			2010
Commodity contracts:
Electricity	13		MWh	9		MWh
Natural gas	79		Decatherms	93		Decatherms
Foreign currency exchange	$	6	Canadian	$	7	Canadian

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



	As of December 31,
	2011			2010
Current assets:
Commodity contracts:
Electricity	$	2		$	4
Natural gas	17			9
Total current derivative assets	19		⁽¹⁾	13		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity	—			1
Natural gas	—			2
Total noncurrent derivative assets	—			3		⁽²⁾
Total derivative assets not designated as hedging instruments	$	19		$	16
Total derivative assets	$	19		$	16
Current liabilities:
Commodity contracts:
Electricity	$	66		$	77
Natural gas	150			111
Total current derivative liabilities	216			188
Noncurrent liabilities:
Commodity contracts:
Electricity	71			42
Natural gas	101			146
Total noncurrent derivative liabilities	172			188
Total derivative liabilities not designated as hedging instruments	$	388		$	376
Total derivative liabilities	$	388		$	376


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


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

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



	Years Ended December 31,
	2011		2010		2009
Commodity contracts:
Electricity	$	117	$	127	$	79
Natural Gas	98		192		101

Net unrealized losses and certain net realized losses presented in the table above are offset within the statement of income by the effects of regulatory accounting. Of the net loss recognized in net income for the years ended December 31, 2011, 2010, and 2009, $192 million, $258 million, and $98 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 December 31, 2011 related to PGE’s derivative activities would be realized as a result of the settlement of the underlying derivative instrument (in millions):



	2012		2013		2014		2015		Total
Commodity contracts:
Electricity	$	64	$	42	$	21	$	8	$	135
Natural gas	132		72		24		6		234
Net unrealized loss	$	196	$	114	$	45	$	14	$	369

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 some other counterparties will have the right to terminate their agreements with the Company.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2011 was $321 million, for which the Company had $104 million in posted collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered at December 31, 2011, the cash requirement to either post as collateral or settle the instruments immediately would have been $302 million.

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:



	As of December 31,
	2011		2010
Assets from price risk management activities:
Counterparty A	19	%	1	%
Counterparty B	16		1
Counterparty C	13		5
Counterparty D	7		22
Counterparty E	7		23
Counterparty F	—		11
Counterparty G	—		10
	62	%	73	%
Liabilities from price risk management activities:
Counterparty E	23	%	24	%
Counterparty H	10		4
Counterparty I	7		12
	40	%	40	%

For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 4, Fair Value of Financial Instruments.

- Definition

The entire disclosure for the entity's entire derivative instruments and hedging activities. Describes an entity's risk management strategies, derivatives in hedging activities and non-hedging derivative instruments, the assets, obligations, liabilities, revenues and expenses arising therefrom, and the amounts of and methodologies and assumptions used in determining the amounts of such items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 45
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 44
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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+ Details

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2011

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

REGULATORY ASSETS AND LIABILITIES

The majority of PGE’s regulatory assets and liabilities are reflected in customer prices and are amortized over the period in which they are reflected in customer prices. Items not currently reflected in prices are pending before the regulatory body as discussed below.

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



		Weighted Average Remaining Life ⁽¹⁾	As of December 31,
			2011				2010
			Current		Noncurrent		Current		Noncurrent
Regulatory assets:
	Price risk management ⁽²⁾	2 years	$	194	$	172	$	175	$	185
	Pension and other postretirement plans ⁽²⁾	⁽³⁾	—		295		—		213
	Deferred income taxes ⁽²⁾	⁽⁴⁾	—		87		—		95
	Deferred broker settlements ⁽²⁾	1 year	11		—		24		—
	Renewable energy deferral	1 year	1		—		22		—
	Debt reacquisition costs ⁽²⁾	7 years	—		28		—		23
	Other ⁽⁵⁾	Various	10		12		—		28
	Total regulatory assets		$	216	$	594	$	221	$	544
Regulatory liabilities:
	Asset retirement removal costs ⁽⁶⁾	⁽⁴⁾	$	—	$	637	$	—	$	588
	Asset retirement obligations ⁽⁶⁾	⁽⁴⁾	—		36		—		33
	Power cost adjustment mechanism	⁽⁷⁾	—		10		—		—
	Trojan ISFSI pollution control tax credits	⁽⁷⁾	—		7		18		4
	Other	Various	6		30		7		32
	Total regulatory liabilities		$	6	$	720	$	25	$	657


(1)	As of December 31, 2011.


(2)	Does not include a return on investment.


(3)	Recovery expected over the average service life of employees. For additional information, see Note 2, Summary of Significant Accounting Policies.


(4)	Recovery expected over the estimated lives of the assets.


(5)	Of the total other unamortized regulatory asset balances, a return is recorded on $21 million and $26 million as of December 31, 2011 and 2010, respectively.


(6)	Included in rate base for ratemaking purposes.


(7)	Refund period not yet determined.

As of December 31, 2011, PGE had regulatory assets of $22 million earning a return on investment at the following rates: (i) $7 million at PGE’s authorized cost of capital, currently 8.033%; (ii) $7 million at the approved rate for deferred accounts under amortization, ranging from 2.01% to 4.27%, depending on the year of approval; and (iii) $8 million earning a return by inclusion in rate base.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. During the fourth quarter of 2011, PGE received an order from the OPUC on its Annual Update Tariff for 2012 net variable power costs (NVPC). Pursuant to the order, the OPUC reduced the Company’s 2012 NVPC forecast by approximately $3 million, which is reflected as a reduction to the regulatory asset for price risk management as of December 31, 2011. For further information regarding assets and liabilities from price risk management activities, see Note 5, Price Risk Management.

Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic benefit cost. For further information, see Note 10, Employee Benefits.

Deferred income taxes represents income tax benefits resulting from property-related timing differences that previously flowed to customers and will be included in customer prices when the temporary differences reverse. For further information, see Note 11, Income Taxes.

Deferred broker settlements consist of transactions that have been financially settled by clearing brokers prior to the contract delivery date. These gains and losses are deferred for future recovery in customer prices during the corresponding contract settlement month.

Renewable energy deferral reflects the net revenue requirement related to new renewable resources and associated transmission that are not yet included in customer prices, with the majority related to Biglow Canyon Wind Farm. Recovery of net revenue requirements associated with new renewable resources, which are required by the 2007 Oregon Renewable Energy Act, is allowed under a renewable adjustment clause mechanism authorized by the OPUC.

Asset retirement removal costs represent the costs that do not qualify as AROs and are a component of depreciation expense allowed in customer prices. Such costs are recorded as a regulatory liability as they are collected in prices, and are reduced by actual removal costs incurred.

Asset retirement obligations represent the difference in the timing of recognition of (i) the amounts recognized for depreciation expense of the asset retirement costs and accretion of the ARO, and (ii) the amount recovered in customer prices.

Asset Retirement Obilgations

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

AROs, which are included in Other noncurrent liabilities in the consolidated balance sheets, consist of the following (in millions):



	As of December 31,
	2011		2010
Trojan decommissioning activities	$	37	$	38
Utility plant	38		16
Non-utility property	12		10
Asset retirement obligations	$	87	$	64

Trojan decommissioning activities represents the present value of future decommissioning expenditures for the plant, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the Independent Spent Fuel Storage Installation (ISFSI), an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI is to house the spent nuclear fuel at the former plant site until permanent off-site storage is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a U.S. Department of Energy (USDOE) facility is complete, which is not expected prior to 2033.

In 2004, the co-owners of Trojan (PGE, Eugene Water & Electric Board, and PacifiCorp, collectively referred to as Plaintiffs) filed a complaint against the USDOE for failure to accept spent nuclear fuel by January 31, 1998. PGE had contracted with the USDOE for the permanent disposal of spent nuclear fuel in order to allow the final decommissioning of Trojan. The Plaintiffs paid for permanent disposal services during the period of plant operation and have met all other conditions precedent. The Plaintiffs are seeking approximately $128 million in damages. PGE’s share of any recovery would be approximately 67%. A trial before the U.S. Court of Federal Claims commenced in the fourth quarter of 2011, with a decision expected during 2012. However, if the Plaintiffs were to prevail, the USDOE would likely appeal, which would defer any damage payment indefinitely. The Trojan ARO will not be impacted by the outcome of this case as such potential recovery is for past decommissioning costs and the ARO reflects only future decommissioning expenditures. Any proceeds received related to this legal matter would be returned to customers to offset amounts previously collected in relation to Trojan decommissioning activities.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, distribution and transmission assets where disposal is governed by environmental regulation, as well as the Bull Run hydro project. Decommissioning work has been substantially completed at Bull Run, with only environmental monitoring continuing through 2012.

During 2011, an updated decommissioning study for PGE’s Boardman coal-fired plant was completed, which included the assumption that Boardman’s coal-fired operations cease in 2020 rather than 2040. As a result of the study, PGE increased its ARO related to Boardman by approximately $20 million, with a corresponding increase in the cost basis of the plant, included in Electric utility plant, net on the consolidated balance sheet. Such transaction is non-cash and is excluded from investing activities in the consolidated statement cash flows for the year ended December 31, 2011.

Non-utility property primarily represents ARO’s which have been recognized for portions of unregulated properties leased to third parties.

The following is a summary of the changes in the Company’s AROs (in millions):



	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	64		$	63		$	58
Liabilities incurred	1			1			—
Liabilities settled	(4		)	(3		)	(4		)
Accretion expense	4			4			4
Revisions in estimated cash flows	22			(1		)	5
Balance as of end of year	$	87		$	64		$	63

Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. Recovery of Trojan decommissioning costs is included in PGE’s retail prices, currently at approximately $4 million annually, with an equal amount recorded in Depreciation and amortization expense.

PGE maintains a separate trust account, Nuclear decommissioning trust in the consolidated balance sheet, for funds collected from customers through prices to cover the cost of Trojan decommissioning activities. See “Trust Accounts” in Note 3, Balance Sheet Components, for additional information on the Nuclear decommissioning trust.

The Oak Grove hydro facility and transmission and distribution plant located on public right-of-ways and on certain easements meet the requirements of a legal obligation and will require removal when the plant is no longer in service. An ARO liability is not currently measurable as management believes that these assets will be used in utility operations for the foreseeable future. Removal costs are charged to accumulated asset retirement removal costs, which is included in Regulatory liabilities on PGE’s consolidated balance sheets.

Revolving Credit Facilities

12 Months Ended

Dec. 31, 2011

Line of Credit Facility [Abstract]

Revolving Credit Facilities

REVOLVING CREDIT FACILITIES

PGE has two unsecured revolving credit facilities, with an aggregate borrowing capacity of $670 million, as follows:


•	A $370 million syndicated credit facility, of which $10 million is scheduled to terminate in July 2012 and $360 million in July 2013;


•	A $300 million syndicated credit facility, which is scheduled to terminate in December 2016.

Pursuant to the terms of the agreements, both credit facilities may be used for general corporate purposes and as backup for commercial paper borrowings, and also permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. Both credit facilities require annual fees based on PGE’s unsecured credit ratings, and contain customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65.0% of total capitalization. As of December 31, 2011, PGE was in compliance with this covenant with a 51.5% 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 FERC, the Company is authorized to issue short-term debt up to $700 million through February 6, 2014. The authorization provides that if utility assets financed by unsecured debt are divested, then a proportionate share of the unsecured debt must also be divested.

As of December 31, 2011, PGE had no borrowings and $30 million in commercial paper outstanding under the credit facilities, with $124 million in letters of credit issued. As of December 31, 2011, the aggregate unused available credit under the credit facilities is $516 million.

Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions):



	Years Ended December 31,
	2011			2010			2009
Average daily amount of short-term debt outstanding	$	2		$	9		$	28
Weighted daily average interest rate *	0.4		%	0.4		%	1.3		%
Maximum amount outstanding during the year	$	44		$	51		$	205


*	Excludes the effect of commitment fees, facility fees and other financing fees.

Long-term Debt

12 Months Ended

Dec. 31, 2011

Long-term Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT

Long-term debt consists of the following (in millions):



	As of December 31,
	2011			2010
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.83% in 2011 and 5.85% in 2010, due at various dates through 2040	$	1,615		$	1,678
Pollution Control Revenue Bonds:
Port of Morrow, Oregon, 5% rate, due 2033	23			23
City of Forsyth, Montana, 5% rate, due 2033	119			119
Port of St. Helens, Oregon, 5.25% rate, due in 2014	—			10
Total Pollution Control Revenue Bonds	142			152
Pollution Control Revenue Bonds owned by PGE	(21		)	(21		)
Unamortized debt discount	(1		)	(1		)
Total long-term debt	1,735			1,808
Less: current portion of long-term debt	(100		)	(10		)
Long-term debt, net of current portion	$	1,635		$	1,798

First Mortgage Bonds—The Indenture securing PGE’s First Mortgage Bonds constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. On December 29, 2011, PGE redeemed $63 million of the 6.5% series due 2014.

Pollution Control Revenue Bonds—PGE has the option to remarket Pollution Control Revenue Bonds held by the Company through 2033. At the time of any remarketing, PGE can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing and could be backed by first mortgage bonds or a bank letter of credit depending on market conditions.

As of December 31, 2011, the future minimum principal payments on long-term debt are as follows (in millions):



Years ending December 31:
2012	$	100
2013	100
2014	—
2015	70
2016	67
Thereafter	1,398
	$	1,735

Interest is payable semi-annually on all long-term debt instruments.

Employee Benefits

12 Months Ended

Dec. 31, 2011

Employee Benefits [Abstract]

Employee Benefits

EMPLOYEE BENEFITS

Pension and Other Postretirement Plans

Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan. The plan has been closed to most new employees since January 31, 2009 and to all new employees since January 1, 2012. Such closure did not change the benefits provided to existing participants under the plan.

The assets of the pension plan are held in a trust and are comprised of equity, debt, and alternative asset investment vehicles, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31.

During 2011 and 2010, PGE made contributions to the pension plan of $26 million and $30 million, respectively, with no contributions in 2009. No contributions to the pension plan are expected in 2012.

Other Postretirement Benefits—PGE has non-contributory postretirement health and life insurance plans, as well as Health Reimbursement Accounts (HRAs) for its employees (collectively “Other Postretirement Benefits” in the following tables). Employees are covered under a Defined Dollar Medical Benefit Plan which limits PGE’s obligation pursuant to the postretirement health plan by establishing a maximum benefit per employee with employees paying the additional cost.

The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, common stocks, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions which are reviewed annually with PGE’s consulting actuaries and trust investment consultants and updated as appropriate, with measurement dates of December 31.

Contributions to the HRAs provide for claims by retirees for qualified medical costs. For bargaining employees, the participants’ accounts are credited with 58% of the value of the employee’s accumulated sick time as of April 30, 2004, plus 100% of their earned time off accumulated at the time of retirement. For active non-bargaining employees, the Company grants a fixed dollar amount that will become available for qualified medical expenses upon their retirement.

Non-Qualified Benefit Plans—The Non-Qualified Benefit Plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan (SERP), and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. These trust assets are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified benefit plans is December 31.

Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. The Company also provides two retired employees with death benefits through a split dollar life insurance policy which pays a fixed amount to the beneficiary and for which the Company has a security interest for the amount of premiums paid. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions):



	2011						2010
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	17	$	19	$	36	$	19	$	25	$	44
Non-qualified benefit plan liabilities *	25		76		101		24		73		97


*	For the NQBP, excludes the current portion of $2 million in 2011 and 2010, which is classified in Other current liabilities in the consolidated balance sheets.

See “Trust Accounts” in Note 3, Balance Sheet Components, for information on the Non-qualified benefit plan trust.

Investment Policy and Asset Allocation—The Board of Directors of PGE appoints an Investment Committee, which is comprised of officers of the Company. In addition, the Board also establishes the Company’s asset allocation. The Investment Committee is then responsible for implementation and oversight of the asset allocation. The Company’s investment policy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities and other alternative investments. The commitments to each class are controlled by an asset deployment and cash management strategy that takes profits from asset classes whose allocations have shifted above their target ranges to fund benefit payments and investments in asset classes whose allocations have shifted below their target ranges.

The asset allocations for the plans, and the target allocation, are as follows:



	As of December 31,
	2011				2010
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	68	%	67	%	68	%	67	%
Debt securities	32		33		32		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	61	%	72	%	46	%	47	%
Debt securities	39		28		54		53
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	30	%	23	%	42	%	42	%
Debt securities	7		14		5		7
Insurance contracts	63		63		53		51
Total	100	%	100	%	100	%	100	%

The Target for the Defined Benefit Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the Non-Qualified Benefit Plans, these Targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average Targets for the Other Postretirement Benefit Plans and Non-Qualified Benefit Plans, reported percentages are affected by the fair market values of the investments within the pools.

The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. Equity securities primarily include investments across the capitalization ranges and style biases, both domestically and internationally. Fixed income securities include, but are not limited to, corporate bonds of companies from diversified industries, mortgage-backed securities, and U.S. Treasuries. Other types of investments include investments in hedge funds and private equity funds that follow several different strategies.

The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions):



	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	3	$	—	$	3
Equity securities:
Domestic	151		12		—		163
International	54		51		—		105
Debt securities:
Domestic government and corporate credit	—		78		—		78
Corporate credit	76		—		—		76
Private equity funds	—		—		32		32
Alternative investments	—		—		30		30
	$	281	$	144	$	62	$	487
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	12		1		—		13
International	2		2		—		4
Debt securities—Domestic government	3		—		—		3
	$	17	$	10	$	—	$	27



	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	15	$	—	$	15
Equity securities:
Domestic	52		111		—		163
International	53		53		—		106
Debt securities—Domestic government and corporate credit	68		70		—		138
Private equity funds	—		—		23		23
Alternative investments	—		—		28		28
	$	173	$	249	$	51	$	473
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	3		2		—		5
International	1		1		—		2
Debt securities—Domestic government	2		—		—		2
	$	6	$	10	$	—	$	16

An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 4, Fair Value of Financial Instruments. The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short term treasury bills, federal agency securities, certificates of deposit, and commercial paper. Money market funds held in the trusts are classified as Level 2 instruments as they are traded in an active market of similar securities but are not directly valued using quoted prices.

Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 securities based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 securities due to pricing inputs that are not directly or indirectly observable in the marketplace.

Debt securities—PGE invests in highly-liquid United States treasury and corporate credit mutual fund securities to support the investment objectives of the trusts. These securities are classified as Level 1 instruments due to the highly observable nature of pricing in an active market.

Fair values for Level 2 debt securities, including municipal debt and corporate credit securities, mortgage-backed securities and asset-backed securities are determined by evaluating pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation if applicable.

Private equity—PGE invests in a combination of primary and secondary fund-of-funds which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, venture capital, buyout and special situations. Private equity investments are classified as Level 3 securities due to fund valuation methodologies that utilize discounted cash flow, market comparable and limited secondary market pricing to develop estimates of fund valuation. PGE valuation of individual fund performance compares stated fund performance against published benchmarks.

Alternative investments—Investments in a portable alpha strategy are comprised of long positions in S&P 500 futures contracts and a hedge fund-of-funds comprised of diversified group, by sector and market capitalization of long only, short only and/or both long/short equity hedge funds. Valuation of hedge funds included within this vehicle is provided by fund managers using unobservable internally modeled inputs. PGE performs validation procedures of manager performance by comparing stated performance against published benchmarks. Alternative investments are classified as level 3 due to lack of observable market inputs and relative illiquidity of the fund.

Changes in the fair value of assets held by the pension plan classified as Level 3 in the fair value hierarchy presented in the table above were as follows for the years ended December 31, 2011 and 2010 (in millions):



	Private equity			Alternative assets		Total Level 3
Balance as of December 31, 2009	$	17		$	23	$	40
Purchases and sales, net	4			2		6
Realized gain on sales	1			—		1
Unrealized gain on assets	1			3		4
Balance as of December 31, 2010	23			28		51
Purchases	7			—		7
Realized loss on sales	(2		)	—		(2		)
Unrealized gain on assets	4			2		6
Balance as of December 31, 2011	$	32		$	30	$	62

The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and non-qualified benefit plans as of and for the years ended December 31, 2011 and 2010. Obligations related to the Other NQBP are not included in the following tables (dollars in millions):



	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2011			2010			2011			2010			2011			2010
Benefit obligation:
As of January 1	$	550		$	491		$	79		$	77		$	25		$	27
Service cost	12			11			2			2			—			—
Interest cost	29			28			4			4			1			1
Participants’ contributions	—			—			2			2			—			—
Actuarial loss (gain)	69			42			(5		)	1			3			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	634		$	550		$	75		$	79		$	27		$	25
Fair value of plan assets:
As of January 1	$	473		$	406		$	16		$	19		$	19		$	20
Actual return on plan assets	14			59			—			1			—			2
Company contributions	26			30			16			1			—			—
Participants’ contributions	—			—			2			2			—			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	487		$	473		$	27		$	16		$	17		$	19
Unfunded position as of December 31	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)
Accumulated benefit plan obligation as of December 31	$	566		$	503		N/A			N/A			$	27		$	25
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	17		$	19
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(147		)	(77		)	(48		)	(63		)	(25		)	(23		)
Net liability	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)



	Defined Benefit Pension Plan						Other Postretirement Benefits								Non-Qualified Benefit Plans
	2011			2010			2011				2010				2011			2010
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	97		$	22		$	(4	)		$	1			$	2		$	—
Amortization of net actuarial loss	(8		)	(3		)	(1		)		(1		)		(1		)	(1		)
Amortization of prior service cost	(1		)	(1		)	(1		)		(1		)		—			—
	$	88		$	18		$	(6	)		$	(1	)		$	1		$	(1	)
Amounts included in AOCL*:
Net actuarial loss	$	275		$	186		$	15			$	20			$	10		$	9
Prior service cost	1			2			4				5				—			—
	$	276		$	188		$	19			$	25			$	10		$	9
Assumptions used:
Discount rate used to calculate benefit obligation	5.00		%	5.47		%	3.76		%	-	4.02		%	-	5.00		%	5.47		%
							4.90		%		5.40		%
Weighted average rate of increase in future compensation levels	3.71		%	3.80		%	4.58		%		4.83		%		N/A			N/A
Long-term rate of return on plan assets	8.25		%	8.50		%	7.09		%		6.44		%		N/A			N/A


*	Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets.

Net periodic benefit cost consists of the following for the years ended December 31 (in millions):



	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2011			2010			2009			2011			2010			2009			2011		2010		2009
Service cost	$	12		$	11		$	11		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	29			28			31			4			4			4			1		1		2
Expected return on plan assets	(42		)	(39		)	(43		)	(1		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	1			1			1			1			1			1			—		—		—
Amortization of net actuarial loss	8			3			—			1			1			1			1		1		—
Net periodic benefit cost	$	8		$	4		$	—		$	7		$	7		$	7		$	2	$	2	$	2

PGE estimates that $20 million will be amortized from AOCL into net periodic benefit cost in 2012, consisting of a net actuarial loss of $17 million for pension benefits, $1 million for non-qualified benefits and $1 million for other postretirement benefits, and prior service cost of $1 million for other postretirement benefits.

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):



	Payments Due
	2012		2013		2014		2015		2016		2017 - 2021
Defined benefit pension plan	$	31	$	32	$	34	$	36	$	37	$	209
Other postretirement benefits	4		4		4		4		5		23
Non-qualified benefit plans	2		2		2		3		2		11
Total	$	37	$	38	$	40	$	43	$	44	$	243

All of the plans develop expected long-term rates of return for the major asset classes using long-term historical returns, with adjustments based on current levels and forecasts of inflation, interest rates, and economic growth. Also included are incremental rates of return provided by investment managers whose returns are expected to be greater than the markets in which they invest.

For measurement purposes, the assumed health care cost trend rates, which can affect amounts reported for the health care plans, were as follows:


•	For 2011, 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2012 through 2013, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019;


•	For 2010, 8% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2011 through 2013, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2019; and


•	For 2009, 7.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2010, and assumed to decrease 0.5% per year thereafter, reaching 5% in 2015.

A one percentage point increase or decrease in the above health care cost assumption would have no material impact on total service or interest cost, and would increase or decrease the postretirement benefit obligation by less than $1 million.

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees hired prior to February 1, 2009, the Company matches employee contributions up to 6% of the participating employee’s base pay. For eligible employees hired after January 31, 2009, and/or who are not otherwise covered by a defined benefit pension plan, PGE matches up to 5% of the participating employee’s base salary and, whether or not an employee contributes to the 401(k) Plan, the Company contributes 5% of the employee’s base salary.

For bargaining employees, who are subject to the International Brotherhood of Electrical Workers Local 125 agreements, the Company contributes a stated amount per compensable hour plus 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions of approximately $16 million, $15 million, and $14 million during the years ended December 31, 2011, 2010, and 2009.

- Definition

The entire disclosure for pension and other postretirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 518
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 264
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 03-2
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 30
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
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-Name FASB Staff Position (FSP)
-Number FAS106-2
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-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 7, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Implementation Guide (Q and A)
-Number FAS88
-Paragraph 63
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI http://asc.fasb.org/topic&trid=2235017

+ Details

Income Taxes

12 Months Ended

Dec. 31, 2011

Income Taxes Note [Abstract]

Income Taxes

INCOME TAXES

Income tax expense (benefit) consists of the following (in millions):



	Years Ended December 31,
	2011		2010			2009
Current:
Federal	$	2	$	(20	)	$	(46	)
State and local	—		—			—
	2		(20		)	(46		)
Deferred:
Federal	43		61			78
State and local	13		12			6
	56		73			84
Investment tax credit adjustments	—		—			(2		)
Income tax expense	$	58	$	53		$	36

The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows:



	Years Ended December 31,
	2011		2010		2009
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(12.7	)	(10.4	)	(8.3	)
State and local taxes, net of federal tax benefit	2.6		4.4		3.4
Flow through depreciation and cost basis differences	2.1		0.1		(1.6	)
Investment tax credit amortization	—		—		(1.5	)
Other	1.3		1.2		1.8
Effective tax rate	28.3	%	30.3	%	28.8	%

Deferred income tax assets and liabilities consist of the following (in millions):



	As of December 31,
	2011			2010
Deferred income tax assets:
Price risk management	$	145		$	72
Employee benefits	135			98
Tax credits, net of valuation allowance	56			40
Regulatory liabilities	22			37
Tax loss carryforwards	1			17
Total deferred income tax assets	359			264
Deferred income tax liabilities:
Depreciation and amortization	572			534
Regulatory assets	274			175
Other	9			4
Total deferred income tax liabilities	855			713
Deferred income tax liability, net	$	(496	)	$	(449	)
Classification of net deferred income taxes:
Current deferred income tax asset ⁽¹⁾	$	33		$	—
Current deferred income tax liability ⁽²⁾	—			(4		)
Noncurrent deferred income tax liability	(529		)	(445		)
	$	(496	)	$	(449	)


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


(2)	Included in Accrued expenses and other current liabilities in the consolidated balance sheets.

Certain reclassifications have been made to the 2010 deferred income tax assets and deferred income tax liabilities presented in the preceding table to conform with the 2011 presentation and include the following: (i) an increase in Depreciation and amortization and a decrease in Regulatory liabilities of $220 million related to asset retirement obligations; (ii) an increase in Price risk management and a decrease in Regulatory liabilities of $74 million related to fair value adjustments; (iii) an increase in Employee benefits and a decrease in Regulatory assets of $73 million related to actuarial adjustments; and (iv) an increase in Regulatory assets and a decrease in Other of $8 million related to reacquired long-term debt.

As of December 31, 2011, PGE had no federal loss carryforwards and state loss carryforwards of less than $1 million, which will expire at various dates from 2016 through 2031. In addition, PGE has federal and state tax credit carryforwards of $42 million and $14 million, respectively, which will expire at various dates from 2012 through 2031.

PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2011 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2010, PGE believed the benefit from state credit carryforwards expiring in 2011 would not be realized and, in recognition of this risk, the Company recorded a valuation allowance of $2 million on the deferred tax assets relating to these state credit carryforwards. During 2011, these state credit carryforwards expired unused. The net change in the valuation allowance for the years ended December 31, 2011 and 2010 were decreases of $2 million and $1 million, respectively.

As of December 31, 2010, the amount of the Company’s unrecognized tax benefit was $2 million, including interest, resulting from a gross increase in a position taken in a prior period. During the year ended December 31, 2010, the Company recognized $1 million in interest and no penalties. During the first quarter of 2011, the unrecognized tax benefit of $2 million was recognized as a result of filing for a federal tax accounting method change. As of December 31, 2011, PGE has no unrecognized tax benefits.

PGE files income tax returns in the U.S. federal jurisdiction, the states of Oregon and Montana, and certain local jurisdictions. The Internal Revenue Service (IRS) performed an examination of PGE’s income tax returns for 2007 and 2008 during 2010. This audit closed in the first quarter of 2011, with no material findings. In addition, the IRS commenced examination of the 2006, 2009, and 2010 income tax returns in the fourth quarter of 2011. The Company is not currently under examination by state or local tax authorities.

- Definition

The entire disclosure for income taxes. Disclosures may include net deferred tax liability or asset recognized in an enterprise's statement of financial position, net change during the year in the total valuation allowance, approximate tax effect of each type of temporary difference and carryforward that gives rise to a significant portion of deferred tax liabilities and deferred tax assets, utilization of a tax carryback, and tax uncertainties information.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 08
-Paragraph h
-Article 4

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 136, 172
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 109
-Paragraph 43, 44, 45, 46, 47, 48, 49
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32718-109319

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32639-109319

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(h))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32537-109319

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6907707&loc=d3e32559-109319

+ Details

Stock Purchase Plan	12 Months Ended
Stock Purchase Plan	Dec. 31, 2011
Employee Stock Purchase Plan Note [Abstract]
Stock Purchase Plan [Text Block]	STOCK PURCHASE PLANS Employee Stock Purchase Plan PGE has an employee stock purchase plan (ESPP), under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock (based on fair value on the purchase date) or 1,500 shares, whichever is less. There are two six-month offering periods each year, January 1 through June 30 and July 1 through December 31, during which eligible employees may purchase shares of PGE common stock at a price equal to 95% of the fair value of the stock on the purchase date, the last day of the offering period. As of December 31, 2011, there were 507,594 shares available for future issuance pursuant to the ESPP. Dividend Reinvestment and Direct Stock Purchase Plan On April 1, 2011, PGE’s Dividend Reinvestment and Direct Stock Purchase Plan (DRIP) became effective, under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2011, there were 2,496,842 shares available for future issuance pursuant to the DRIP.

Stock-based Compensation Expense

12 Months Ended

Dec. 31, 2010

Share-based Compensation [Abstract]

Stock-based Compensation Expense

STOCK-BASED COMPENSATION EXPENSE

Pursuant to the Portland General Electric Company 2006 Stock Incentive Plan (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units with time-based vesting conditions (Restricted Stock Units) and performance-based vesting conditions (Performance Stock Units) to non-employee directors, officers and certain key employees. Service requirements generally must be met for stock units to vest. For each grant, the number of Stock Units is determined by dividing the specified award amount for each grantee by the closing stock price on the date of grant. A total of 4,687,500 shares of common stock were registered for future issuance under the Plan, of which 3,931,204 shares remain available for future issuance as of December 31, 2011.

Restricted Stock Units vest in either equal installments over a one-year period on the last day of each calendar quarter, over a three-year period on each anniversary of the grant date, or at the end of a three-year period following the grant date.

Performance Stock Units vest if performance goals are met at the end of a three-year performance period; such goals include return on equity and regulated asset base growth measures. Vesting of Performance Stock Units is calculated by multiplying the number of units granted by a performance percentage determined by the Compensation and Human Resources Committee of PGE’s Board of Directors. The performance percentage is calculated based on the extent to which the performance goals are met. In accordance with the Plan, however, the committee may disregard or offset the effect of extraordinary, unusual or non-recurring items in determining results relative to these goals. Based on the attainment of the performance goals, the awards can range from zero to 150% of the grant.

Outstanding Restricted and Performance Stock Units provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. DERs represent an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vest on the same schedule as the stock units. The DERs are settled in cash (for grants to non-employee directors) or shares of PGE common stock valued either at the closing stock price on the vesting date (for Performance Stock Unit grants) or dividend payment date (for all other grants). The cash from the settlement of the DERs for non-employee directors may be deferred under the terms of the Portland General Electric Company 2006 Outside Directors’ Deferred Compensation Plan.

Restricted and Performance Stock Unit activity is summarized in the following table:



	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2008	360,382		25.04
Granted	243,574		14.95
Forfeited	(4,847	)	24.85
Vested	(176,846	)	23.60
Outstanding as of December 31, 2009	422,263		19.82
Granted	191,469		19.18
Forfeited	(45,081	)	23.45
Vested	(103,223	)	25.78
Outstanding as of December 31, 2010	465,428		17.88
Granted	152,657		23.84
Forfeited	(106,979	)	22.35
Vested	(19,702	)	23.34
Outstanding as of December 31, 2011	491,404		18.54

The number of vested Restricted and Performance Stock Units presented above exceed the number of shares issued for the vesting of restricted and performance stock units on the consolidated statements of equity because, upon vesting, the Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. The total value of Restricted and Performance Stock Units vested during the years ended December 31, 2011, 2010, and 2009 was $1 million, $3 million and $4 million, respectively. The weighted average fair value is measured based on the closing price of PGE common stock on the date of grant. For the years ended December 31, 2011, 2010, and 2009, PGE recorded $4 million, $2 million and $1 million, respectively, of stock-based compensation expense, which is included in Administrative and other expense in the consolidated statements of income. Such amounts differ from those reported in the consolidated statements of equity for Stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The net impact to equity from the income tax payments, partially offset by the issuance of DERs, resulted in a charge to equity of less than $1 million in 2011, 2010, and 2009, which is not included in Administrative and other expenses in the consolidated statements of income.

As of December 31, 2011, unrecognized stock-based compensation expense was $4 million, of which approximately $3 million and $1 million is expected to be expensed in 2012 and 2013, respectively. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the vesting of 121.8%, 117.9%, and 91.1% of awarded Performance Stock Units for 2011, 2010, and 2009, respectively, with an estimated 6% forfeiture rate. No stock-based compensation costs have been capitalized and the plan had no material impact on cash flows for the years ended December 31, 2011, 2010, or 2009.

- Definition

Tabular disclosure of components of a stock option or other award plan under which equity-based compensation is awarded to employees, typically comprised of the amount of unearned compensation (deferred compensation cost), compensation expense, and changes in the quantity and fair value of the shares (or other type of equity) granted, exercised, forfeited, and issued and outstanding pertaining to that plan. Disclosure may also include nature and general terms of such arrangements that existed during the period and potential effects of those arrangements on shareholders, effect of compensation cost arising from equity-based payment arrangements on the income statement, method of estimating the fair value of the goods or services received, or the fair value of the equity instruments granted, during the period, cash flow effects resulting from equity-based payment arrangements and, for registrants that accelerate vesting of out of the money share options, reasons for the decision to accelerate.

+ References + Details

Earnings Per Share

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHARE

Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Dilutive potential common shares consist of Restricted Stock Units and employee stock purchase plan shares. Unvested Performance Stock Units and related DERs are not included in the computation of dilutive securities because vesting of these instruments is dependent upon the attainment of required criteria over three-year performance periods. For additional information on Performance Stock Units and DERs, see Note 13, Stock-Based Compensation Expense.

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



	Years Ended December 31,
	2011		2010		2009
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	147	$	125	$	95
Denominator (in thousands):
Weighted average common shares outstanding—basic	75,333		75,275		72,790
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	17		16		62
Weighted average common shares outstanding—diluted	75,350		75,291		72,852

Earnings per share—basic and diluted	$	1.95	$	1.66	$	1.31

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 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.

Commitments and Guarantees

12 Months Ended

Dec. 31, 2011

Commitments and Guarantees Note [Abstract]

Commitments and Guarantees [Text Block]

COMMITMENTS AND GUARANTEES

Commitments

As of December 31, 2011, PGE’s future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):



	Payments Due
	2012		2013		2014		2015		2016		Thereafter		Total
Capital and other purchase commitments	$	58	$	18	$	10	$	10	$	6	$	73	$	175
Purchased power and fuel:
Electricity purchases	129		77		76		76		57		381		796
Capacity contracts	21		21		21		20		19		—		102
Public Utility Districts	7		8		8		8		7		30		68
Natural gas	49		22		22		20		12		11		136
Coal and transportation	25		19		9		—		—		—		53
Operating leases	9		10		9		10		10		196		244
Total	$	298	$	175	$	155	$	144	$	111	$	691	$	1,574

Capital and other purchase commitments—Certain commitments have been made for capital and other purchases for 2012 and beyond. Such commitments include those related to hydro licenses, upgrades to production, distribution and transmission facilities, decommissioning activities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges.

Electricity purchases and Capacity contracts—PGE has power purchase contracts with counterparties, which expire at varying dates through 2036, and power capacity contracts through 2016. As of December 31, 2011, PGE has power sale contracts with counterparties of approximately $13 million in 2012.

Public Utility Districts—PGE has long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. The Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the Public Utility Districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions):



	Revenue Bonds as of December 31, 2011		PGE Share			Contract Expiration	PGE Cost, including Debt Service
	Revenue Bonds as of December 31, 2011		Output		Capacity	Contract Expiration	2011		2010		2009
					(in MW)
Priest Rapids and Wanapum	$	917	8.8	%	176	2052	$	14	$	10	$	17
Wells	259		19.4		159	2018	10		7		8
Portland Hydro	11		100.0		36	2017	4		4		4

Under contracts with the public utility districts, PGE has acquired a percentage of the output (Allocation) of Priest Rapids and Wanapum and Wells. The contracts provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be allocated up to a cumulative maximum of 25% of the defaulting purchaser’s percentage Allocation. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax exempt status of any outstanding debt.

Natural gas—PGE has agreements for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. The Company also has a natural gas storage agreement, which expires in April 2017, for the purpose of fueling the Company’s Port Westward and Beaver generating plants.

Coal and transportation—PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman, which expire at various dates through 2014.

Operating leases—PGE has various operating leases associated with its headquarters and certain of its production, transmission, and support facilities. The majority of the future minimum operating lease payments presented in the table above consist of (i) the corporate headquarters lease, which expires in 2018, but includes renewal period options through 2043, and (ii) the Port of St. Helens land lease, where PGE’s Beaver and Port Westward generating plants operate, which expires in 2096. Rent expense was $9 million in 2011 and in 2010, and $7 million in 2009.

The future minimum operating lease payments presented is net of sublease income of: $3 million in 2012; $2 million in 2013, 2014, and 2015; and $1 million in 2016. Sublease income was $3 million in 2011, 2010, and 2009.

Guarantees

PGE entered into a sale transaction in 1985 in which it sold an undivided 15% interest in Boardman and a 10.714% undivided interest in the Pacific Northwest Intertie (Intertie) transmission line (jointly the Boardman Assets) to an unrelated third party (Purchaser). The Purchaser leased the Boardman Assets to a lessee (Lessee) unrelated to PGE or the Purchaser. Concurrently, PGE assigned to the Lessee certain agreements for the sale of power and transmission services from Boardman and the Intertie (P&T Agreements) to a regulated electric utility (Utility) unrelated to PGE, the Purchaser, or the Lessee. The P&T Agreements expire on December 31, 2013. The payments by the Utility under the P&T Agreements exceed the payments to be made by the Lessee to the Purchaser under the lease. In exchange for PGE undertaking certain obligations of the Lessee under the lease, the Lessee reassigned to PGE certain rights, including the excess payments, under the P&T Agreements. However, in the event that the Utility defaults on the payments it owes under the P&T Agreements, PGE may be required to pay the damages owed by the Lessee to the Purchaser under the lease. Assuming no recovery from the Utility and no reduction in damages from mitigating sales or leases related to the Boardman Assets and P&T Agreements, the maximum amount that would be owed by PGE in 2012 is approximately $74 million. Management believes that circumstances that could result in such amount, or any lesser amount, being owed by the Company are remote.

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 the Company’s historical experience and the evaluation of the specific indemnities. As of December 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 consolidated balance sheets with respect to these indemnities.

Variable Interest Entities

12 Months Ended

Dec. 31, 2010

Variable Interest Entities Note [Abstract]

Variable Interest Entities

VARIABLE INTEREST ENTITIES

PGE has determined that it is the primary beneficiary of three VIEs and, therefore, consolidates the VIEs within the Company’s 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. The Company is the Managing Member and a financial institution is the Investor Member in each of the Limited Liability Companies (LLCs), holding equity interests of less than 1% and more than 99%, respectively, in each entity. PGE has determined that its interests in these VIEs contain the obligation to absorb the variability of the entities that could potentially be significant to the VIEs, and the Company has the power to direct the activities that most significantly affect the entities’ economic performance.

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: (i) PGE has the experience 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; (ii) 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 (iii) based on projections prepared in accordance with the operating agreements, PGE expects to absorb a majority of the expected losses of the LLCs.

During 2010 and 2009, impairment losses of $4 million and $5 million, respectively, were recognized on the photovoltaic solar power facilities held by the LLCs and classified in Depreciation and amortization expense in PGE’s consolidated statements of income. Based on PGE’s intent to ultimately acquire 100% of the LLCs and the fact that the capitalized cost of the photovoltaic solar power facilities exceeded the undiscounted cash flows of the respective facility over its estimated useful life, impairment analyses were performed. The impairment losses were equal to the excess of the carrying amounts over the estimated fair values of the photovoltaic solar power facilities. Estimated fair values were determined using the discounted cash flow method, assuming a discount rate (after taxes) of approximately 7%, which is PGE’s allowed rate of return, and estimated useful lives ranging from 20 to 25 years. The new cost basis of the photovoltaic solar power facilities are amortized over their remaining estimated useful lives. The valuation technique used to measure fair value of the photovoltaic solar power facilities at the impairment date is considered Level 3 in the fair value hierarchy, as described in Note 4, Fair Value of Financial Instruments.

As noted above, PGE has consolidated the VIEs even though it has less than a 1% ownership interest in the LLCs. The participating members are allocated their proportionate share of the LLCs net losses based on the respective members’ ownership percent. Accordingly, the majority of the impairment losses are attributable to the noncontrolling interests through the Net losses attributable to noncontrolling interests in PGE’s consolidated statements of income for the years ended December 31, 2010 and 2009.

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



	As of 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.

Jointly-owned Plant

12 Months Ended

Dec. 31, 2010

Jointly-owned Plant Note [Abstract]

Jointly-owned Plant [Text Block]

JOINTLY-OWNED PLANT

PGE has interests in three jointly-owned generating facilities. Under the joint operating agreements, each participating owner is responsible for financing its share of construction, operating and leasing costs. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.

As of December 31, 2011, PGE had the following investments in jointly-owned plant (dollars in millions):



	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	65.00	%	1980			$	467	$	292	$	2
Colstrip	20.00		1986			507		326		2
Pelton/Round Butte	66.67		1958	/	1964	206		46		11
Total						$	1,180	$	664	$	15


*	Excludes asset retirement obligations and accumulated asset retirement removal costs.

Contingencies	12 Months Ended
Contingencies	Dec. 31, 2011
Contingencies Note [Abstract]
Contingencies [Text Block]	CONTINGENCIES PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which (i) the damages sought are indeterminate or the basis for the damages claimed is not clear, (ii) the proceedings are in the early stages, (iii) discovery is not complete, (iv) the matters involve novel or unsettled legal theories, (v) there are significant facts in dispute, (vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants), or (vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. Trojan Investment Recovery Regulatory Proceedings. In 1993, PGE closed Trojan and sought full recovery of, and a 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 return on, 87% of its remaining investment in Trojan. Numerous challenges and appeals 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. 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 entered into agreements to settle the litigation related to recovery of, and return on, its investment in Trojan. The Utility Reform Project (URP) did not participate in the settlement and filed a complaint with the OPUC challenging the settlement agreements. In 2002, the OPUC issued an order (2002 Order) denying all of the URP’s challenges. 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 in 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 in 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 2008 Order to the Oregon Court of Appeals. Oral arguments were made on February 3, 2012 and a decision by the Oregon Court of Appeals remains pending. Class Actions. In a separate legal proceeding, two lawsuits were filed in Marion County Circuit Court against PGE in 2003 on behalf of two classes of electric service customers. The class action 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 of Trojan. In 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. The Marion County Circuit Court subsequently abated the class actions in response to the ruling of the Oregon Supreme Court. Because the above matters involve unsettled legal theories and have a broad range of potential outcomes, management cannot estimate a range of potential loss. Management believes, however, that these matters will not have a material impact on the financial condition of the Company, but may have a material impact on the results of operations and cash flows in future reporting periods. Pacific Northwest Refund Proceeding In 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 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 the evidence 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. In October, 2011, the FERC issued an Order on Remand, establishing an evidentiary hearing to determine whether any seller had engaged in unlawful market activity in the Pacific Northwest spot markets during the December 25, 2000 through June 20, 2001 period by violating specific contracts or tariffs, and, if so, whether a direct connection existed between the alleged unlawful conduct and the rate charged under the applicable contract. FERC held that the Mobile-Sierra public interest standard governs challenges to the bilateral contracts at issue in this proceeding, and the strong presumption under Mobile-Sierra that the rates charged under each contract are just and reasonable would have to be specifically overcome before a refund could be ordered. FERC directed the presiding judge, if necessary, to determine a refund methodology and to calculate refunds, but held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Certain parties claiming refunds filed requests for rehearing of the Order on Remand, contesting, among other things, the applicable refund period reflected in the Order, the use of the Mobile-Sierra standard, any restraints in the Order on the type of evidence that could be introduced in the hearing, and the lack of market-wide remedy. The rehearing requests remain pending. In its October 2011 Order on Remand, the FERC held the hearing procedures in abeyance pending the results of settlement discussions, which it ordered be convened before a FERC settlement judge. The settlement proceedings are ongoing. 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 (including CERS) as to transactions in the Pacific Northwest during the settlement period, January 1, 2000 through June 20, 2001, but did not settle potential claims from other market participants relating to transactions in the Pacific Northwest. Management cannot predict whether the FERC will order refunds in the Pacific Northwest Refund proceeding, which contracts would be subject to refunds, or how such refunds, if any, would be calculated. Accordingly, management cannot estimate a range of potential loss. Management believes, however, that the outcome will not have a material impact on the financial condition of the Company, but may have a material 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 is not expected to issue the Record of Decision until 2014. 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. Accordingly, management cannot estimate a range of potential loss. Management believes, however, that the outcome will not have a material impact on the financial condition of the Company, but may have a material impact on PGE’s results of operations and cash flows in future reporting periods. EPA Investigation of Harbor Oil Harbor Oil, Inc. operated an oil reprocessing business on a site located in north Portland (Harbor Oil), until about 1999. Subsequently, other companies have continued to conduct operations on the site. Until 2003, PGE contracted with the operators of the site to provide used oil from the Company’s power plants and electrical distribution system to the operators for use in their reprocessing business. Other entities continue to utilize Harbor Oil for the reprocessing 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 2003, the EPA included the Harbor Oil site on the National Priority List as a federal Superfund site. PGE received a Notice from the EPA in 2005, in which the Company was named as one of fourteen PRPs with respect to Harbor Oil. In 2007, an AOC was signed by the EPA and six other parties, including PGE, to implement an RI/FS at Harbor Oil. In 2011, the final draft of the remedial investigation report was submitted to the EPA, which has yet to issue a response. Sufficient information is currently not available to determine the total cost of investigation and remediation of Harbor Oil or the liability of the PRPs, including PGE. Accordingly, management cannot estimate a range of potential loss. Management believes, however, that the outcome of this matter will not have a material impact on the financial condition of the Company, but may have a material impact on PGE’s results of operations and cash flows in future reporting periods. Revenue Bonds In 2008, PGE repurchased $5.8 million of Pollution Control Revenue Bonds Series 1996 (Bonds) issued through the Port of Morrow. In connection with the repurchase, PGE paid the $5.8 million repurchase price 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. PGE subsequently filed a claim for return of the Bonds from Lehman. In November 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 the outcome of this matter to have a material impact on the Company’s financial condition, but it may have a material impact on PGE’s results of operations and cash flows in a future interim reporting period. Other Matters PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims 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 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.

Basis of Presentation Basis of Presentation (Policies)	12 Months Ended
Basis of Presentation Basis of Presentation (Policies)	Dec. 31, 2011
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries and those variable interest entities (VIEs) where PGE has determined it is the primary beneficiary. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. Intercompany balances and transactions have been eliminated. For entities that are determined to meet the definition of a VIE and where the Company has determined it is the primary beneficiary, the VIE is consolidated and a noncontrolling interest is recognized for any third party interests. This has resulted in the Company consolidating entities in which it has less than a 50% equity interest. For further information, see Note 16, Variable Interest Entities.

- Definition

Disclosure of accounting policy regarding (1) the principles it follows in consolidating or combining the separate financial statements, including the principles followed in determining the inclusion or exclusion of subsidiaries or other entities in the consolidated or combined financial statements and (2) its treatment of interests (for example, common stock, a partnership interest or other means of exerting influence) in other entities, for example consolidation or use of the equity or cost methods of accounting. The accounting policy may also address the accounting treatment for intercompany accounts and transactions, noncontrolling interest, and the income statement treatment in consolidation for issuances of stock by a subsidiary.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 140
-Paragraph 46
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 2-6
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 14, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 5, 6, 16-19
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 18
-Paragraph 20
-Subparagraph a(2)
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 96-16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 97-2
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 3A
-Section 02, 03

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph k
-Article 1

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph c
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 45
-URI http://asc.fasb.org/section&trid=2197723

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
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-URI http://asc.fasb.org/subtopic&trid=2197480

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
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-Paragraph 2
-Subparagraph (SX 210.3A-02)
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Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
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-URI http://asc.fasb.org/subtopic&trid=2196966

Reference 18: http://www.xbrl.org/2003/role/presentationRef
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-Name Accounting Standards Codification
-Topic 323
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-Section 45
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6382870&loc=d3e33801-111570

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-URI http://asc.fasb.org/subtopic&trid=2197087

+ Details

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2011
Summary of Significant Accounting Policies [Abstract]
Income Tax Uncertainties, Policy [Policy Text Block]	Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return, or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheet.
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Retail revenue is billed monthly based on meter readings taken throughout the month. Unbilled revenue represents the revenue earned from the last meter read date through the last day of the month, which has not been billed as of the last day of the month. Unbilled revenue is calculated based on each month’s actual net retail system load, the number of days from the last meter read date through the last day of the month, and current retail customer prices. As a rate-regulated utility, there are situations in which PGE accrues revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization.
Asset Retirement Obligations, Policy [Policy Text Block]	An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. PGE recognizes those legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future removal expenditures is capitalized as an ARO on the consolidated balance sheets and revised periodically, with actual expenditures charged to the ARO as incurred. The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.
Marketable Securities, Policy [Policy Text Block]	All of PGE’s investments in marketable securities, included in the Non-qualified benefit plan trust and Nuclear decommissioning trust on the consolidated balance sheets, are classified as trading. Trading securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the Non-qualified benefit plan trust assets are included in Other income, net. Realized and unrealized gains and losses on the Nuclear decommissioning trust fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking. The cost of securities sold is based on the average cost method.
Plant Retirement and Abandonment, Policy [Policy Text Block]	The original cost of depreciable property units, net of any related salvage value, is charged to accumulated depreciation when property is retired and removed from service. Cost of removal expenditures are charged to AROs for assets that meet the definition of a legal obligation and to accumulated asset retirement removal costs, included in Regulatory liabilities, for assets without AROs.
depreciation lives [Policy Text Block]	Thermal production plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2050. Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives,
Inventory, Policy [Policy Text Block]	PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance and capital activities and fuel for use in generating plants. Fuel inventories include natural gas, oil, and coal. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.
Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block]	Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheet
Trade and Other Accounts Receivable, Policy [Policy Text Block]	Accounts receivable are recorded at invoiced amounts and do not bear interest when recorded. Late payment fees on balances in arrears are first assessed 16 business days after the due date. An inactive account balance is charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the final due date. Estimated provisions for uncollectible accounts receivable related to retail sales, charged to Administrative and other expense, are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection of customer accounts, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors. Provisions related to wholesale accounts receivable and unsettled positions, charged to Purchased power and fuel expense, are based on a periodic review and evaluation that includes counterparty non-performance risk and contractual rights of offset when applicable. Actual amounts written off are charged to the allowance for uncollectible accounts.
Cash and Cash Equivalents, Policy [Policy Text Block]	Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents,
Derivatives, Policy [Policy Text Block]	PGE engages in price risk management activities, utilizing financial instruments such as forward, swap, and option contracts for electricity, natural gas, oil and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities, unless they qualify for the normal purchases and normal sales exception. Changes in fair value are recognized in the statement of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load meet the requirements for treatment under the normal purchases and normal sales exception. Other activities consist of certain electricity forwards, options and swaps, certain natural gas forwards, options, and swaps, and forward contracts for acquiring Canadian dollars. Such activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net power costs for the Company’s retail customers. In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, PGE recognizes a realized gain or loss on the derivative instrument. Contracts that qualify for the normal purchases and normal sales exception are not required to be recorded at fair value. Unrealized gains and losses from contracts that qualify as cash flow hedges are recorded net in Other comprehensive income and contracts not designated as cash flow hedges are recorded net in Purchased power and fuel expense on the statements of income. Physical electricity sale and purchase transactions are recorded in Revenues and Purchased power and fuel expense upon settlement, respectively, while financial transactions are recorded on a net basis in Purchased power and fuel expense upon settlement. Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral with certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash deposits provided as collateral are classified as Margin deposits in the accompanying consolidated balance sheets
Property, Plant and Equipment, Policy [Policy Text Block]	Electric utility plant is capitalized at its original cost. Costs include direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at the Company’s generating plants charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining a FERC license for the Company’s hydroelectric projects are capitalized and amortized over the related license period.
Property, Plant and Equipment, Planned Major Maintenance Activities, Policy [Policy Text Block]	Periodic major maintenance inspections and overhauls at the Company’s generating plants charged to expense as incurred, subject to regulatory accounting as applicable.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes and is based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income.
Regulatory Depreciation and Amortization, Policy [Policy Text Block]	Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage.
Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block]	Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years.
Public Utilities, Policy [Policy Text Block]	the Company applies regulatory accounting, resulting in regulatory assets or regulatory liabilities. Regulatory assets represent (i) probable future revenue associated with certain costs that are expected to be recovered from customers through the ratemaking process, or (ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as prices are established by or subject to approval by independent third-party regulators; prices are designed to recover the specific enterprise’s cost of service; and in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the statement of income over the period in which it is included in prices. Circumstances that could result in the discontinuance of regulatory accounting include (i) increased competition that restricts the Company’s ability to establish prices to recover specific costs, and (ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. PGE periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate.
power cost [Policy Text Block]	PGE is subject to a power cost adjustment mechanism (PCAM) as approved by the OPUC. Pursuant to the PCAM, the Company can adjust future customer prices to reflect a portion of the difference between each year’s forecasted net variable power costs (NVPC) included in customer prices (baseline NVPC) and actual NVPC. PGE is subject to a portion of the business risk or benefit associated with the difference between actual NVPC and baseline NVPC by application of an asymmetrical “deadband.” If the difference between actual NVPC and baseline NVPC falls within the established deadband range, PGE absorbs the incremental cost or benefit, with the difference falling outside the lower and upper thresholds of the deadband range being shared 90/10 between customers and the Company, respectively. Any customer refund or collection is also subject to a regulated earnings test. A refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for that year being no less than 1% above the Company’s latest authorized ROE. A collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s last authorized ROE. PGE’s authorized ROE was 10% for 2011, 2010, and 2009. A final determination of any customer refund or collection is made by the OPUC through an annual public filing and review. PGE estimates and records amounts related to the PCAM on a quarterly basis during the year. If the projected difference between baseline and actual NVPC for the year exceeds the established deadband, and if forecasted earnings exceed the level required by the regulated earnings test, a regulatory liability is recorded for any future amount payable to retail customers, with offsetting amounts recorded to Purchased power and fuel expense. If the difference is below the lower end of the deadband, a regulatory asset is recorded for any future amount due from retail customers.
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. Gain contingencies are recognized when realized and are disclosed when material. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which (i) the damages sought are indeterminate or the basis for the damages claimed is not clear, (ii) the proceedings are in the early stages, (iii) discovery is not complete, (iv) the matters involve novel or unsettled legal theories, (v) there are significant facts in dispute, (vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants), or (vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position as of December 31, 2011 and 2010. Revenue Recognition Re The assets of the pension plan are held in a trust and are comprised of equity, debt, and alternative asset investment vehicles, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31.
Revenue Recognition, Policy [Policy Text Block]	Revenues are recognized as electricity is delivered to customers and include amounts for any services provided. The prices charged to customers are subject to federal (FERC), and state (OPUC) regulation.
franchise tax [Policy Text Block]	Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes
Share-based Compensation, Option and Incentive Plans Policy [Policy Text Block]	The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite service period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.
Income Tax, Policy [Policy Text Block]	Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance is established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. As a rate-regulated enterprise, changes in deferred tax assets and liabilities that are related to certain property are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability.
interest and penalties related to income taxes [Policy Text Block]	PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Balance Sheet Components Balance Sheet Components (Policies)	12 Months Ended
	Dec. 31, 2011
Balance Sheet Components [Abstract]
Preliminary Engineering [Policy Text Block]	The Company incurs preliminary engineering costs related to potential future capital projects, which are capitalized in Other noncurrent assets in the consolidated balance sheets. Preliminary engineering costs consist of expenditures for preliminary surveys, plans, and investigations made for the purpose of determining the feasibility of utility projects being considered. Once the project is approved for construction, such costs are reclassified to Electric utility plant. If the project is abandoned, such costs are expensed to Production and distribution expense 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.

Fair Value of FInancial Instruments Fair Value of Financial Instruments (Policies)	12 Months Ended
	Dec. 31, 2011
Fair Value of Financial Instruments [Abstract]
Transfers in and out of Level 3 [Policy Text Block]	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.
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]	Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s consolidated balance sheets and allocated to securities that are exposed to interest rate, credit and market volatility risks. These assets are classified within Level 1, 2 or 3 based on the following factors: Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. Money market funds held in the Nuclear decommissioning trust are classified as Level 2 in the fair value hierarchy as the securities are traded in active markets of similar securities but are not directly valued using quoted market prices. Debt securities—PGE invests in highly-liquid United States treasury securities to support the investment objectives of the trusts. These securities are classified as Level 1 in the fair value hierarchy due to the highly observable nature of the pricing in an active market. Fair values for municipal debt and corporate credit securities are classified as Level 2 as prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation as applicable. Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 in the fair value hierarchy as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange (NYSE), both American stock exchanges. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 in the fair value hierarchy as pricing inputs may not be directly observable in the marketplace. Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign exchange rate risk, mitigate the effects of market fluctuations, and manage volatility in net power costs for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, Price Risk Management. For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as quoted forward prices for commodities and interest rates. 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 over-the-counter forwards and swaps. Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer term over-the-counter forward and swap derivatives. Commodity option contracts whose fair value is derived using standardized valuation techniques, such as Black-Scholes, are also classified as Level 3. Inputs into the valuation of commodity option contracts include forward commodity pricing, forward interest rates, and historic volatilities and correlations.
Fair Value of Financial Instruments, Policy [Policy Text Block]	PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2011 and 2010, and then classified based on a fair value hierarchy. The fair value hierarchy is used to prioritize the inputs to the valuation techniques used to measure fair value. These three broad levels and application to the Company are discussed below. Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Level 2—Pricing inputs include those that are directly or indirectly observable in the marketplace as of the reporting date. Level 3—Pricing inputs include significant inputs which are unobservable for the asset or liability. 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. PGE recognizes any transfers between levels in the fair value hierarchy as of the end of the reporting period. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.
Debt, Policy [Policy Text Block]	Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. 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.

Price Risk Management Price Risk Management (Policies)	12 Months Ended
Price Risk Management Price Risk Management (Policies)	Dec. 31, 2011
Price Risk Management [Abstract]
Gross Reporting of Positive and Negative Exposures Related to Derivative Instruments [Policy Text Block]	PGE has elected to report gross on the balance sheet the positive and negative exposures resulting from derivative instruments entered into with counterparties where a master netting arrangement exists.

Regulatory Assets and Liabilities Regulatory Assets and Liabilities (Policies)	12 Months Ended
	Dec. 31, 2011
Regulatory Assets and Liabilities [Abstract]
Description of Impairment to Carrying Amount of Regulatory Assets	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">During the fourth quarter of 2011, PGE received an order from the OPUC on its Annual Update Tariff for 2012 net variable power costs (NVPC). Pursuant to the order, the OPUC reduced the Company’s 2012 NVPC forecast by approximately </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$3 million</font><font style="font-family:inherit;font-size:11pt;">, which is reflected as a reduction to the regulatory asset for price risk management as of December 31, 2011.</font></div></div>
Refund Period Not Yet Determined for REgulatory Liabilities, PCAM and Pollution Control Tax Credits	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;">Refund period not yet determined</font></div></div>
Remaining Recovery Period of Regulatory Asset, Pension and Postretirement Plans, For Which No Return on Investment During Recovery is Provided	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;">Recovery expected over the average service life of employees</font></div></div>
Remaining Refund Period of Regulatory Liabilities, Asset Removal Costs and Retirement Obligations	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:10pt;"><font style="font-family:inherit;font-size:10pt;">Recovery expected over the estimated lives of the assets</font></div></div>

Asset Retirement Obilgations Asset Retirement Obligations (Policies)	12 Months Ended
	Dec. 31, 2011
NOTE 7: ASSET RETIREMENT OBLIGATIONS [Abstract]
Asset Retirement Obligations, Policy [Policy Text Block]	An ARO is recognized in the period in which it is incurred if a reasonable estimate of fair value can be made. PGE recognizes those legal obligations related to dismantlement and restoration costs associated with the future retirement of tangible long-lived assets. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and a market-risk premium are not available. The present value of estimated future removal expenditures is capitalized as an ARO on the consolidated balance sheets and revised periodically, with actual expenditures charged to the ARO as incurred. The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, which is included in Depreciation and amortization in the consolidated statements of income. Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.

- Definition

Disclosure of accounting policy for determining amounts to accrue and charge against earnings so as to satisfy legal obligations associated with the retirement (through sale, abandonment, recycling, or disposal in some other manner) of a tangible long-lived asset that result from the acquisition, construction, or development and (or) the normal operation of a long-lived asset. This accounting policy disclosure excludes obligations arising 1) in connection with leased property, whether imposed by a lease agreement or by a party other than the lessor, that meet the definition of either minimum lease payments or contingent rentals; 2) solely from a plan to sell or otherwise dispose of a long-lived asset and 3) from certain environmental remediation liabilities.

+ References + Details

Employee Benefits Employee Benefits (Policies)	12 Months Ended
Employee Benefits Employee Benefits (Policies)	Dec. 31, 2011
Employee Benefits [Abstract]
pension and other postretirement benefits valuation methodology [Policy Text Block]	The following methods are used in valuation of each asset class of investments held in the pension and other postretirement benefit plan trusts. Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short term treasury bills, federal agency securities, certificates of deposit, and commercial paper. Money market funds held in the trusts are classified as Level 2 instruments as they are traded in an active market of similar securities but are not directly valued using quoted prices. Equity securities—Equity mutual fund and common stock securities are primarily classified as Level 1 securities based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Certain mutual fund assets included in commingled trusts or separately managed accounts are classified as Level 2 securities due to pricing inputs that are not directly or indirectly observable in the marketplace. Debt securities—PGE invests in highly-liquid United States treasury and corporate credit mutual fund securities to support the investment objectives of the trusts. These securities are classified as Level 1 instruments due to the highly observable nature of pricing in an active market. Fair values for Level 2 debt securities, including municipal debt and corporate credit securities, mortgage-backed securities and asset-backed securities are determined by evaluating pricing data, such as broker quotes, for similar securities adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation if applicable. Private equity—PGE invests in a combination of primary and secondary fund-of-funds which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, venture capital, buyout and special situations. Private equity investments are classified as Level 3 securities due to fund valuation methodologies that utilize discounted cash flow, market comparable and limited secondary market pricing to develop estimates of fund valuation. PGE valuation of individual fund performance compares stated fund performance against published benchmarks. Alternative investments—Investments in a portable alpha strategy are comprised of long positions in S&P 500 futures contracts and a hedge fund-of-funds comprised of diversified group, by sector and market capitalization of long only, short only and/or both long/short equity hedge funds. Valuation of hedge funds included within this vehicle is provided by fund managers using unobservable internally modeled inputs. PGE performs validation procedures of manager performance by comparing stated performance against published benchmarks. Alternative investments are classified as level 3 due to lack of observable market inputs and relative illiquidity of the fund.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position as of December 31, 2011 and 2010. Revenue Recognition Re The assets of the pension plan are held in a trust and are comprised of equity, debt, and alternative asset investment vehicles, all of which are recorded at fair value. Pension plan calculations include several assumptions which are reviewed annually and are updated as appropriate, with the measurement date of December 31.
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]	The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, common stocks, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions which are reviewed annually with PGE’s consulting actuaries and trust investment consultants and updated as appropriate, with measurement dates of December 31.
Non-qualified benefit [Policy Text Block]	Non-Qualified Benefit Plans—The Non-Qualified Benefit Plans (NQBP) in the following tables include obligations for a Supplemental Executive Retirement Plan (SERP), and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also include pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in a non-qualified benefit plan trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. These trust assets are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bond, and equity mutual funds, are classified as trading and recorded at fair value. The measurement date for the non-qualified benefit plans is December 31. Other NQBP—In addition to the non-qualified benefit plans discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. These unfunded plans include the MDCP and the Outside Directors’ Deferred Compensation Plan. The Company also provides two retired employees with death benefits through a split dollar life insurance policy which pays a fixed amount to the beneficiary and for which the Company has a security interest for the amount of premiums paid. PGE holds investments in a non-qualified benefit plan trust which are intended to be a funding source for these plans.

- Definition

Disclosure of accounting policy for plans, other than pension plans, that provide postretirement benefits (including both defined benefit and defined contribution plans). This accounting policy may address (1) the types of plans sponsored by the entity, and the benefits provided by each plan (2) groups that participate in (or are covered by) each plan (3) how plan assets, liabilities and expenses are measured, including the use of any actuaries and (4) significant assumptions used by the entity to value plan assets and liabilities and how such assumptions are derived.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 106
-Paragraph 19, 20, 21, 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 9, 11, 12, 13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 5, 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 70
-URI http://asc.fasb.org/subtopic&trid=2235116

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-URI http://asc.fasb.org/subtopic&trid=2235172

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 80
-URI http://asc.fasb.org/subtopic&trid=2235144

+ Details

- Definition

Disclosure of accounting policy for pension plans. This accounting policy may address (1) the types of plans sponsored by the entity (2) groups that participate in (or are covered by) each plan (3) how plan assets, liabilities and expenses are measured, including the use of any actuaries and (4) significant assumptions used by the entity to value plan assets and liabilities and how such assumptions are derived.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7, 9, 11, 12, 13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 5, 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 87
-Paragraph 15-19, 63, 64
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph h
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph q
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 8
-Subparagraph m
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 70
-URI http://asc.fasb.org/subtopic&trid=2235116

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 80
-URI http://asc.fasb.org/subtopic&trid=2235144

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 30
-URI http://asc.fasb.org/subtopic&trid=2235074

+ Details

Income Taxes Income Taxes (Policies)	12 Months Ended
Income Taxes Income Taxes (Policies)	Dec. 31, 2011	Dec. 31, 2010
Income Taxes [Abstract]
Valuation Allowance, Commentary	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2011 will be realized; accordingly, </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">no</font><font style="font-family:inherit;font-size:11pt;"> valuation allowance has been recorded.</font></div></div>	<div style="font-family:Times New Roman;font-size:10pt;"><div style="line-height:120%;font-size:11pt;"><font style="font-family:inherit;font-size:11pt;">As of December 31, 2010, PGE believed the benefit from state credit carryforwards expiring in 2011 would not be realized and, in recognition of this risk, the Company recorded a valuation allowance of </font><font style="font-family:inherit;font-size:11pt;color:#000000;text-decoration:none;">$2 million</font><font style="font-family:inherit;font-size:11pt;"> on the deferred tax assets relating to these state credit carryforwards.</font></div></div>

Earnings Per Share Earnings Per Share (Policies)	12 Months Ended
Earnings Per Share Earnings Per Share (Policies)	Dec. 31, 2011
Earnings Per Share [Abstract]
Earnings Per Share, Policy [Policy Text Block]	Basic earnings per share is computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share is computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Dilutive potential common shares consist of Restricted Stock Units and employee stock purchase plan shares. Unvested Performance Stock Units and related DERs are not included in the computation of dilutive securities because vesting of these instruments is dependent upon the attainment of required criteria over three-year performance periods.

- Definition

Disclosure of accounting policy for computing basic and diluted earnings or loss per share for each class of common stock and participating security. Addresses all significant policy factors, including any antidilutive items that have been excluded from the computation and takes into account stock dividends, splits and reverse splits that occur after the balance sheet date of the latest reporting period but before the issuance of the financial statements.

+ References + Details

Commitments and Guarantees Commitments and Guarantees (Policies)	12 Months Ended
	Dec. 31, 2011
Commitments and Guarantees [Abstract]
Minimum Guarantees, Policy [Policy Text Block]	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 the Company’s historical experience and the evaluation of the specific indemnities.

Contingencies Contingencies (Policies)	12 Months Ended
Contingencies Contingencies (Policies)	Dec. 31, 2011
Contingencies [Abstract]
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. Legal costs incurred in connection with loss contingencies are expensed as incurred. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, disclosure of the loss contingency includes a statement to that effect and the reasons. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. Gain contingencies are recognized when realized and are disclosed when material. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies are accrued and disclosed when it is probable that an asset has been impaired or a liability incurred as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that an asset has been impaired or a liability incurred. If a probable or reasonably possible loss cannot be reasonably estimated, then the Company (i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate, or (ii) discloses that an estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in the subsequent reporting period. The Company evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which (i) the damages sought are indeterminate or the basis for the damages claimed is not clear, (ii) the proceedings are in the early stages, (iii) discovery is not complete, (iv) the matters involve novel or unsettled legal theories, (v) there are significant facts in dispute, (vi) there are a large number of parties (including where it is uncertain how liability, if any, will be shared among multiple defendants), or (vii) there is a wide range of potential outcomes. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

- Definition

Disclosure of accounting policy for commitments and contingencies, which may include policies for recognizing and measuring loss and gain contingencies.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Principles Board Opinion (APB)
-Number 22
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Audit and Accounting Guide (AAG)
-Number AAG-HCO
-Chapter 8
-Paragraph 12, 13
-IssueDate 2006-05-01
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 3
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6367646&loc=d3e18780-107790

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 954
-SubTopic 450
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6491354&loc=d3e6049-115624

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-Section 50
-Paragraph 8
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6398077&loc=d3e12565-110249

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 954
-SubTopic 450
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6491354&loc=d3e6052-115624

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 460
-SubTopic 10
-URI http://asc.fasb.org/subtopic&trid=2155897

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 9
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 10
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 11
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 12
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 45
-Paragraph 14
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Technical Bulletin (FTB)
-Paragraph 3
-Number 90-1
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name FASB Technical Bulletin (FTB)
-Number 90-1
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name FASB Technical Bulletin (FTB)
-Number 90-1
-Paragraph 5
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 24
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 25
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-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 5
-Paragraph 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2011

Summary of Significant Accounting Policies [Abstract]

Estimated average service lives [Table Text Block]

Depreciation is provided on the Company’s other classes of plant in service over their estimated average service lives, which are as follows (in years):



Production, excluding thermal:
Hydro	86
Wind	27
Transmission	53
Distribution	40
General	14

Balance Sheet Components Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2011

Balance Sheet Components [Abstract]

Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

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



	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	5		$	5		$	4
Increase in provision	11			7			9
Amounts written off, less recoveries	(10		)	(7		)	(8		)
Balance as of end of year	$	6		$	5		$	5

Investments held in trust [Table Text Block]

The trusts are comprised of the following investments as of December 31 (in millions):



	Nuclear Decommissioning Trust				Non-Qualified Benefit Plan Trust
	2011		2010		2011		2010
Cash equivalents	$	14	$	13	$	—	$	—
Marketable securities, at fair value:
Equity securities	—		—		10		19
Debt securities	23		21		3		2
Insurance contracts, at cash surrender value	—		—		23		23
	$	37	$	34	$	36	$	44

Schedule of Other Assets and Other Liabilities [Table Text Block]

Other current assets and Accrued expenses and other current liabilities consist of the following (in millions):



	As of December 31,
	2011		2010
Other current assets:
Current deferred income tax asset	$	33	$	—
Assets from price risk management activities	19		13
Income taxes receivable	12		22
Other	34		32
	$	98	$	67

Accrued expenses and other current liabilities:
Accrued employee compensation and benefits	$	44	$	36
Accrued interest payable	24		26
Dividends payable	21		20
Other	62		63
	$	151	$	145

Fair Value of FInancial Instruments Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2011

Fair Value of Financial Instruments [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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 December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust ⁽¹⁾:
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		11		—		11
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	7		2		—		9
International	1		—		—		1
Debt securities - domestic government	3		—		—		3
Assets from price risk management activities ^{(1) (3)}:
Electricity	—		2		—		2
Natural gas	—		17		—		17
	$	14	$	55	$	—	$	69
Liabilities - Liabilities from price risk management activities ^{(1) (3)}:
Electricity	$	—	$	108	$	29	$	137
Natural gas	—		201		50		251
	$	—	$	309	$	79	$	388


(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 5, 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:
Domestic government	3		9		—		12
Corporate credit	—		9		—		9
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	16		—		—		16
International	2		1		—		3
Debt securities - domestic government	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 5, Price Risk Management.

The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions):



	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	3	$	—	$	3
Equity securities:
Domestic	151		12		—		163
International	54		51		—		105
Debt securities:
Domestic government and corporate credit	—		78		—		78
Corporate credit	76		—		—		76
Private equity funds	—		—		32		32
Alternative investments	—		—		30		30
	$	281	$	144	$	62	$	487
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	12		1		—		13
International	2		2		—		4
Debt securities—Domestic government	3		—		—		3
	$	17	$	10	$	—	$	27



	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	15	$	—	$	15
Equity securities:
Domestic	52		111		—		163
International	53		53		—		106
Debt securities—Domestic government and corporate credit	68		70		—		138
Private equity funds	—		—		23		23
Alternative investments	—		—		28		28
	$	173	$	249	$	51	$	473
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	3		2		—		5
International	1		1		—		2
Debt securities—Domestic government	2		—		—		2
	$	6	$	10	$	—	$	16

Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]



Net liabilities from price risk management activities as of December 31, 2010	$	120
Net realized and unrealized losses ⁽¹⁾	86
Purchases	3
Settlements	(1		)
Net transfers out of Level 3 to Level 2	(129		)
Net liabilities from price risk management activities as of December 31, 2011	$	79

Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	88


(1)	Contains nominal amounts of realized losses, net.

The comparable information contained in the preceding table was as follows for the years ended December 31 (in millions):



	2010			2009
Net liabilities from price risk management activities as of beginning of year	$	154		$	123
Net realized and unrealized losses ⁽¹⁾	65			47
Purchases, issuances, and settlements, net	27			—
Net transfers out of Level 3 to Level 2	(126		)	(16		)
Net liabilities from price risk management activities as of end of year	$	120		$	154

Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	95		$	49


(1)	Contains nominal amounts of realized losses, net.

- Definition

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income, and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issuances, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References + Details

Price Risk Management Price Risk Management (Tables)

12 Months Ended

Dec. 31, 2011

Price Risk Management [Abstract]

Schedule of Price Risk Derivatives [Table Text Block]



	As of December 31,
	2011			2010
Commodity contracts:
Electricity	13		MWh	9		MWh
Natural gas	79		Decatherms	93		Decatherms
Foreign currency exchange	$	6	Canadian	$	7	Canadian

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]

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



	As of December 31,
	2011			2010
Current assets:
Commodity contracts:
Electricity	$	2		$	4
Natural gas	17			9
Total current derivative assets	19		⁽¹⁾	13		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Electricity	—			1
Natural gas	—			2
Total noncurrent derivative assets	—			3		⁽²⁾
Total derivative assets not designated as hedging instruments	$	19		$	16
Total derivative assets	$	19		$	16
Current liabilities:
Commodity contracts:
Electricity	$	66		$	77
Natural gas	150			111
Total current derivative liabilities	216			188
Noncurrent liabilities:
Commodity contracts:
Electricity	71			42
Natural gas	101			146
Total noncurrent derivative liabilities	172			188
Total derivative liabilities not designated as hedging instruments	$	388		$	376
Total derivative liabilities	$	388		$	376


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


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

Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]



	Years Ended December 31,
	2011		2010		2009
Commodity contracts:
Electricity	$	117	$	127	$	79
Natural Gas	98		192		101

Schedule of Notional Amounts of Outstanding Derivative Positions [Table Text Block]



	2012		2013		2014		2015		Total
Commodity contracts:
Electricity	$	64	$	42	$	21	$	8	$	135
Natural gas	132		72		24		6		234
Net unrealized loss	$	196	$	114	$	45	$	14	$	369

Schedule of Concentration of Risk, by Counterparty [Table Text Block]

Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:



	As of December 31,
	2011		2010
Assets from price risk management activities:
Counterparty A	19	%	1	%
Counterparty B	16		1
Counterparty C	13		5
Counterparty D	7		22
Counterparty E	7		23
Counterparty F	—		11
Counterparty G	—		10
	62	%	73	%
Liabilities from price risk management activities:
Counterparty E	23	%	24	%
Counterparty H	10		4
Counterparty I	7		12
	40	%	40	%

Regulatory Assets and Liabilities Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2011

Regulatory Assets [Line Items]

Schedule of Regulatory Assets and Liabilities [Table Text Block]

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



		Weighted Average Remaining Life ⁽¹⁾	As of December 31,
			2011				2010
			Current		Noncurrent		Current		Noncurrent
Regulatory assets:
	Price risk management ⁽²⁾	2 years	$	194	$	172	$	175	$	185
	Pension and other postretirement plans ⁽²⁾	⁽³⁾	—		295		—		213
	Deferred income taxes ⁽²⁾	⁽⁴⁾	—		87		—		95
	Deferred broker settlements ⁽²⁾	1 year	11		—		24		—
	Renewable energy deferral	1 year	1		—		22		—
	Debt reacquisition costs ⁽²⁾	7 years	—		28		—		23
	Other ⁽⁵⁾	Various	10		12		—		28
	Total regulatory assets		$	216	$	594	$	221	$	544
Regulatory liabilities:
	Asset retirement removal costs ⁽⁶⁾	⁽⁴⁾	$	—	$	637	$	—	$	588
	Asset retirement obligations ⁽⁶⁾	⁽⁴⁾	—		36		—		33
	Power cost adjustment mechanism	⁽⁷⁾	—		10		—		—
	Trojan ISFSI pollution control tax credits	⁽⁷⁾	—		7		18		4
	Other	Various	6		30		7		32
	Total regulatory liabilities		$	6	$	720	$	25	$	657


(1)	As of December 31, 2011.


(2)	Does not include a return on investment.


(3)	Recovery expected over the average service life of employees. For additional information, see Note 2, Summary of Significant Accounting Policies.


(4)	Recovery expected over the estimated lives of the assets.


(5)	Of the total other unamortized regulatory asset balances, a return is recorded on $21 million and $26 million as of December 31, 2011 and 2010, respectively.


(6)	Included in rate base for ratemaking purposes.


(7)	Refund period not yet determined.

Asset Retirement Obilgations Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2011

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

AROs, which are included in Other noncurrent liabilities in the consolidated balance sheets, consist of the following (in millions):



	As of December 31,
	2011		2010
Trojan decommissioning activities	$	37	$	38
Utility plant	38		16
Non-utility property	12		10
Asset retirement obligations	$	87	$	64

Schedule of Change in Asset Retirement Obligation [Table Text Block]

The following is a summary of the changes in the Company’s AROs (in millions):



	Years Ended December 31,
	2011			2010			2009
Balance as of beginning of year	$	64		$	63		$	58
Liabilities incurred	1			1			—
Liabilities settled	(4		)	(3		)	(4		)
Accretion expense	4			4			4
Revisions in estimated cash flows	22			(1		)	5
Balance as of end of year	$	87		$	64		$	63

Revolving Credit Facilities Revolving Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2011

Revolving Credit Facilities [Abstract]

Schedule of Short-term Debt [Table Text Block]

Short-term borrowings under these credit facilities and related interest rates were as follows (dollars in millions):



	Years Ended December 31,
	2011			2010			2009
Average daily amount of short-term debt outstanding	$	2		$	9		$	28
Weighted daily average interest rate *	0.4		%	0.4		%	1.3		%
Maximum amount outstanding during the year	$	44		$	51		$	205


*	Excludes the effect of commitment fees, facility fees and other financing fees.

Long-term Debt Long term debt (Tables)

12 Months Ended

Dec. 31, 2011

Long-term Debt, Unclassified [Abstract]

Schedule of Long-term Debt Instruments [Table Text Block]

Long-term debt consists of the following (in millions):



	As of December 31,
	2011			2010
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.83% in 2011 and 5.85% in 2010, due at various dates through 2040	$	1,615		$	1,678
Pollution Control Revenue Bonds:
Port of Morrow, Oregon, 5% rate, due 2033	23			23
City of Forsyth, Montana, 5% rate, due 2033	119			119
Port of St. Helens, Oregon, 5.25% rate, due in 2014	—			10
Total Pollution Control Revenue Bonds	142			152
Pollution Control Revenue Bonds owned by PGE	(21		)	(21		)
Unamortized debt discount	(1		)	(1		)
Total long-term debt	1,735			1,808
Less: current portion of long-term debt	(100		)	(10		)
Long-term debt, net of current portion	$	1,635		$	1,798

Schedule of Maturities of Long-term Debt [Table Text Block]

As of December 31, 2011, the future minimum principal payments on long-term debt are as follows (in millions):



Years ending December 31:
2012	$	100
2013	100
2014	—
2015	70
2016	67
Thereafter	1,398
	$	1,735

- Definition

Tabular disclosure of long-debt instruments or arrangements, including identification, terms, features, collateral requirements and other information necessary to a fair presentation. These are debt arrangements that originally required repayment more than twelve months after issuance or greater than the normal operating cycle of the entity, if longer.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 02
-Paragraph 22
-Article 5

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28551-108399

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=6451184&loc=d3e28541-108399

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21475-112644

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21538-112644

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21521-112644

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=6584090&loc=d3e28878-108400

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6479336&loc=d3e64711-112823

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(e),(f))
-URI http://asc.fasb.org/extlink&oid=6881521&loc=d3e23780-122690

+ Details

Employee Benefits Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2011

Employee Benefits [Abstract]

Assets and Liabilities associated with Non Qualified Benefit Plans [Table Text Block]

Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions):



	2011						2010
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust	$	17	$	19	$	36	$	19	$	25	$	44
Non-qualified benefit plan liabilities *	25		76		101		24		73		97


*	For the NQBP, excludes the current portion of $2 million in 2011 and 2010, which is classified in Other current liabilities in the consolidated balance sheets.

Schedule of Allocation of Plan Assets [Table Text Block]

The asset allocations for the plans, and the target allocation, are as follows:



	As of December 31,
	2011				2010
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	68	%	67	%	68	%	67	%
Debt securities	32		33		32		33
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	61	%	72	%	46	%	47	%
Debt securities	39		28		54		53
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	30	%	23	%	42	%	42	%
Debt securities	7		14		5		7
Insurance contracts	63		63		53		51
Total	100	%	100	%	100	%	100	%

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]

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 December 31, 2011
	Level 1		Level 2		Level 3		Total
Assets:
Nuclear decommissioning trust ⁽¹⁾:
Money market funds	$	—	$	14	$	—	$	14
Debt securities:
Domestic government	3		9		—		12
Corporate credit	—		11		—		11
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	7		2		—		9
International	1		—		—		1
Debt securities - domestic government	3		—		—		3
Assets from price risk management activities ^{(1) (3)}:
Electricity	—		2		—		2
Natural gas	—		17		—		17
	$	14	$	55	$	—	$	69
Liabilities - Liabilities from price risk management activities ^{(1) (3)}:
Electricity	$	—	$	108	$	29	$	137
Natural gas	—		201		50		251
	$	—	$	309	$	79	$	388


(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 5, 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:
Domestic government	3		9		—		12
Corporate credit	—		9		—		9
Non-qualified benefit plan trust ⁽²⁾:
Equity securities:
Domestic	16		—		—		16
International	2		1		—		3
Debt securities - domestic government	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 5, Price Risk Management.

The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions):



	As of December 31, 2011
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	3	$	—	$	3
Equity securities:
Domestic	151		12		—		163
International	54		51		—		105
Debt securities:
Domestic government and corporate credit	—		78		—		78
Corporate credit	76		—		—		76
Private equity funds	—		—		32		32
Alternative investments	—		—		30		30
	$	281	$	144	$	62	$	487
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	12		1		—		13
International	2		2		—		4
Debt securities—Domestic government	3		—		—		3
	$	17	$	10	$	—	$	27



	As of December 31, 2010
	Level 1		Level 2		Level 3		Total
Defined Benefit Pension Plan assets:
Money market funds	$	—	$	15	$	—	$	15
Equity securities:
Domestic	52		111		—		163
International	53		53		—		106
Debt securities—Domestic government and corporate credit	68		70		—		138
Private equity funds	—		—		23		23
Alternative investments	—		—		28		28
	$	173	$	249	$	51	$	473
Other Postretirement Benefit Plans assets:
Money market funds	$	—	$	7	$	—	$	7
Equity securities:
Domestic	3		2		—		5
International	1		1		—		2
Debt securities—Domestic government	2		—		—		2
	$	6	$	10	$	—	$	16

Schedule of Changes in Fair Value of Plan Assets [Table Text Block]



	Private equity			Alternative assets		Total Level 3
Balance as of December 31, 2009	$	17		$	23	$	40
Purchases and sales, net	4			2		6
Realized gain on sales	1			—		1
Unrealized gain on assets	1			3		4
Balance as of December 31, 2010	23			28		51
Purchases	7			—		7
Realized loss on sales	(2		)	—		(2		)
Unrealized gain on assets	4			2		6
Balance as of December 31, 2011	$	32		$	30	$	62

Schedule of Defined Benefit Plans Disclosures [Table Text Block]



	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2011			2010			2011			2010			2011			2010
Benefit obligation:
As of January 1	$	550		$	491		$	79		$	77		$	25		$	27
Service cost	12			11			2			2			—			—
Interest cost	29			28			4			4			1			1
Participants’ contributions	—			—			2			2			—			—
Actuarial loss (gain)	69			42			(5		)	1			3			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	634		$	550		$	75		$	79		$	27		$	25
Fair value of plan assets:
As of January 1	$	473		$	406		$	16		$	19		$	19		$	20
Actual return on plan assets	14			59			—			1			—			2
Company contributions	26			30			16			1			—			—
Participants’ contributions	—			—			2			2			—			—
Benefit payments	(26		)	(22		)	(7		)	(7		)	(2		)	(3		)
As of December 31	$	487		$	473		$	27		$	16		$	17		$	19
Unfunded position as of December 31	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)
Accumulated benefit plan obligation as of December 31	$	566		$	503		N/A			N/A			$	27		$	25
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	17		$	19
Current liability	—			—			—			—			(2		)	(2		)
Noncurrent liability	(147		)	(77		)	(48		)	(63		)	(25		)	(23		)
Net liability	$	(147	)	$	(77	)	$	(48	)	$	(63	)	$	(10	)	$	(6	)



	Defined Benefit Pension Plan						Other Postretirement Benefits								Non-Qualified Benefit Plans
	2011			2010			2011				2010				2011			2010
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	97		$	22		$	(4	)		$	1			$	2		$	—
Amortization of net actuarial loss	(8		)	(3		)	(1		)		(1		)		(1		)	(1		)
Amortization of prior service cost	(1		)	(1		)	(1		)		(1		)		—			—
	$	88		$	18		$	(6	)		$	(1	)		$	1		$	(1	)
Amounts included in AOCL*:
Net actuarial loss	$	275		$	186		$	15			$	20			$	10		$	9
Prior service cost	1			2			4				5				—			—
	$	276		$	188		$	19			$	25			$	10		$	9
Assumptions used:
Discount rate used to calculate benefit obligation	5.00		%	5.47		%	3.76		%	-	4.02		%	-	5.00		%	5.47		%
							4.90		%		5.40		%
Weighted average rate of increase in future compensation levels	3.71		%	3.80		%	4.58		%		4.83		%		N/A			N/A
Long-term rate of return on plan assets	8.25		%	8.50		%	7.09		%		6.44		%		N/A			N/A


*	Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets.

Schedule of Net Benefit Costs [Table Text Block]

Net periodic benefit cost consists of the following for the years ended December 31 (in millions):



	Defined Benefit Pension Plan									Other Postretirement Benefits									Non-Qualified Benefit Plans
	2011			2010			2009			2011			2010			2009			2011		2010		2009
Service cost	$	12		$	11		$	11		$	2		$	2		$	2		$	—	$	—	$	—
Interest cost on benefit obligation	29			28			31			4			4			4			1		1		2
Expected return on plan assets	(42		)	(39		)	(43		)	(1		)	(1		)	(1		)	—		—		—
Amortization of prior service cost	1			1			1			1			1			1			—		—		—
Amortization of net actuarial loss	8			3			—			1			1			1			1		1		—
Net periodic benefit cost	$	8		$	4		$	—		$	7		$	7		$	7		$	2	$	2	$	2

Schedule of Expected Benefit Payments [Table Text Block]

The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions):



	Payments Due
	2012		2013		2014		2015		2016		2017 - 2021
Defined benefit pension plan	$	31	$	32	$	34	$	36	$	37	$	209
Other postretirement benefits	4		4		4		4		5		23
Non-qualified benefit plans	2		2		2		3		2		11
Total	$	37	$	38	$	40	$	43	$	44	$	243

- Definition

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5, 6, 7
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 158
-Paragraph 4, 7, 16, 20, 21
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=6930749&loc=d3e4179-114921

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2410-114920

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
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-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2439-114920

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6962843&loc=d3e2417-114920

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 132R
-Paragraph 5
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2011

Income Taxes [Abstract]

Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]

Income tax expense (benefit) consists of the following (in millions):



	Years Ended December 31,
	2011		2010			2009
Current:
Federal	$	2	$	(20	)	$	(46	)
State and local	—		—			—
	2		(20		)	(46		)
Deferred:
Federal	43		61			78
State and local	13		12			6
	56		73			84
Investment tax credit adjustments	—		—			(2		)
Income tax expense	$	58	$	53		$	36

Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]

The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows:



	Years Ended December 31,
	2011		2010		2009
Federal statutory tax rate	35.0	%	35.0	%	35.0	%
Federal tax credits	(12.7	)	(10.4	)	(8.3	)
State and local taxes, net of federal tax benefit	2.6		4.4		3.4
Flow through depreciation and cost basis differences	2.1		0.1		(1.6	)
Investment tax credit amortization	—		—		(1.5	)
Other	1.3		1.2		1.8
Effective tax rate	28.3	%	30.3	%	28.8	%

Schedule of Deferred Tax Assets and Liabilities [Table Text Block]

Deferred income tax assets and liabilities consist of the following (in millions):



	As of December 31,
	2011			2010
Deferred income tax assets:
Price risk management	$	145		$	72
Employee benefits	135			98
Tax credits, net of valuation allowance	56			40
Regulatory liabilities	22			37
Tax loss carryforwards	1			17
Total deferred income tax assets	359			264
Deferred income tax liabilities:
Depreciation and amortization	572			534
Regulatory assets	274			175
Other	9			4
Total deferred income tax liabilities	855			713
Deferred income tax liability, net	$	(496	)	$	(449	)
Classification of net deferred income taxes:
Current deferred income tax asset ⁽¹⁾	$	33		$	—
Current deferred income tax liability ⁽²⁾	—			(4		)
Noncurrent deferred income tax liability	(529		)	(445		)
	$	(496	)	$	(449	)


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


(2)	Included in Accrued expenses and other current liabilities in the consolidated balance sheets.

Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables)

12 Months Ended

Dec. 31, 2011

Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]

Schedule of Share-based Compensation, Restricted Stock Units Award Activity [Table Text Block]

Restricted and Performance Stock Unit activity is summarized in the following table:



	Units		Weighted Average Grant Date Fair Value
Outstanding as of December 31, 2008	360,382		25.04
Granted	243,574		14.95
Forfeited	(4,847	)	24.85
Vested	(176,846	)	23.60
Outstanding as of December 31, 2009	422,263		19.82
Granted	191,469		19.18
Forfeited	(45,081	)	23.45
Vested	(103,223	)	25.78
Outstanding as of December 31, 2010	465,428		17.88
Granted	152,657		23.84
Forfeited	(106,979	)	22.35
Vested	(19,702	)	23.34
Outstanding as of December 31, 2011	491,404		18.54

Earnings Per Share Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2011

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]

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



	Years Ended December 31,
	2011		2010		2009
Numerator (in millions):
Net income attributable to Portland General Electric Company common shareholders	$	147	$	125	$	95
Denominator (in thousands):
Weighted average common shares outstanding—basic	75,333		75,275		72,790
Dilutive effect of unvested restricted stock units and employee stock purchase plan shares	17		16		62
Weighted average common shares outstanding—diluted	75,350		75,291		72,852

Earnings per share—basic and diluted	$	1.95	$	1.66	$	1.31

Commitments and Guarantees Commitments and Guarantees (Tables)

12 Months Ended

Dec. 31, 2011

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

As of December 31, 2011, PGE’s future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):



	Payments Due
	2012		2013		2014		2015		2016		Thereafter		Total
Capital and other purchase commitments	$	58	$	18	$	10	$	10	$	6	$	73	$	175
Purchased power and fuel:
Electricity purchases	129		77		76		76		57		381		796
Capacity contracts	21		21		21		20		19		—		102
Public Utility Districts	7		8		8		8		7		30		68
Natural gas	49		22		22		20		12		11		136
Coal and transportation	25		19		9		—		—		—		53
Operating leases	9		10		9		10		10		196		244
Total	$	298	$	175	$	155	$	144	$	111	$	691	$	1,574

Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block]

PGE has long-term power purchase contracts with certain public utility districts in the state of Washington and with the City of Portland, Oregon. The Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether or not they are operable. The future minimum payments for the Public Utility Districts in the preceding table reflect the principal payment only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions):



	Revenue Bonds as of December 31, 2011		PGE Share			Contract Expiration	PGE Cost, including Debt Service
	Revenue Bonds as of December 31, 2011		Output		Capacity	Contract Expiration	2011		2010		2009
					(in MW)
Priest Rapids and Wanapum	$	917	8.8	%	176	2052	$	14	$	10	$	17
Wells	259		19.4		159	2018	10		7		8
Portland Hydro	11		100.0		36	2017	4		4		4

- Definition

Tabular disclosure of unconditional purchase obligations that are not recognized as a liability on the balance sheet, including the nature and significant terms of an unconditional purchase obligation; the amount of the fixed and determinable portion of the obligation as of the date of the latest balance sheet presented in the aggregate and, if determinable, for each of the five succeeding fiscal years; the nature of any variable components of the obligation; the amount purchased under the obligation (for example, the take-or-pay or throughput contract) for the reporting period; and may include the amount of imputed interest necessary to reduce the obligation to present value.

+ References + Details

Variable Interest Entities Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2011

Variable interest Entities [Abstract]

Schedule of Variable Interest Entities [Table Text Block]

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



	As of 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.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 4
-Subparagraph g
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Interpretation (FIN)
-Number 46R
-Paragraph 2, 14, 15, 16, 23, 24, 25, 26
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 140
-Paragraph 35
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5728-111685

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
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-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5710-111685

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6970148&loc=d3e5747-111685

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Variable Interest Entity
-URI http://asc.fasb.org/extlink&oid=6528138

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS140-4/FIN46(R)-8
-Paragraph C4
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 22B

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 22E

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 23A

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 167
-Appendix D
-Paragraph 24

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 5A
-URI http://asc.fasb.org/extlink&oid=6970148&loc=SL6759159-111685

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 810
-SubTopic 10
-Section 50
-Paragraph 9
-URI http://asc.fasb.org/extlink&oid=6970148&loc=SL6228884-111685

+ Details

Jointly-owned Plant Jointly-owned Plant (Tables)

12 Months Ended

Dec. 31, 2011

Jointly-owned Plant [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31, 2011, PGE had the following investments in jointly-owned plant (dollars in millions):



	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation*		Construction Work In Progress
Boardman	65.00	%	1980			$	467	$	292	$	2
Colstrip	20.00		1986			507		326		2
Pelton/Round Butte	66.67		1958	/	1964	206		46		11
Total						$	1,180	$	664	$	15


*	Excludes asset retirement obligations and accumulated asset retirement removal costs.

Basis of Presentation Basis of Presentation (Details) $ in Millions	Dec. 31, 2011 mi² shares	Dec. 31, 2010 USD ($)
Basis of Presentation [Abstract]
Incorporated Cities	52
Service Area Sq Miles \| mi²	4,000
Number of Retail Customers	822,466
Service area population	1,700,000
Percent of State's Population	44.00%
Entity Number of Employees	2,634
Number of Union Employees	840
Number of Union Employees Subject to Agreement A	804
Number of Union Employees Subject to Agreement B	36
Other Accrued Liabilities, Current \| $		$ 67

Summary of Significant Accounting Policies Estimated average service lives (Details)	12 Months Ended
	Dec. 31, 2011
Production, excluding thermal:
Hydro	86
Wind	27
Transmission	53
Distribution	40
General	14

Summary of Significant Accounting Policies Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Property, Plant and Equipment [Line Items]
Other Investments						$ 0.0
Margin deposit						80.0	$ 83.0
Letters of Credit Outstanding, Amount						$ 104.0	$ 180.0
Public Utilities, Allowance for Funds Used During Construction, Rate						8.00%	8.00%	7.00%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest						$ 2.7	$ 9.0	$ 12.0
Allowance for equity funds used during construction						$ 5.0	$ 13.0	$ 18.0
Depreciation expense rate						3.71%	3.90%	3.80%
asset retirement removal costs included in depreciation expense						$ 49.0	$ 47.0	$ 47.0
Finite-Lived Intangible Assets, Accumulated Amortization						153.0	133.0
Amortization of Intangible Assets						19.0	17.0	16.0
Future Amortization Expense, Year One					$ 20.0
Future Amortization Expense, Year Two				$ 14.0
Future Amortization Expense, Year Three			$ 12.0
Future Amortization Expense, Year Four		$ 11.0
Future Amortization Expense, Year Five	$ 8.0
power cost deadband - lower threshold						15.0	17.0	15.0
power cost deadband - upper threshold						30.0	35.0	29.0
net variable power cost underrun						(34.0)	(12.0)
net variable power cost savings outside of threshold						19.0
Estimated Refund Under Power Cost Adjustment Mechanism						(10.0)	0.0	0.0
potential refund under the PCAM						17.0
net variable power cost overrun							22.0
Franchise taxes						41.0	39.0	$ 38.0
Deferred Tax Assets, Regulatory Assets and Liabilities						22.0	37.0
Noncurrent Regulatory Assets [Member]
Property, Plant and Equipment [Line Items]
Deferred Tax Assets, Regulatory Assets and Liabilities						$ 87.0	$ 95.0

Balance Sheet Components Allowance for Uncollectible accounts activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance as of beginning of year	$ 5	$ 5	$ 4
Increase in provision	11	7	9
Amounts written off, less recoveries	(10)	(7)	(8)
Balance as of end of year	$ 6	$ 5	$ 5

Balance Sheet Components Investments Held in Trust (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Marketable securities, at fair value:
Decommissioning Fund Investments, Fair Value	$ 37	$ 34
Assets Held-in-trust, Noncurrent	36	44
Nuclear Decommissioning [Member]
Cash equivalents	14	13
Marketable securities, at fair value:
Equity securities	0	0
Debt securities	23	21
Insurance contracts, at cash surrender value	0	0
Decommissioning Fund Investments, Fair Value	37	34
Non Qualified Benefit Plans [Member]
Cash equivalents	0	0
Marketable securities, at fair value:
Equity securities	10	19
Debt securities	3	2
Insurance contracts, at cash surrender value	23	23
Assets Held-in-trust, Noncurrent	$ 36	$ 44

- Definition

For an unclassified balance sheet, total of debt securities categorized neither as held-to-maturity nor trading.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 13
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 12
-Subparagraph b
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 133
-Paragraph 22
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 16
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 115
-Paragraph 137
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 320
-SubTopic 10
-Section 25
-Paragraph 1
-Subparagraph (b)
-URI http://asc.fasb.org/extlink&oid=6379932&loc=d3e22054-111558

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 320
-SubTopic 10
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6871852&loc=d3e26610-111562

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 320
-Section 50
-Paragraph 2
-Subparagraph (b)-(g)
-URI http://asc.fasb.org/extlink&oid=6957658&loc=d3e62557-112803

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15C
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name FASB Staff Position (FSP)
-Number FAS115-1/124-1
-Paragraph 15D
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

- Definition

Cash equivalents, excluding items classified as marketable securities, include short-term, highly liquid investments that are both readily convertible to known amounts of cash, and so near their maturity that they present insignificant risk of changes in value because of changes in interest rates. Generally, only investments with original maturities of three months or less qualify under that definition. Original maturity means original maturity to the entity holding the investment. For example, both a three-month US Treasury bill and a three-year Treasury note purchased three months from maturity qualify as cash equivalents. However, a Treasury note purchased three years ago does not become a cash equivalent when its remaining maturity is three months. Compensating balance arrangements that do not legally restrict the withdrawal or usage of cash equivalents may be reported as cash equivalents, while legally restricted equivalents held as compensating balances against borrowing arrangements, contracts entered into with others, or company statements of intention with regard to particular equivalents are not generally reported as part of unrestricted cash equivalents.

+ References + Details

- Definition

This element represents the portion of the balance sheet assertion valued at fair value by the entity whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission. This element represents the portion of a balance sheet assertion valued at fair value by the entity whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission. This item represents the amount that could be realized under a life insurance contract or contracts owned by the Company as of the date of the statement of financial position. Such Company-owned life insurance policies are commonly known as corporate-owned life insurance (COLI) or bank-owned life insurance (BOLI).

+ References + Details

Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Other current assets:
Current deferred income tax asset	$ 33	$ 0
Assets from price risk management activities	19	13
Income taxes receivable	12	22
Other	34	32
Other Assets, Current	98	67
Accrued expenses and other current liabilities:
Accrued employee compensation and benefits	44	36
Accrued interest payable	24	26
Dividends payable	21	20
Other	62	63
Other Liabilities, Current	$ 151	$ 145

Balance Sheet Components Balance Sheet Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2008
Allowance for Doubtful Accounts Receivable, Current	$ 6	$ 5	$ 5	$ 4
Preliminary engineering costs	10	13
Preliminary engineering costs expensed	$ 0	$ 0	$ 0

Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	$ 14
Domestic government, Debt securities	12
Corporate debt securities held in decommissioning trust assets	11
Corporate Credit, Debt securities	76	$ 28
Domestic Equity Securities	9
International Equity Securities	1
Debt securities - domestic government	3
Electricity	2
Natural gas	17
Financial Instruments, Owned, at Fair Value	69
Liabilities from price risk management activities: [Abstract]
Electricity	137
Natural gas	251
Liabilities, Fair Value Disclosure	388
Estimate of Fair Value, Fair Value Disclosure [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds		13
Domestic government, Debt securities		12
Corporate debt securities held in decommissioning trust assets		9
Domestic Equity Securities		16
International Equity Securities		3
Debt securities - domestic government		2
Electricity		5
Natural gas		11
Financial Instruments, Owned, at Fair Value		71
Liabilities from price risk management activities: [Abstract]
Electricity		119
Natural gas		257
Liabilities, Fair Value Disclosure		376
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Domestic government, Debt securities	3	3
Corporate debt securities held in decommissioning trust assets	0	0
Corporate Credit, Debt securities	76	0
Domestic Equity Securities	7	16
International Equity Securities	1	2
Debt securities - domestic government	3	2
Electricity	0	0
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	14	23
Liabilities from price risk management activities: [Abstract]
Electricity	0	0
Natural gas	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	14	13
Domestic government, Debt securities	9	9
Corporate debt securities held in decommissioning trust assets	11	9
Corporate Credit, Debt securities	0	0
Domestic Equity Securities	2	0
International Equity Securities	0	1
Debt securities - domestic government	0	0
Electricity	2	4
Natural gas	17	11
Financial Instruments, Owned, at Fair Value	55	47
Liabilities from price risk management activities: [Abstract]
Electricity	108	102
Natural gas	201	153
Liabilities, Fair Value Disclosure	309	255
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Domestic government, Debt securities	0	0
Corporate debt securities held in decommissioning trust assets	0	0
Corporate Credit, Debt securities	0	28
Domestic Equity Securities	0	0
International Equity Securities	0	0
Debt securities - domestic government	0	0
Electricity	0	1
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	0	1
Liabilities from price risk management activities: [Abstract]
Electricity	29	17
Natural gas	50	104
Liabilities, Fair Value Disclosure	79	121
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 23	$ 23

Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net liabilities from price risk management activities as of beginning of year	$ 120	$ 154	$ 123
Net realized and unrealized losses	86	65	47
Purchases, issuances, and settlements, net		27	0
Purchases	3
Settlements	(1)
Net transfers out of Level 3 to Level 2	(129)	(126)	(16)
Net liabilities from price risk management activities as of end of year	79	120	154
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$ 88	$ 95	$ 49

Fair Value of FInancial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt, Fair Value	$ 2,091	$ 1,968
Long-term Debt	$ 1,735	$ 1,808

Price Risk Management Price Risk Management (Details) $ in Millions, $ in Millions	Dec. 31, 2011 CAD ($)	Dec. 31, 2011 USD ($)	Dec. 31, 2010 CAD ($)	Dec. 31, 2010 USD ($)
Derivative [Line Items]
Derivative, Collateral, Master Netting Arrangements, Letters of Credit		$ 26		$ 31
Derivative, Net Liability Position, Aggregate Fair Value		321
Collateral Already Posted, Aggregate Fair Value		104
Collateral Aggregate Fair Value		$ 302
Volume Related to Derivative Instruments Held at Balance Sheet Date, Foreign Currency	$ 6		$ 7

Price Risk Management Schedule of Notional Amounts of Outstanding Derivative Positions (Details) MWh in Millions, MMBTU in Millions	Dec. 31, 2011 MMBTU MWh	Dec. 31, 2010 MMBTU MWh
Commodity contracts: [Abstract]
Electricity \| MWh	13	9
Volume Related to Derivative Instruments at Balance Sheet Date Commodity Contracts Natural Gas \| MMBTU	79	93

Price Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Current Assets, Commodity Contracts:
Commodity Contract Asset, Current, Electricity	$ 2	$ 4
Commodity Contract Asset, Current, Natural Gas	17	9
Current Derivative Assets	19	13
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	0	1
Commodity Contract Asset, Noncurrent, Natural Gas	0	2
Total noncurrent derivative assets	0	3
Total derivative assets not designated as hedging instruments	19	16
Total derivative assets	19	16
Current liabilities:
Commodity Contract Liability, Current, Electricity	66	77
Commodity Contract Liability, Current, Natural Gas	150	111
Total current derivative liabilities	216	188
Liabilities, Noncurrent [Abstract]
Commodity Contract Liability, Noncurrent, Electricity	71	42
Commodity Contract Liability, Noncurrent, Natural Gas	101	146
Total noncurrent derivative liabilities	172	188
Total derivative liabilities not designated as hedging instruments	388	376
Total derivative liabilities	$ 388	$ 376

Price Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Derivative [Line Items]
Net gain or loss recognized in the statement of income offset by regulatory accounting	$ 192	$ 258	$ 98
Commodity contracts: [Abstract]
Commodity Contracts, Electricity	117	127	79
Contracts, Natural Gas	$ 98	$ 192	$ 101

Price Risk Management Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) - Gain (Loss) on Derivatives [Member] - USD ($) $ in Millions	12 Months Ended				48 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2015
Commodity contracts: [Abstract]
Commodity Contracts, Electricity	$ 8	$ 21	$ 42	$ 64	$ 135
Commodity Contracts, Natural Gas	6	24	72	132	234
Net unrealized loss	$ 14	$ 45	$ 114	$ 196	$ 369

Price Risk Management Schedule of Concentration of Risk, by Counterparty (Details)	Dec. 31, 2011	Dec. 31, 2010
Assets from price risk management activities:
Counterparty A	19.00%	1.00%
Counterparty B	16.00%	1.00%
Counterparty C	13.00%	5.00%
Counterparty D	7.00%	22.00%
Counterparty E	7.00%	23.00%
Counterparty F	0.00%	11.00%
Counterparty G	0.00%	10.00%
Concentration of Risk, Derivative Instruments, Assets	62.00%	73.00%
Liabilities from price risk management activities: [Abstract]
Counterparty E	23.00%	24.00%
Counterparty H	10.00%	4.00%
Counterparty I	7.00%	12.00%
Concentration of Risk, Derivative Instruments, Liabilities	40.00%	40.00%

Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets [Line Items]
Remaining Recovery Period of Regulatory Assets, Price Risk Management	2 years
Remaining Recovery Period of Regulatory Asset, Deferred Broker Settlements	1 year
Remaining Recovery Period of Regulatory Asset, Debt Reacquisition Costs	7 years
Price risk management	$ 19	$ 13
Deferred income taxes	22	37
Asset retirement obligations	87	64
Current Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	0	0
Asset retirement obligations	0	0
Power Cost Adjustment Mechanism	0	0
Trojan ISFSI pollution control tax credits	0	18
Other	6	7
Total regulatory liabilities	6	25
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Asset retirement removal costs	637	588
Asset retirement obligations	36	33
Power Cost Adjustment Mechanism	10	0
Trojan ISFSI pollution control tax credits	7	4
Other	30	32
Total regulatory liabilities	720	657
Regulatory Assets, Current [Member]
Regulatory Assets [Line Items]
Price risk management	194	175
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Deferred broker settlements	11	24
Renewable energy deferral	1	22
Debt reacquisition costs	0	0
Other	10	0
Total regulatory assets	216	221
Noncurrent Regulatory Assets [Member]
Regulatory Assets [Line Items]
Price risk management	172	185
Pension and other postretirement plans	295	213
Deferred income taxes	87	95
Deferred broker settlements	0	0
Renewable energy deferral	0	0
Debt reacquisition costs	28	23
Other	12	28
Total regulatory assets	$ 594	$ 544

Regulatory Assets and Liabilities Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Regulatory Assets and Liabilities Disclosure [Abstract]
Regulatory Assets Earning a Return, Other Category	$ 21	$ 26
Regulatory Assets Earning a Return	22
Regulatory Assets Earning a Rate of Return at the Cost of Capital	$ 7
Authorized Cost of Capital	8.033%
Regulatory Assets Earning a Rate of Return at the Approved Rate	$ 7
Approved Rate for Deferred Account Under Amortization, Low End of Range	2.01%
Approved Rate for Deferred Accounts under Amortization, High End of Range	4.27%
Regulatory Assets Earning a Rate of Return by Inclusion in Rate Base	$ 8
Amount of Impairment to Carrying Amount of Regulatory Assets	$ 3

Asset Retirement Obilgations Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 37	$ 38
Utility plant	38	16
Non-utility property	12	10
Asset retirement obligations	$ 87	$ 64

Asset Retirement Obilgations Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Balance as of beginning of year	$ 64	$ 63	$ 58
Liabilities incurred	1	1	0
Liabilities settled	(4)	(3)	(4)
Accretion expense	4	4	4
Revisions in estimated cash flows	22	(1)	5
Balance as of end of year	$ 87	$ 64	$ 63

Asset Retirement Obilgations Asset Retirement Obligations (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($)
Asset Retirement Obligations [Abstract]
Damages sought in USDOE claim	$ 128
PGE Share of Recovery from USDOE Claims	67.00%
Asset Retirement Obligation Increase related to Boardman plant	$ 20
Asset Retirement Obligation Rate Recovery related to Trojan Plant	$ 4

Revolving Credit Facilities Schedule of Short term debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Short-term Debt [Line Items]
Average daily amount of short-term debt outstanding	$ 2	$ 9	$ 28
Weighted daily average interest rate	0.40%	0.40%	1.30%
Maximum amount outstanding during the year	$ 44	$ 51	$ 205

Revolving Credit Facilities Revolving Credit Facilities (Details)	12 Months Ended
	Dec. 31, 2011 USD ($)	Dec. 31, 2010 USD ($)
Revolving Credit Facilities [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity	$ 670,000,000
Credit Facilities - $370 million revolver	370,000,000
Portion of $370 million credit facility scheduled to terminate in July 2012	10,000,000
Portion of $370 million credit facility scheduled to terminate in July 2013	360,000,000
Credit Facilities - $300 million revolver	$ 300,000,000
Line of Credit Facitlity, Covenant Terms, One Month Term	one
Line of Credit Facitlity, Covenant Terms, Two Month Term	two
Line of Credit Facitlity, Covenant Terms, Three Month Term	three
Line of Credit Facitlity, Covenant Terms, Six Month Term	six
Debt Instrument, Covenant Description	.65
Ratio of Indebtedness to Net Capital	0.515
Commercial Paper, Maximum Term	270
FERC Authorized Short-term Debt, effective through February 6, 2014	$ 700,000,000
Short-term Debt	0
Commercial Paper	30,000,000	$ 19,000,000
Line of Credit Facility, Amount Outstanding	124,000,000
Line of Credit Facility, Remaining Borrowing Capacity	$ 516,000,000

Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Debt Instrument [Line Items]
First Mortgage Bonds, rates range from 3.46% to 9.31%, with a weighted average rate of 5.83% in 2011 and 5.85% in 2010, due at various dates through 2040	$ 1,615	$ 1,678
Pollution Control Revenue Bonds:
Port of Morrow, Oregon, 5% rate, due 2033	23	23
City of Forsyth, Montana, 5% rate, due 2033	119	119
Port of St. Helens, Oregon, 5.25% rate, due in 2014	0	10
Total Pollution Control Revenue Bonds	142	152
Pollution Control Revenue Bonds owned by PGE	(21)	(21)
Unamortized debt discount	(1)	(1)
Total long-term debt	1,735	1,808
Less: current portion of long-term debt	(100)	(10)
Long-term debt, net of current portion	$ 1,635	$ 1,798

Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Long-term Debt, Unclassified [Abstract]
2012	$ 100
2013	100
2014	0
2015	70
2016	67
Thereafter	1,398
Total long-term debt	$ 1,735	$ 1,808

Long-term Debt Long term debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Long-term Debt, Unclassified [Abstract]
Debt Instrument, Decrease, Repayments	$ (63)
Debt Instrument, Interest Rate, Stated Percentage	6.50%
City of Forsyth Bond rate	5.00%
First Mortgage Bonds - maximum rate	9.31%
First mortgage Bonds - minimum rate	3.46%
Port of Morrow Bond Rate	5.00%
Port of St. Helens Bond rate	5.25%
Debt, Weighted Average Interest Rate	5.83%	5.85%

Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	$ 36	$ 44
Non-qualified benefit plan liabilities	101	97
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	17	19
Non-qualified benefit plan liabilities	25	24
Other non-qualified benefit plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	19	25
Non-qualified benefit plan liabilities	$ 76	$ 73

- Definition

This represents the noncurrent liability recognized in the balance sheet that is associated with other postretirement defined benefit plans (excluding pension plans).

+ References

+ Details

Employee Benefits Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010
Actual [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	68.00%	68.00%
Debt Securities	32.00%	32.00%
Total	100.00%	100.00%
Actual [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	61.00%	46.00%
Debt Securities	39.00%	54.00%
Total	100.00%	100.00%
Actual [Member] \| Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	30.00%	42.00%
Debt Securities	7.00%	5.00%
Insurance contracts	63.00%	53.00%
Total	100.00%	100.00%
Target [Member] \| Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	67.00%	67.00%
Debt Securities	33.00%	33.00%
Total	100.00%	100.00%
Target [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	72.00%	47.00%
Debt Securities	28.00%	53.00%
Total	100.00%	100.00%
Target [Member] \| Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Equity Securities	23.00%	42.00%
Debt Securities	14.00%	7.00%
Insurance contracts	63.00%	51.00%
Total	100.00%	100.00%

Employee Benefits Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Defined Benefit Plan Disclosure [Line Items]
Domestic	$ 163	$ 163
Debt securities—Domestic government	3	2
Defined Benefit Pension Plan assets:
Domestic	13	5
Domestic	9
International	1
International	4	2
Debt securities:
Domestic government and corporate credit	78	138
Domestic government and corporate credit	3
Corporate credit	76	28
Private equity funds	32	23
Alternative investments	30
Defined Benefit Plan, Fair Value of Plan Assets	487	473
Other Postretirement Benefit Plans assets:
Money market funds	7	7
Equity securities:
Debt securities—Domestic government	12
Other post retirement benefit plan assets total	27	16
Money market funds	3	15
International	105	106
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Domestic	151	52
Debt securities—Domestic government	3	2
Defined Benefit Pension Plan assets:
Domestic	12	3
Domestic	7	16
International	1	2
International	2	1
Debt securities:
Domestic government and corporate credit	0	68
Domestic government and corporate credit	3	2
Corporate credit	76	0
Private equity funds	0	0
Alternative investments	0
Defined Benefit Plan, Fair Value of Plan Assets	281	173
Other Postretirement Benefit Plans assets:
Money market funds	0	0
Equity securities:
Debt securities—Domestic government	3	3
Other post retirement benefit plan assets total	17	6
Money market funds	0	0
International	54	53
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Domestic	12	111
Debt securities—Domestic government	0	0
Defined Benefit Pension Plan assets:
Domestic	1	2
Domestic	2	0
International	0	1
International	2	1
Debt securities:
Domestic government and corporate credit	78	70
Domestic government and corporate credit	0	0
Corporate credit	0	0
Private equity funds	0	0
Alternative investments	0
Defined Benefit Plan, Fair Value of Plan Assets	144	249
Other Postretirement Benefit Plans assets:
Money market funds	7	7
Equity securities:
Debt securities—Domestic government	9	9
Other post retirement benefit plan assets total	10	10
Money market funds	3	15
International	51	53
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Domestic	0	0
Debt securities—Domestic government	0	0
Defined Benefit Pension Plan assets:
Domestic	0	0
Domestic	0	0
International	0	0
International	0	0
Debt securities:
Domestic government and corporate credit	0	0
Domestic government and corporate credit	0	0
Corporate credit	0	28
Private equity funds	32	23
Alternative investments	30
Defined Benefit Plan, Fair Value of Plan Assets	62	51
Other Postretirement Benefit Plans assets:
Money market funds	0	0
Equity securities:
Debt securities—Domestic government	0	0
Other post retirement benefit plan assets total	0	0
Money market funds	0	0
International	$ 0	$ 0

Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	$ 487	$ 473
Private Equity Funds [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	32	23	$ 17
Purchases	7
Realized loss on sales	(2)
Purchases and sales, net		4
Realized gain on sales		1
Unrealized gain on assets	4	1
alternative assets [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	30	28	23
Purchases	0
Realized loss on sales	0
Purchases and sales, net		2
Realized gain on sales		0
Unrealized gain on assets	2	3
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets	62	51	$ 40
Purchases	7
Realized loss on sales	(2)
Purchases and sales, net		6
Realized gain on sales		1
Unrealized gain on assets	$ 6	$ 4

Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Fair value of plan assets:
As of January 1	$ 473
Classification in consolidated balance sheet:
Noncurrent asset	(36)	$ (44)
Noncurrent liability	195	140
Pension Plans, Defined Benefit [Member]
Amounts included in comprehensive income:
Net actuarial loss (gain)	97	22
Benefit obligation:
As of January 1	634	550	$ 491
Fair value of plan assets:
Service cost	12	11	11
Interest cost on benefit obligation	29	28	31
Participants’ contributions	0	0
Actuarial loss (gain)	69	42
Benefit payments	(26)	(22)
As of January 1	473	406
Unfunded position as of December 31	(147)	(77)
Defined Benefit Plan, Accumulated Benefit Obligation	566	503
Actual return on plan assets	14	59
Company contributions	26	30
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(147)	(77)
Amortization of net actuarial loss	(8)	(3)
Amortization of prior service cost	(1)	(1)
Total Amounts included in comprehensive income	88	18
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	276	188
Amounts included in AOCL:
Net actuarial loss	275	186
Prior service cost	$ 1	$ 2
Assumptions used:
Discount rate used to calculate benefit obligation	5.00%	5.47%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.71%	3.80%
Long-term rate of return on plan assets	8.25%	8.50%
Other Postretirement Benefit Plans [Member]
Amounts included in comprehensive income:
Net actuarial loss (gain)	$ (4)	$ 1
Benefit obligation:
As of January 1	75	79	77
Fair value of plan assets:
Service cost	2	2	2
Interest cost on benefit obligation	4	4	4
Participants’ contributions	2	2
Actuarial loss (gain)	(5)	1
Benefit payments	(7)	(7)
As of January 1	16	19
Unfunded position as of December 31	(48)	(63)
Actual return on plan assets	0	1
Company contributions	16	1
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(48)	(63)
Amortization of net actuarial loss	(1)	(1)
Amortization of prior service cost	(1)	(1)
Total Amounts included in comprehensive income	(6)	(1)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	19	25
Amounts included in AOCL:
Net actuarial loss	15	20
Prior service cost	$ 4	$ 5
Assumptions used:
Discount rate used to calculate benefit obligation	3.76%	4.02%
Defined Benefit Plan Discount rate - upper range	4.90%	5.40%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.58%	4.83%
Long-term rate of return on plan assets	7.09%	6.44%
Non Qualified Benefit Plans [Member]
Amounts included in comprehensive income:
Net actuarial loss (gain)	$ 2	$ 0
Benefit obligation:
As of January 1	27	25	27
Fair value of plan assets:
Service cost	0	0	0
Interest cost on benefit obligation	1	1	$ 2
Participants’ contributions	0	0
Actuarial loss (gain)	3	0
Benefit payments	(2)	(3)
As of January 1	19	20
Unfunded position as of December 31	(10)	(6)
Defined Benefit Plan, Accumulated Benefit Obligation	27	25
Actual return on plan assets	0	2
Company contributions	0	0
Classification in consolidated balance sheet:
Noncurrent asset	(17)	(19)
Current liability	(2)	(2)
Noncurrent liability	(25)	(23)
Amortization of net actuarial loss	(1)	(1)
Amortization of prior service cost	0	0
Total Amounts included in comprehensive income	1	(1)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	10	9
Amounts included in AOCL:
Net actuarial loss	10	9
Prior service cost	$ 0	$ 0
Assumptions used:
Discount rate used to calculate benefit obligation	5.00%	5.47%

Employee Benefits Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 2	$ 2
Interest cost on benefit obligation	4	4	4
Expected return on plan assets	(1)	(1)	(1)
Amortization of prior service cost	1	1	1
Amortization of net actuarial loss	1	1	1
Net periodic benefit cost	7	7	7
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost on benefit obligation	1	1	2
Expected return on plan assets	0	0	0
Amortization of prior service cost	0	0	0
Amortization of net actuarial loss	1	1	0
Net periodic benefit cost	2	2	2
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	12	11	11
Interest cost on benefit obligation	29	28	31
Expected return on plan assets	(42)	(39)	(43)
Amortization of prior service cost	1	1	1
Amortization of net actuarial loss	8	3	0
Net periodic benefit cost	$ 8	$ 4	$ 0

Employee Benefits Schedule of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2011 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 37
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	38
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	40
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	43
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	44
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	243
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	31
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	32
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	34
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	36
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	37
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	209
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	5
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	23
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	3
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	2
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 11

Employee Benefits Employee Benefits (Details) - USD ($)	12 Months Ended
Employee Benefits Employee Benefits (Details) - USD ($)	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Employee Benefits [Abstract]
Pension Contributions	$ 0	$ 26,000,000	$ 30,000,000	$ 0
Contribution to health reimbursement account - sick time		0.58
Contribution to health reimbursement account - earned time off		1,000,000
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year		20,000,000
Net actuarial loss portion of amortization from AOCL for pension benefits		17,000,000
Net Actuarial Loss Portion of Amortization from AOCL for Non-qualified benefits		1,000,000
Net actuarial loss portion of amortiztion of AOCL for other postretirement benefits		1,000,000
Prior service cost portion of amortization of AOCL for other postretirement benefits		$ 1,000,000
Defined benefit plan, current annual rate of health care cost increase		8.00%	8.00%	7.50%
Defined Benefit Plan, Health Care Cost Trend Rate Assumed for Next Fiscal Year		0.50%	0.50%	0.50%
Defined Benefit Plan, Ultimate Health Care Cost Trend Rate		5.00%	5.00%	5.00%
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components		$ 0
Defined Benefit Plan, Effect of One Percentage Point Increase on Accumulated Postretirement Benefit Obligation		$ 1,000,000
Company match pre 2009 hire		6.00%
Company match post 2008 hire		5.00%
Company contribution percentage to 401k for post 2008 hires		5.00%
Company contribution percent to 401k for bargaining employees		1.00%
401k Plan Company contributions		$ 16,000,000	$ 15,000,000	$ 14,000,000

Income Taxes Schedule of Components of Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Current:
Federal	$ 2	$ (20)	$ (46)
State and local	0	0	0
Current Income Tax Expense (Benefit)	2	(20)	(46)
Deferred:
Federal	43	61	78
State and local	13	12	6
deferred income tax expense	56	73	84
Investment tax credit adjustments	0	0	(2)
Income tax expense	$ 58	$ 53	$ 36

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Income Taxes [Abstract]
Federal statutory tax rate	35.00%	35.00%	35.00%
Federal tax credits	(12.70%)	(10.40%)	(8.30%)
State and local taxes, net of federal tax benefit	2.60%	4.40%	3.40%
Flow through depreciation and cost basis differences	2.10%	0.10%	(1.60%)
Investment tax credit amortization	0.00%	0.00%	(1.50%)
Other	1.30%	1.20%	1.80%
Effective tax rate	28.30%	30.30%	28.80%

Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Deferred income tax assets:
Price risk management	$ 145	$ 72
Employee benefits	135	98
Deferred Tax Assets, tax credits, net of valuation allowance	56	40
Deferred income taxes	22	37
Tax loss carryforwards	1	17
Total deferred income tax assets	359	264
Deferred income tax liabilities:
Depreciation and amortization	572	534
Regulatory assets	274	175
Other	9	4
Total deferred income tax liabilities	855	713
Deferred income tax liability, net	(496)	(449)
Classification of net deferred income taxes:
Current deferred income tax asset	33	0
Current deferred income tax liability	0	(4)
Noncurrent deferred income tax liability	$ (529)	$ (445)

Income Taxes Income taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes Income taxes (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Operating Loss Carryforwards [Line Items]
Deferred Taxes Reclass, To Depreciation and Amortization From Regulatory Liabilities		$ 220
Deferred Taxes Reclass, To Price Risk Management From Regulatory Liabilities		74
Deferred Taxes Reclass, To Employee Benefits From Regulatory Assets		73
Deferred Taxes Reclass To Regulatory Assets From Other		8
Loss Carryforward, Federal	$ 0
Loss Carryforward, State	1
Tax Credit Carryforward, Federal	42
Tax Credit Carryforward, State	14
Deferred Tax Assets, Valuation Allowance	0	2
Valuation Allowance, Deferred Tax Asset, Change in Amount	(2)	(1)
Unrecognized Tax Benefits	0	2
Unrecognized Tax Benefits, Interest on Income Taxes Expense		1
Unrecognized Tax Benefits, Income Tax Penalties Expense		$ 0
Unrecognized Tax Benefits, Decreases Resulting from Current Period Tax Positions	$ 2

Stock Purchase Plan Stock Purchase Plan (Details)	12 Months Ended
Stock Purchase Plan Stock Purchase Plan (Details)	Dec. 31, 2011 USD ($) shares
Dividend Reinvestment and Direct Stock Purchase Plan [Abstract]
Dividend Reinvestment and Direct Stock Purchase Plan Shares	2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares	2,496,842
Employee stock purchase plans [Abstract]
employee stock purchase plan shares authorized	625,000
Employee Stock Purchase Plan, Base Pay Threshold	10.00%
Employee Stock Purchase Plan, Purchased Stock Value Limitation \| $	$ 25,000
Employee Stock Purchase Plan, Share Purchase Limitation	1,500
Employee Stock Purchase Plan, Purchase Price	95.00%
Employee Stock Purchase Plan, Number of Available Shares	507,594

Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Outstanding, Units	465,428	422,263	360,382
Outstanding, Weighted Average Grant Date Fair Value	$ 17.88	$ 19.82	$ 25.04
Granted, Units	152,657	191,469	243,574
Granted, Weighted Average Grant Date Fair Value	$ 23.84	$ 19.18	$ 14.95
Forfeited, Units	(106,979)	(45,081)	(4,847)
Forfeited, Weighted Average Grant Date Fair Value	$ 22.35	$ 23.45	$ 24.85
Vested, Units	(19,702)	(103,223)	(176,846)
Vested, Weighted Average Grant Date Fair Value	$ 23.34	$ 25.78	$ 23.6
Outstanding, Units	491,404	465,428	422,263
Outstanding, Weighted Average Grant Date Fair Value	$ 18.54	$ 17.88	$ 19.82

- Definition

The weighted average fair value of nonvested awards on equity-based plans excluding option plans (for example, phantom stock or unit plan, stock or unit appreciation rights plan, revenue or profit achievement stock award plan) for which the employer is contingently obligated to issue equity instruments or transfer assets to an employee who has not yet satisfied service or performance criteria necessary to gain title to proceeds from the sale of the award or underlying shares or units.

+ References + Details

Stock-based Compensation Expense Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended					36 Months Ended
	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 2011
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized			4,687,500			4,687,500
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant			3,931,204			3,931,204
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value			$ 1.0	$ 3.0	$ 4.0
Share-based Compensation	$ 1.0	$ 3.0	4.0	2.0	1.0
Adjustments Related to Tax Withholding for Share-based Compensation			0.0	$ 0.5	$ 1.0
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized			$ 4.0			$ 4.0
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting			121.80%	117.90%	91.10%
Stock-based Compensation, Forfeiture Rate						6.00%

Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Attributable to Parent	$ 147	$ 125	$ 95
Weighted Average Number of Shares Outstanding, Basic	75,333	75,275	72,790
Weighted Average Number Diluted Shares Outstanding Adjustment	17	16	62
Weighted Average Number of Shares Outstanding, Diluted	75,350	75,291	72,852
Earnings Per Share, Basic and Diluted	$ 1.95	$ 1.66	$ 1.31

- Definition

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 87-21
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 130
-Paragraph 10, 15
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 95
-Paragraph 28, 29, 30
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Article 5
-Section 03
-Paragraph 19

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Regulation S-X (SX)
-Number 210
-Section 04
-Paragraph 20
-Article 9

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 230
-SubTopic 10
-Section 45
-Paragraph 28
-URI http://asc.fasb.org/extlink&oid=6943989&loc=d3e3602-108585

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Net Income
-URI http://asc.fasb.org/extlink&oid=6518256

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Other Comprehensive Income
-URI http://asc.fasb.org/extlink&oid=6519514

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 225
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SX 210.5-03.18)
-URI http://asc.fasb.org/extlink&oid=6880815&loc=d3e20235-122688

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.19)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6920043&loc=d3e565-108580

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 944
-SubTopic 225
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-04.22)
-URI http://asc.fasb.org/extlink&oid=6879464&loc=d3e573970-122913

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph 38
-Subparagraph d
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher AICPA
-Name Accounting Research Bulletin (ARB)
-Number 51
-Paragraph A7
-Appendix A

+ Details

- Definition

The average number of shares or units issued and outstanding that are used in calculating diluted EPS or earnings per unit (EPU), determined based on the timing of issuance of shares or units in the period.

+ References + Details

- Definition

Number of [basic] shares or units, after adjustment for contingently issuable shares or units and other shares or units not deemed outstanding, determined by relating the portion of time within a reporting period that common shares or units have been outstanding to the total time in that period.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 171
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 40
-Subparagraph a
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Statement of Financial Accounting Standard (FAS)
-Number 128
-Paragraph 8
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 50
-Paragraph 1
-Subparagraph (a)
-URI http://asc.fasb.org/extlink&oid=6371337&loc=d3e3550-109257

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 260
-SubTopic 10
-Section 45
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=6920599&loc=d3e1448-109256

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Weighted-Average Number of Common Shares Outstanding
-URI http://asc.fasb.org/extlink&oid=6528421

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Emerging Issues Task Force (EITF)
-Number 07-4
-Paragraph 4
-LegacyDoc This reference is SUPERSEDED by the Accounting Standards Codification effective for interim and annual periods ending after September 15, 2009. This reference is included to help users transition from the previous accounting hierarchy and will be removed from future versions of this taxonomy.

+ Details

Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2011 USD ($)
Capital Additions [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 175
Unrecorded Unconditional Purchase Obligation, Due within One Year	58
Unrecorded Unconditional Purchase Obligation, Due within Two Years	18
Unrecorded Unconditional Purchase Obligation, Due within Three Years	10
Unrecorded Unconditional Purchase Obligation, Due within Four Years	10
Unrecorded Unconditional Purchase Obligation, Due within Five Years	6
Unrecorded Unconditional Purchase Obligation, Due after Five Years	73
Long-term Contract for Purchase of Electric Power [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	796
Unrecorded Unconditional Purchase Obligation, Due within One Year	129
Unrecorded Unconditional Purchase Obligation, Due within Two Years	77
Unrecorded Unconditional Purchase Obligation, Due within Three Years	76
Unrecorded Unconditional Purchase Obligation, Due within Four Years	76
Unrecorded Unconditional Purchase Obligation, Due within Five Years	57
Unrecorded Unconditional Purchase Obligation, Due after Five Years	381
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	102
Unrecorded Unconditional Purchase Obligation, Due within One Year	21
Unrecorded Unconditional Purchase Obligation, Due within Two Years	21
Unrecorded Unconditional Purchase Obligation, Due within Three Years	21
Unrecorded Unconditional Purchase Obligation, Due within Four Years	20
Unrecorded Unconditional Purchase Obligation, Due within Five Years	19
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	68
Unrecorded Unconditional Purchase Obligation, Due within One Year	7
Unrecorded Unconditional Purchase Obligation, Due within Two Years	8
Unrecorded Unconditional Purchase Obligation, Due within Three Years	8
Unrecorded Unconditional Purchase Obligation, Due within Four Years	8
Unrecorded Unconditional Purchase Obligation, Due within Five Years	7
Unrecorded Unconditional Purchase Obligation, Due after Five Years	30
Public Utilities, Inventory, Fuel [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	136
Unrecorded Unconditional Purchase Obligation, Due within One Year	49
Unrecorded Unconditional Purchase Obligation, Due within Two Years	22
Unrecorded Unconditional Purchase Obligation, Due within Three Years	22
Unrecorded Unconditional Purchase Obligation, Due within Four Years	20
Unrecorded Unconditional Purchase Obligation, Due within Five Years	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	11
Coal Supply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	53
Unrecorded Unconditional Purchase Obligation, Due within One Year	25
Unrecorded Unconditional Purchase Obligation, Due within Two Years	19
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Lease Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	244
Unrecorded Unconditional Purchase Obligation, Due within One Year	9
Unrecorded Unconditional Purchase Obligation, Due within Two Years	10
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	10
Unrecorded Unconditional Purchase Obligation, Due within Five Years	10
Unrecorded Unconditional Purchase Obligation, Due after Five Years	196
Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	1,574
Unrecorded Unconditional Purchase Obligation, Due within One Year	298
Unrecorded Unconditional Purchase Obligation, Due within Two Years	175
Unrecorded Unconditional Purchase Obligation, Due within Three Years	155
Unrecorded Unconditional Purchase Obligation, Due within Four Years	144
Unrecorded Unconditional Purchase Obligation, Due within Five Years	111
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 691

Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions	12 Months Ended
	Dec. 31, 2011 USD ($) MW	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 917
PGE Share of Output	8.80%
PGE Share of Capacity \| MW	176
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2052
commitment costs	$ 14	$ 10	$ 17
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 259
PGE Share of Output	19.40%
PGE Share of Capacity \| MW	159
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2018
commitment costs	$ 10	7	8
Portland Hydro [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 11
PGE Share of Output	100.00%
PGE Share of Capacity \| MW	36
Long-term Contract for Purchase of Electric Power, Date of Contract Expiration	Dec. 31, 2017
commitment costs	$ 4	$ 4	$ 4

Commitments and Guarantees Commitments and Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2011	Dec. 31, 2010	Dec. 31, 2009	Dec. 31, 1985
Unrecorded Unconditional Purchase Obligation [Line Items]
percentage of output	25.00%
Operating Leases, Rent Expense	$ 9	$ 9	$ 7
Long-term Contract for Purchase of Electric Power, Estimated Annual Cost	13
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within One Year	3
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Two Years	2
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Five Years	1
Operating Leases, Rent Expense, Sublease Rentals	3	$ 3	$ 3
Ownership interest in Boardman sold				15.00%
ownership interest in Pacific Northwest Intertie sold				10.714%
maximum potential liability under power and transmission agreements	74
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Three Years	2
Future Minimum Sublease Rentals, Sale Leaseback Transactions, within Four Years	$ 2

Variable Interest Entities Schedule of Variable Interest Entities (Details) - USD ($) $ in Millions	Dec. 31, 2011	Dec. 31, 2010
Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 1	$ 1
Accounts receivable	0	4
Electric utility plant, net	$ 5	$ 5

Variable Interest Entities Variable Interest Entities (Details) $ in Millions	12 Months Ended		36 Months Ended
	Dec. 31, 2010 USD ($)	Dec. 31, 2009 USD ($)	Dec. 31, 2011 shares
Variable interest Entities [Abstract]
Variable Interest Entity, Qualitative or Quantitative Information, Ownership Percentage			1.00%
Limited Liability Company (LLC) or Limited Partnership (LP), Members or Limited Partners, Ownership Interest			99.00%
Subsidiary or Equity Method Investee, Cumulative Percentage Ownership after All Transactions			100.00%
Estimated Remaining Useful Life of Facility Acquired			75.00%
Variable Interest Entity, Initial Consolidation, Gain (Loss) \| $	$ 4	$ 5
Variable Interest Entity, Discount Rate Used in Impairment Calc			7.00%
Property, Plant and Equipment, Useful Life, Minimum			20
Property, Plant and Equipment, Useful Life, Maximum			25

Jointly-owned Plant Schedule of Jointly-owned plant (Details) $ in Millions	Dec. 31, 2011 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman	65.00%
Jointly Owned Plant, Boardman Plant In Service Year	1980
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service	$ 467
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation	292
Jointly Owned Utility Plant Ownership Amount of Construction Work In Progress Boardman	$ 2
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%
Jointly Owned Plant, Colstrip Plant In Service Year	1986
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service	$ 507
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation	326
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip	$ 2
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte	66.67%
Jointly Owned Plant, Pelton Plant in Service Year	1958
Jointly Owned Plant, Round Butte in Service Year	1964
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service	$ 206
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation	46
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte	11
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1,180
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	664
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 15

Contingencies Contingencies (Details) $ in Millions	12 Months Ended
Contingencies Contingencies (Details) $ in Millions	Dec. 31, 2011	Dec. 31, 2008 USD ($)	Dec. 31, 1997 mi	Sep. 30, 2008 USD ($)	Dec. 31, 2003 USD ($)	Dec. 31, 1993
Loss Contingencies [Line Items]
investment in Trojan						87.00%
Customer refund for Trojan Investment, net of Interest				$ 15.4
Interest Rate Applied to Trojan Refund				9.60%
refund to customers for Trojan Investment including interest				$ 33.1
Class action damages sought					$ 260.0
Site Contingency, Names of Other Potentially Responsible Parties	100		69
river miles \| mi			5.7
Repayments of Pollution Control Bond		$ 5.8

Label	Element	Value
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	$ 487,000,000
Other Postretirement Benefit Plans, Defined Benefit [Member]
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	27,000,000
Non Qualified Benefit Plans [Member]
Defined Benefit Plan, Fair Value of Plan Assets	us-gaap_DefinedBenefitPlanFairValueOfPlanAssets	$ 17,000,000

- Definition

Assets, usually stocks, bonds, and other investments, that have been segregated and restricted (usually in a trust) to provide benefits, at their fair value as of the measurement date. Plan assets include amounts contributed by the employer (and by employees for a contributory plan) and amounts earned from investing the contributions, less benefits paid. If a plan has liabilities other than for benefits, those non-benefit obligations may be considered as reductions of plan assets.

+ References + Details