Portland General Electric (POR) 10-Q 28 Apr 15 2015 Q1 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	3 Months Ended
	Mar. 31, 2015	Apr. 22, 2015
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	784977
Document Type	10-Q
Document Period End Date	31-Mar-15
Amendment Flag	FALSE
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	-19
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		78,344,941
Trading Symbol	POR

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Income (Unaudited) (USD $)	3 Months Ended
In Millions, except Share data in Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Revenues, net	$473	$493
Operating expenses:
Purchased power and fuel	161	184
Generation, transmission and distribution	62	54
Administrative and other	60	54
Depreciation and amortization	75	75
Taxes other than income taxes	30	28
Total operating expenses	388	395
Income from operations	85	98
Interest expense, net	30	25
Other income (expense):
Allowance for equity funds used during construction	4	6
Miscellaneous income (expense), net	1	-1
Other income, net	5	5
Income before income tax expense	60	78
Income tax expense	10	20
Net income and Comprehensive income	$50	$58
Weighted-average shares outstanding (in thousands):
Basic	78,271	78,992
Diluted	81,466	80,156
Earnings per share:
Basic	$0.64	$0.74
Diluted	$0.62	$0.73
Dividends declared per common share	$0.28	$0.28

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (Unaudited) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Current assets:
Cash and cash equivalents	$27	$127
Accounts receivable, net	129	149
Unbilled revenues	75	93
Inventories	95	82
Regulatory assets - current	125	133
Other current assets	133	115
Total current assets	584	699
Electric utility plant, net	5,789	5,679
Regulatory assets - noncurrent	545	494
Nuclear decommissioning trust	90	90
Non-qualified benefit plan trust	34	32
Other noncurrent assets	49	48
Total assets	7,091	7,042
Current liabilities
Accounts payable	137	156
Liabilities from price risk mangement activities - current	107	106
Current portion of long-term debt	322	375
Accrued expenses and other current liabilities	243	236
Total current liabilities	809	873
Long-term debt, net of current portion	2,134	2,126
Regulatory liabilities - noncurrent	911	906
Deferred income taxes	636	625
Unfunded status of pension and postretirement plans	239	237
Liabilities from price risk mangement activities - noncurrent	176	122
Asset retirement obligations	119	116
Non-qualified benefit plan liabilities	106	105
Other noncurrent liabilities	22	21
Total liabilities	5,152	5,131
Commitments and contingencies (see notes)
Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2015 and December 31, 2014	0	0
Common stock, no par value, 160,000,000 shares authorized; 78,344,691 and 78,228,339 shares issued and outstanding as of March 31, 2015 and December 31, 2014, respectively	918	918
Accumulated other comprehensive loss	-7	-7
Retained earnings	1,028	1,000
Total equity	1,939	1,911
Total liabilities and equity	$7,091	$7,042

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) (USD $)	Mar. 31, 2015	Dec. 31, 2014
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	78,344,691	78,228,339
Common stock, shares outstanding	78,344,691	78,228,339

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Cash Flows (Unaudited) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Cash flows from operating activities:
Net income	$50	$58
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	75	75
Increase (decrease) in net liabilities from price risk management activities	53	-19
Regulatory deferrals-price risk management activities	-53	19
Deferred income taxes	10	15
Pension and other postretirement benefits	9	8
Allowance for equity funds used during construction	-4	-6
Regulatory deferral of settled derivative instruments	2	5
Decoupling mechanism deferrals, net of amortization	-3	-4
Other non-cash income and expenses, net	6	7
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	37	14
(Increase) decrease in Inventories	-13	2
Increase in margin deposits, net	-9	-8
Decrease in accounts payable and accrued liabilities	-1	-6
Other working capital items, net	-20	-15
Cash received to be returned to customers pursuant to the Residential Exchange Program	1	15
Other, net	-6	-2
Net cash provided by operating activities	134	158
Cash flows from investing activities:
Capital expenditures	-178	-185
Sales tax refund received related to Tucannon River Wind Farm	12	0
Sales of nuclear decommissioning trust securities	4	6
Purchases of nuclear decommissioning trust securities	-5	-6
Proceeds from sale of property	0	4
Other, net	0	2
Net cash used in investing activities	-167	-179
Cash flows from financing activities:
Proceeds from issuance of long-term debt	75	0
Payments on long-term debt	-120	0
Dividends paid	-22	-22
Net cash used in financing activities	-67	-22
Decrease in cash and cash equivalents	-100	-43
Cash and cash equivalents, beginning of period	127	107
Cash and cash equivalents, end of period	27	64
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	14	10
Non-cash investing and financing activities:
Accrued capital additions	62	69
Accrued dividends payable	$22	$22

Basis_of_Presentation_Notes

Basis of Presentation (Notes)	3 Months Ended
	Mar. 31, 2015
Basis of Presentation [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION
	Nature of Business
	Portland General Electric Company (PGE or the Company) is a single, vertically integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. 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 are located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area allocation is located entirely within the state of Oregon, encompassing 52 incorporated cities, of which Portland and Salem are the largest. As of March 31, 2015, PGE served 844,393 retail customers with a service area population of approximately 1.8 million, comprising approximately 46% of the state’s population.
	Condensed Consolidated Financial Statements
	These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading.
	To conform with the 2015 presentation, PGE has separately presented Decrease in inventories of $2 million from Other working capital items, net in the operating activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2014.
	The financial information included herein for the three months ended March 31, 2015 and 2014 is unaudited; however, such information reflects all adjustments, consisting of normal recurring adjustments, that are, in the opinion of management, necessary for a fair presentation of the condensed consolidated financial position, condensed consolidated statements of income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale energy and natural gas, interim financial results do not necessarily represent those to be expected for the year. The financial information as of December 31, 2014 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2014, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 13, 2015, which should be read in conjunction with such condensed consolidated financial statements.
	Comprehensive Income
	PGE had no material components of other comprehensive income to report for the three months ended March 31, 2015 and 2014.
	Use of Estimates
	The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of 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 experienced by the Company could differ materially from those estimates.
	Recent Accounting Pronouncements
	Accounting Standards Update (ASU) 2014-09, Revenue from Contracts with Customers (Topic 606) (ASU 2014-09), creates a new Topic 606 and supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and most industry-specific guidance throughout the Industry Topics of the Codification. ASU 2014-09 provides a five-step analysis of transactions to determine when and how revenue is recognized that consists of: i) identify the contract with the customer; ii) identify the performance obligations in the contract; iii) determine the transaction price; iv) allocate the transaction price to the performance obligations; and v) recognize revenue when or as each performance obligation is satisfied. Companies can transition to the requirements of this ASU either retrospectively or as a cumulative-effect adjustment as of the date of adoption, which is January 1, 2017 for the Company, with early adoption prohibited. The impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows of the adoption of ASU 2014-09 is not known at this time.
	In April 2015, the Financial Accounting Standards Board issued ASU 2015-03, Interest—Imputation of Interest (Subtopic 835-30) (ASU 2015-03), which requires that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with debt discounts. The provisions of ASU 2015-03 are effective for fiscal years beginning after December 15, 2015, or January 1, 2016 for PGE, and interim periods within those fiscal years. Early adoption is permitted for financial statements that have not been previously issued. The provisions should be applied on a retrospective basis. Upon transition, an entity is required to comply with the applicable disclosures for a change in an accounting principle, which includes: i) the nature of and reason for the change in accounting principle; ii) the transition method; iii) a description of the prior-period information that has been retrospectively adjusted; and iv) the effect of the change on the financial statement line items. The adoption of the provisions of ASU 2015-03 is not expected to have a material impact on PGE’s consolidated financial position, consolidated results of operation, or consolidated cash flows.

Balance_Sheet_Components_Notes

Balance Sheet Components (Notes)	3 Months Ended
	Mar. 31, 2015
Balance Sheet Components [Abstract]
BALANCE SHEET COMPONENTS	BALANCE SHEET COMPONENTS
	Accounts Receivable, Net
	Accounts receivable is net of an allowance for uncollectible accounts of $7 million and $6 million as of March 31, 2015 and December 31, 2014, respectively.
	The activity in the allowance for uncollectible accounts is as follows (in millions):
		Three Months Ended March 31,
		2015				2014
	Balance as of beginning of period	$	6			$	6
	Provision, net	2				2
	Amounts written off, less recoveries	(1		)		(1		)
	Balance as of end of period	$	7			$	7
	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, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.
	Other Current Assets
	Other current assets consist of the following (in millions):
		March 31,				December 31, 2014
		2015
	Prepaid expenses	$	58			$	39
	Current deferred income tax asset	33				33
	Margin deposits	20				11
	Accrued sales tax refund related to Tucannon River Wind Farm	11				23
	Assets from price risk management activities	7				6
	Other	4				3
	Other current assets	$	133			$	115
	Electric Utility Plant, Net
	Electric utility plant, net consists of the following (in millions):
		March 31,				December 31,
		2015				2014
	Electric utility plant	$	8,251			$	8,161
	Construction work-in-progress	478				417
	Total cost	8,729				8,578
	Less: accumulated depreciation and amortization	(2,940		)		(2,899		)
	Electric utility plant, net	$	5,789			$	5,679
	Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $200 million and $191 million as of March 31, 2015 and December 31, 2014, respectively. Amortization expense related to intangible assets was $9 million and $6 million for the three months ended March 31, 2015 and 2014, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.
	Regulatory Assets and Liabilities
	Regulatory assets and liabilities consist of the following (in millions):
		March 31, 2015							December 31, 2014
		Current				Noncurrent			Current			Noncurrent
	Regulatory assets:
	Price risk management	$	100			$	174		$	100		$	121
	Pension and other postretirement plans	—				242			—			247
	Deferred income taxes	—				87			—			86
	Debt issuance costs	—				15			—			15
	Deferred capital projects	14				—			19			—
	Other	11				27			14			25
	Total regulatory assets	$	125			$	545		$	133		$	494
	Regulatory liabilities:
	Asset retirement removal costs	$	—			$	813		$	—		$	804
	Trojan decommissioning activities	22				29			23			34
	Asset retirement obligations	—				40			—			39
	Other	37				29			37			29
	Total regulatory liabilities	$	59		*	$	911		$	60	*	$	906
	*	Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.
	Accrued Expenses and Other Current Liabilities
	Accrued expenses and other current liabilities consist of the following (in millions):
		March 31,				December 31, 2014
		2015
	Regulatory liabilities—current	$	59			$	60
	Accrued employee compensation and benefits	39				51
	Accrued interest payable	40				26
	Accrued dividends payable	22				23
	Accrued taxes payable	26				22
	Other	57				54
	Total accrued expenses and other current liabilities	$	243			$	236
	Credit Facilities
During the first quarter of 2015, PGE determined that a $500 million aggregate revolving credit facility capacity would be sufficient to meet its liquidity needs and accordingly, in March 2015, reduced its aggregate revolving credit capacity from $700 million to $500 million. As of March 31, 2015, PGE has a $500 million revolving credit facility, which is scheduled to expire in November 2019.
Pursuant to the terms of the agreement, the revolving credit facility 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 credit facility. The revolving credit facility contains provisions for two, one-year extensions subject to approval by the banks, requires annual fees based on PGE’s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of March 31, 2015, PGE was in compliance with this covenant with a 55.9% debt-to-total capital ratio.
PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. As of March 31, 2015, PGE had no borrowings or commercial paper outstanding, $46 million of letters of credit issued, and an aggregate available capacity under the credit facility of $454 million.
In addition, PGE has two $30 million letter of credit facilities, under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit are subject to the approval of the issuing institution. As of March 31, 2015, $58 million of letters of credit had been issued under these facilities.
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 revolving credit facility.
Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt up to $900 million through February 6, 2016. 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.
Long-term Debt
During the first quarter of 2015, PGE had the following long-term debt transactions:
•	Issued $75 million of 3.55% Series of First Mortgage Bonds (FMBs) due 2030 in January;
•	Repaid $70 million of 3.46% Series FMBs in January; and
•	Repaid $50 million of long-term bank loans in March.
On April 22, 2015, PGE agreed with certain institutional investors to issue and sell $70 million of new FMBs under a private placement. The FMBs will have an interest rate of 3.50% and mature in 2035. The transaction is expected to close and fund on May 19, 2015. In addition, on May 21, 2015, the Company will redeem its $67 million of 6.80% Series FMBs, due January 15, 2016.
Pension and Other Postretirement Benefits
Components of net periodic benefit cost are as follows for the three months ended March 31 (in millions):
	Defined Benefit							Other Postretirement
	Pension Plan							Benefits
	2015				2014			2015			2014
Service cost	$	4			$	4		$	1		$	—
Interest cost	8				9			1			1
Expected return on plan assets	(10		)		(10		)	—			—
Amortization of net actuarial loss	5				4			—			—
Net periodic benefit cost	$	7			$	7		$	2		$	1

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments (Notes)	3 Months Ended
	Mar. 31, 2015
Fair Value of Financial Instruments [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 condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2015 and December 31, 2014, and then classifies these financial assets and liabilities 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 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 that 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 transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. 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 during the three months ended March 31, 2015 and 2014, except those transfers from Level 3 to Level 2 presented in this note.
	The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):
		As of March 31, 2015
		Level 1				Level 2			Level 3			Total
	Assets:
	Nuclear decommissioning trust: (1)
	Money market funds	$	—			$	65		$	—		$	65
	Debt securities:
	Domestic government	4				10			—			14
	Corporate credit	—				11			—			11
	Non-qualified benefit plan trust: (2)
	Equity Securities:
	Domestic	5				1			—			6
	International	1				—			—			1
	Assets from price risk management activities: (1) (3)
	Electricity	—				5			2			7
	Natural gas	—				2			—			2
		$	10			$	94		$	2		$	106
	Liabilities—Liabilities from price risk management
	activities: (1) (3)
	Electricity	$	—			$	24		$	114		$	138
	Natural gas	—				109			36			145
		$	—			$	133		$	150		$	283
	-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 $27 million, which are recorded at cash surrender value.
	-3	For further information, see Note 4, Price Risk Management.
		As of December 31, 2014
		Level 1				Level 2			Level 3			Total
	Assets:
	Nuclear decommissioning trust: (1)
	Money market funds	$	—			$	65		$	—		$	65
	Debt securities:
	Domestic government	7				7			—			14
	Corporate credit	—				11			—			11
	Non-qualified benefit plan trust: (2)
	Equity securities:
	Domestic	4				1			—			5
	International	1				—			—			1
	Assets from price risk management activities: (1) (3)
	Electricity	—				4			1			5
	Natural gas	—				2			—			2
		$	12			$	90		$	1		$	103
	Liabilities—Liabilities from price risk management
	activities: (1) (3)
	Electricity	$	—			$	32		$	80		$	112
	Natural gas	—				95			21			116
		$	—			$	127		$	101		$	228
	-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 $26 million, which are recorded at cash surrender value.
	-3	For further information, see Note 4, Price Risk Management.
	Trust assets held in the Nuclear decommissioning and Non-qualified benefit plan trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in 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 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 domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.
	Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. 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 due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange. 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 are directly or indirectly observable in the marketplace.
	Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, 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 forward commodity prices and interest rates. Substantially all of these inputs 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 commodity forwards, futures 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 commodity forwards, futures and swaps.
Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:
									Valuation Technique	Significant Unobservable Input		Price per Unit
		Fair Value														Weighted Average
Commodity Contracts		Assets				Liabilities						Low		High
		(in millions)
As of March 31, 2015:
Electricity physical forward		$	—			$	112		Discounted cash flow	Electricity forward price (per MWh)		$	10.97	$	95.47	$	33.11
Natural gas financial swaps		—				36			Discounted cash flow	Natural gas forward price (per Decatherm)		2.48		4.36		2.94
Electricity financial futures		2				2			Discounted cash flow	Electricity forward price (per MWh)		10.97		34.63		22.82
		$	2			$	150
As of December 31, 2014:
Electricity physical forward		$	—			$	77		Discounted cash flow	Electricity forward price (per MWh)		$	11.97	$	122.72	$	37.43
Natural gas financial swaps		—				21			Discounted cash flow	Natural gas forward price (per Decatherm)		2.88		4.86		3.41
Electricity financial futures		1				3			Discounted cash flow	Electricity forward price (per MWh)		11.97		39.26		27.88
		$	1			$	101
The significant unobservable inputs used in the Company’s fair value measurement of price risk management assets and liabilities are long-term forward prices for commodity derivatives. For shorter term contracts, the Company employs the mid-point of the market’s bid-ask spread and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data aggregated from multiple sources. For certain long term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally developed price curves, which derive longer term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a monthly basis by the Company. This process includes analytical review of changes in commodity prices as well as procedures to analyze and identify the reasons for the changes over specific reporting periods.
The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:
Significant Unobservable Input		Position		Change to Input		Impact on Fair Value Measurement
Market price		Buy		Increase (decrease)		Gain (loss)
Market price		Sell		Increase (decrease)		Loss (gain)
Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):
	Three Months Ended March 31,
	2015				2014
Balance as of the beginning of the period	$	100			$	139
Net realized and unrealized losses (gains)*	50				(11		)
Transfers out of Level 3 to Level 2	(2		)		3
Balance as of the end of the period	$	148			$	131
*	Contains nominal amounts of realized losses. Both realized and unrealized losses (gains) are recorded in Purchased power and fuel expense in the condensed consolidated statements of income of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions.
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. During the three months ended March 31, 2015 and 2014, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when 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. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.
Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and 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. The fair value of PGE’s unsecured term bank loans is classified as Level 3 fair value measurement and is estimated based on the terms of the loans and the Company’s creditworthiness. These significant unobservable inputs to the Level 3 fair value measurement include the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximates their carrying value.
As of March 31, 2015, the carrying amount of PGE’s long-term debt was $2,456 million and its estimated aggregate fair value was $2,929 million, consisting of $2,674 million and $255 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy. As of December 31, 2014, the carrying amount of PGE’s long-term debt was $2,501 million and its estimated aggregate fair value was $2,901 million, consisting of $2,596 million and $305 million classified as Level 2 and Level 3, respectively, in the fair value hierarchy.

Price_Risk_Management_Notes

Price Risk Management (Notes)	3 Months Ended
	Mar. 31, 2015
Price Risk Management [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 generation 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 Company-owned generation. As a result, PGE is exposed to commodity price risk and foreign currency exchange rate risk, from which changes in prices and/or rates may affect the Company’s financial position, results of operations, or cash flows.
	PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in NVPC for its retail customers. These derivative instruments may include forwards, futures, swaps, and option contracts for electricity, natural gas, oil, and foreign currency, which are recorded at fair value on the condensed consolidated balance sheets, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments 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. The Company does not engage in trading activities for non-retail purposes.
	PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):
		March 31,			December 31,
		2015			2014
	Current assets:
	Commodity contracts:
	Electricity	$	5		$	4
	Natural gas	2			2
	Total current derivative assets	7		(1)	6			(1)
	Noncurrent assets:
	Commodity contracts:
	Electricity	2			1
	Total noncurrent derivative assets	2		(2)	1			(2)
	Total derivative assets not designated as hedging instruments	$	9		$	7
	Total derivative assets	$	9		$	7
	Current liabilities:
	Commodity contracts:
	Electricity	$	47		$	54
	Natural gas	60			52
	Total current derivative liabilities	107			106
	Noncurrent liabilities:
	Commodity contracts:
	Electricity	91			58
	Natural gas	85			64
	Total noncurrent derivative liabilities	176			122
	Total derivative liabilities not designated as hedging instruments	$	283		$	228
	Total derivative liabilities	$	283		$	228
	-1	Included in Other current assets on the condensed consolidated balance sheets.
	-2	Included in Other noncurrent assets on the condensed consolidated balance sheets.
	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 through 2035, were as follows (in millions):
		March 31, 2015				December 31, 2014
	Commodity contracts:
	Electricity	15		MWh		16			MWh
	Natural gas	126		Decatherms		127			Decatherms
	Foreign currency	$	7	Canadian		$	7		Canadian
	PGE has elected to report gross on the condensed consolidated balance sheets the positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement. In the case of default on, or termination of, any contract under the master netting arrangements, these agreements provide for the net settlement of all related contractual obligations with a counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit, which are excluded from the offsetting table presented below.
	Information related to Price risk management liabilities subject to master netting agreements is as follows (in millions):
											Gross Amounts Not Offset in
		Gross Amounts Recognized			Gross Amounts Offset				Net Amounts Presented		Condensed Consolidated
											Balance Sheets					Net Amount
											Derivatives			Cash Collateral(1)
	As of March 31, 2015:
	Liabilities:
	Commodity contracts:
	Electricity(2)	$	91		$	—			$	91	$	(91	)	$	—	$	—
	Natural gas(2)	16			—				16		(16		)	—		—
		$	107		$	—			$	107	$	(107	)	$	—	$	—
	As of December 31, 2014:
	Liabilities:
	Commodity contracts:
	Electricity(2)	$	55		$	—			$	55	$	(55	)	$	—	$	—
	Natural gas(2)	17			—				17		(17		)	—		—
		$	72		$	—			$	72	$	(72	)	$	—	$	—
	-1	As of March 31, 2015 and December 31, 2014, PGE had posted collateral in the amount of $15 million and $11 million, respectively, which consisted entirely of letters of credit.
	-2	Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.
	Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are recorded in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):
		Three Months Ended March 31,
		2015			2014
	Commodity contracts:
	Electricity	$	41		$	9
	Natural Gas	44			(36		)
	Net unrealized and certain net realized losses (gains) presented in the preceding table are offset within the condensed consolidated statements of income by the effects of regulatory accounting. Of the net losses (gains) recognized in Net income for the three months ended March 31, 2015 and 2014, net losses of $83 million and $12 million, respectively, have been offset.
Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2015 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):
	2015			2016				2017		2018			2019		Thereafter		Total
Commodity contracts:
Electricity	$	35		$	22			$	6	$	6		$	6	$	56	$	131
Natural gas	43			64				30		6			—		—		143
Net unrealized loss	$	78		$	86			$	36	$	12		$	6	$	56	$	274
PGE’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 PGE’s unsecured debt to below investment grade, the Company 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. Certain other counterparties would have the right to terminate their agreements with the Company.
The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of March 31, 2015 was $274 million, for which PGE has posted $62 million in collateral, consisting of $52 million in letters of credit and $10 million in cash. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2015, the cash requirement to either post as collateral or settle the instruments immediately would have been $261 million. As of March 31, 2015, PGE had posted an additional $10 million in cash collateral for derivative instruments with no credit-risk related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheet.
Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows:
	March 31,		December 31,
	2015		2014
Assets from price risk management activities:
Counterparty A	67	%	63	%
Counterparty B	8		14
	75	%	77	%
Liabilities from price risk management activities:
Counterparty C	31	%	22	%
Counterparty D	9		12
	40	%	34	%
See Note 3, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

Earnings_Per_Share_Notes

Earnings Per Share (Notes)	3 Months Ended
	Mar. 31, 2015
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 period. 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 period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) unvested time-based and performance-based restricted stock units, along with related dividend equivalent rights; and iii) shares issuable pursuant to an equity forward sale agreement (EFSA). See Note 6, Equity, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met. For the three months ended March 31, 2015 and 2014, unvested performance-based restricted stock units and related dividend equivalent rights of approximately 303,000 and 363,000, respectively, were excluded from the dilutive calculation because the performance goals had not been met.
	Net income attributable to common shareholders is the same for both the basic and diluted earnings per share computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):
		Three Months Ended March 31,
		2015	2014
	Weighted-average common shares outstanding—basic	78,271	78,992
	Dilutive effect of potential common shares	3,195	1,164
	Weighted-average common shares outstanding—diluted	81,466	80,156

Equity_Notes

Equity (Notes)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Equity	EQUITY
	The activity in equity during the three months ended March 31, 2015 and 2014 is as follows (dollars in millions):
		Common Stock				Accumulated			Retained
						Other			Earnings
						Comprehensive
		Shares	Amount			Loss
	Balances as of December 31, 2014	78,228,339	$	918		$	(7	)	$	1,000
	Issuances of shares pursuant to equity-based plans	116,352	1			—			—
	Stock-based compensation	—	(1		)	—			—
	Dividends declared	—	—			—			(22		)
	Net income	—	—			—			50
	Balances as of March 31, 2015	78,344,691	$	918		$	(7	)	$	1,028
	Balances as of December 31, 2013	78,085,559	$	911		$	(5	)	$	913
	Issuances of shares pursuant to equity-based plans	96,497	—			—			—
	Stock-based compensation	—	1			—			—
	Dividends declared	—	—			—			(22		)
	Net income	—	—			—			58
	Balances as of March 31, 2014	78,182,056	$	912		$	(5	)	$	949
	Under the terms of the EFSA, the Company may elect to settle the equity forward transactions by means of: i) physical; ii) cash; or iii) net share settlement, in whole or in part, at any time on or prior to June 11, 2015, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE is required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $29.50 per share at the time the EFSA was entered into (June 2013), and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA.
	The EFSA had no initial fair value since it was entered into at the then market price of the common stock. PGE concluded that the EFSA was an equity instrument and that it does not qualify as a derivative because the EFSA was indexed to the Company’s stock. PGE anticipates settling the EFSA through physical settlement on or before June 11, 2015.
	At March 31, 2015, the Company could have physically settled the EFSA by delivering 10,400,000 shares to the forward counterparty in exchange for cash of $272 million. In addition, at March 31, 2015, the Company could have elected to make a cash settlement by paying approximately $114 million, or a net share settlement by delivering approximately 3,074,000 shares of common stock. To the extent that PGE elects a cash or net share settlement, the Company would receive no additional proceeds.
	Prior to settlement, the potentially issuable shares pursuant to the EFSA are reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period are increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period).

Contingencies_Notes

Contingencies (Notes)	3 Months Ended
	Mar. 31, 2015
Contingencies [Abstract]
CONTINGENCIES	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. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.
	Loss contingencies are accrued, and disclosed if material, 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 the estimate or range of potential loss is material. 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 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.
	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 are 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 Class Actions
	In 1993, PGE closed the Trojan nuclear power plant (Trojan) and sought full recovery of, and a rate of return on, its Trojan costs in a general rate case filing with the OPUC. In 1995, the OPUC issued a general rate order that granted the Company recovery of, and a rate of return on, 87% of its remaining investment in Trojan.
	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 2007, following several appeals by various parties, the Oregon Court of Appeals issued an opinion that remanded the matter to the OPUC for reconsideration.
	In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds of $33 million, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in February 2013 and by the Oregon Supreme Court in October 2014.
	In 2003, in two separate legal proceedings, lawsuits were filed in Marion County Circuit Court against PGE on behalf of two classes of electric service customers. The class action lawsuits seek damages totaling $260 million, plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan.
	In 2006, the Oregon Supreme Court issued a ruling ordering the abatement of the class action proceedings. The Oregon Supreme Court concluded that the OPUC had primary jurisdiction to determine what, if any, remedy could be offered to PGE customers, through price reductions or refunds, for any amount of return on the Trojan investment that the Company collected in prices.
	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.
	The October 2014 Oregon Supreme Court decision (referred to above) expressly noted that the plaintiffs in the class action must address any request to lift the abatement with the Marion County Circuit Court. PGE is evaluating how to proceed with respect to the class actions.
	PGE believes that the October 2, 2014 Oregon Supreme Court decision has reduced the risk of a loss to the Company in excess of the amounts previously recorded and discussed above. However, because the class actions remain pending, management believes that it is reasonably possible that such a loss to the Company could result. As these matters involve unsettled legal theories and have a broad range of potential outcomes, sufficient information is currently not available to determine the amount of any such loss.
	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. Although the original decision of the FERC terminated the proceeding and denied the claims for refunds, upon appeal of the decision to the U.S. Ninth Circuit Court of Appeals (Ninth Circuit), the Ninth Circuit remanded the case to the FERC to, among other things, address market manipulation evidence in detail and account for the evidence in any future orders regarding the award or denial of refunds in the proceedings.
	In response to the Ninth Circuit remand, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. The orders 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 either by: i) a showing that a respondent had violated a contract or tariff and that the violation had a direct connection to the rate charged under the applicable contract; or ii) a showing that the contract rate at issue imposed an excessive burden or seriously harmed the public interest. The FERC also expanded the scope of the hearing to allow parties to pursue refunds for transactions between January 1, 2000 and December 24, 2000 under Section 309 of the Federal Power Act by showing violations of a filed tariff or rate schedule or of a statutory requirement. The 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. Refund claimants filed petitions for appeal of these procedural orders with the Ninth Circuit.
	Pursuant to a FERC-ordered settlement process, the Company received notice of two claims and reached agreements to settle both claims for an immaterial amount. The FERC approved both settlements during 2012.
	Additionally, 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 2007, resolved all claims between PGE and the California parties named in the settlement, including the California Energy Resource Scheduling division of the California Department of Water Resources (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.
	The above-referenced settlements resulted in a release for the Company as a named respondent in the first phase of the remand proceedings, which are limited to initial and direct claims for refunds, but there remains a possibility that additional claims related to this matter could be asserted against the Company in a subsequent phase of the proceeding if refunds are ordered against some or all of the current respondents.
	During the first phase of the remand hearing, now completed, two sets of refund proponents, the City of Seattle, Washington (Seattle) and various California parties on behalf of CERS, presented cases alleging that multiple respondents had engaged in unlawful activities and caused severe financial harm that justified the imposition of refunds. After conclusion of the hearing, the presiding Administrative Law Judge issued an Initial Decision on March 28, 2014 finding: i) that Seattle did not carry its Mobile-Sierra burden with respect to its refund claims against any of its respondent sellers; and ii) that the California representatives of CERS did not carry their Mobile-Sierra burden with respect to one of two CERS’ respondents, but that CERS had produced evidence that the remaining CERS respondent had engaged in unlawful activity in the implementation of multiple transactions and bad faith in the formation of as many as 119 contracts. The Administrative Law Judge scheduled a second phase of the hearing to commence after a final FERC decision on the Initial Decision. The Administrative Law Judge determined that in the second phase the remaining respondent will have an opportunity to produce additional evidence as to why its transactions should be considered legitimate and why refunds should not be ordered. The findings in the Initial Decision are subject to further FERC action. If the FERC requires one or more respondents to make refunds, it is possible that such respondent(s) will attempt to recover similar refunds from their suppliers, including the Company.
	Management believes that this matter could result in a loss to the Company in future proceedings. However, management cannot predict whether the FERC will order refunds from any of the current respondents, which contracts would be subject to refunds, the basis on which refunds would be ordered, or how such refunds, if any, would be calculated. Further, management cannot predict whether any current respondents, if ordered to make refunds, will pursue additional refund claims against their suppliers, and, if so, what the basis or amounts of such potential refund claims against the Company would be. Due to these uncertainties, sufficient information is currently not available to determine PGE’s liability, if any, or to estimate a range of reasonably possible loss.
	EPA Investigation of Portland Harbor
	In 1997, an investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as 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 (CERCLA) 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. In 2008, the EPA requested information from various parties, including PGE, concerning additional properties in or near the original segment of the river under investigation as well as several miles beyond. Subsequently, the EPA has listed additional PRPs, which now number over one hundred.
	The Portland Harbor site continues to undergo a remedial investigation (RI) and feasibility study (FS) pursuant to an Administrative Order on Consent (AOC) between the EPA and several PRPs known as the Lower Willamette Group (LWG), which does not include PGE.
	In 2012, the LWG submitted a draft FS to the EPA for review and approval. The draft FS, which is being rewritten by the EPA, along with the RI, will provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision, which the EPA is not expected to issue before 2017.
	The draft FS evaluates several alternative clean-up approaches, which would take from two to 28 years with costs ranging from $169 million to $1.8 billion, depending on the selected remedial action levels and the choice of remedy. The draft FS does not address responsibility for the costs of clean-up, allocate such costs among PRPs, or define precise boundaries for the clean-up. Responsibility for funding and implementing the EPA’s selected clean-up will be determined after the issuance of the Record of Decision.
	Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties discussed above, sufficient information is currently not available to determine PGE’s liability for the cost of any required investigation or remediation of the Portland Harbor site or to estimate a range of potential loss.
	DEQ Investigation of Downtown Reach
	The Oregon Department of Environmental Quality (DEQ) has executed a memorandum of understanding with the EPA to administer and enforce clean-up activities for portions of the Willamette River that are upriver from the Portland Harbor Superfund site (the Downtown Reach). In 2010, the DEQ issued an order requiring PGE to perform an investigation of certain portions of the Downtown Reach. PGE completed this investigation in 2011 and entered into a consent order with the DEQ in 2012 to conduct a feasibility study of alternatives for remedial action for the portions of the Downtown Reach that were included within the scope of PGE’s investigation.
	Following the DEQ’s evaluation of a draft feasibility study, PGE submitted a final feasibility study report to the DEQ in September 2014, which describes possible remediation alternatives that range in estimated cost from $3 million to $8 million. Using the Company’s best estimate of the probable cost for the remediation effort from the set of alternatives provided in the feasibility study report, PGE has a $3 million reserve for this matter as of March 31, 2015.
	The Company also has a regulatory asset of $3 million for future recovery in prices as of March 31, 2015. The final order issued by the OPUC in the 2015 GRC includes revenues to offset the amortization of the regulatory asset over a two year period that began January 1, 2015. The 2016 GRC provides for the possibility of revising the recovery if costs vary from what was estimated.
	EPA Regulation of Coal Combustion Residuals
	In December 2014, the EPA signed a final rule, which becomes effective six months after its April 17, 2015 publication in the Federal Register, that regulates Coal Combustion Residuals (CCRs) under the Resource Conservation and Recovery Act. Based on a preliminary evaluation, the Company believes the rule will not have a material effect on operations at Boardman, which produce dry CCRs. Disposal of the dry CCRs occurs at an on-site landfill that is currently permitted and regulated by the State of Oregon under requirements similar to the new CCR rule.
	The Company believes, however, that this rule will have some effect on operations at Colstrip, which produce wet CCRs. Colstrip utilizes wet scrubbers and a number of settlement ponds that will require upgrading or closure to meet the new regulatory requirements. The extent of the impact to Colstrip remains unclear as the operator of Colstrip has indicated that the financial and operational impact cannot yet be predicted. If PGE were to incur incremental costs as a result of the new rule, the Company would seek recovery in customer prices.
	Alleged Violation of Environmental Regulations at Colstrip
	In July 2012, PGE received a Notice of Intent to Sue (Notice) for violations of the Clean Air Act (CAA) at Colstrip Steam Electric Station (CSES) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC). The Notice was also addressed to the other CSES co-owners, including PPL Montana, LLC, the operator of CSES. PGE has a 20% ownership interest in Units 3 and 4 of CSES. The Notice alleged certain violations of the CAA, including New Source Review, Title V, and opacity requirements, and stated that the Sierra Club and MEIC would: i) request a United States District Court to impose injunctive relief and civil penalties; ii) require a beneficial environmental project in the areas affected by the alleged air pollution; and iii) seek reimbursement of Sierra Club’s and MEIC’s costs of litigation and attorney’s fees.
	The Sierra Club and MEIC asserted that the CSES owners violated the Title V air quality operating permit during portions of 2008 and 2009 and that the owners have violated the CAA by failing to timely submit a complete air quality operating permit application to the Montana Department of Environmental Quality (MDEQ). The Sierra Club and MEIC also asserted violations of opacity provisions of the CAA.
	On March 6, 2013, the Sierra Club and MEIC sued the CSES co-owners, including PGE, for these and additional alleged violations of various environmental related regulations. The plaintiffs are seeking relief that includes an injunction preventing the co-owners from operating CSES except in accordance with the CAA, the Montana State Implementation Plan, and the plant’s federally enforceable air quality permits. In addition, plaintiffs are seeking civil penalties against the co-owners including $32,500 per day for each violation occurring through January 12, 2009, and $37,500 per day for each violation occurring thereafter.
	In May 2013, the defendants filed a motion to dismiss 36 of 39 claims alleged in the complaint. In September 2013, the plaintiffs filed a motion for partial summary judgment regarding the appropriate method of calculating emission increases. Also in September 2013, the plaintiffs filed an amended complaint that withdrew Title V and opacity claims, added claims associated with two 2011 projects, and expanded the scope of certain claims to encompass approximately 40 additional projects. In July 2014, the court denied both the defendants’ motion to dismiss and the plaintiffs’ motion for partial summary judgment.
	On August 27, 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed on September 26, 2014. The second amended complaint continues to seek injunctive relief, declaratory relief, and civil penalties for alleged violations of the federal Clean Air Act. The plaintiffs state in the second amended complaint that it was filed, in part, to comply with the court’s ruling on the defendants’ motion to dismiss and plaintiffs’ motion for partial summary judgment. Discovery in this matter is ongoing with trial now scheduled for November 2015.
	Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to the uncertainties concerning this matter, PGE cannot predict the outcome or determine whether it would have a material impact on the Company.
	Oregon Tax Court Ruling
	On September 17, 2012, the Oregon Tax Court issued a ruling contrary to an Oregon Department of Revenue (DOR) interpretation and a current Oregon administrative rule, regarding the treatment of wholesale electricity sales. The underlying issue was whether electricity should be treated as tangible or intangible property for state income tax apportionment purposes. The DOR appealed the ruling of the Oregon Tax Court to the Oregon Supreme Court.
	On March 26, 2015, the Oregon Supreme Court issued a decision that reversed the Oregon Tax Court ruling and held electricity to be tangible property. With such reversal, PGE’s potential income tax liability from the 2012 Oregon Tax Court ruling has been eliminated.
	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 business, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact 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.

Guarantees_Notes

Guarantees (Notes)	3 Months Ended
	Mar. 31, 2015
Guarantees [Abstract]
GUARANTEES	GUARANTEES
	PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities. As of March 31, 2015, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

Basis_of_Presentation_Policies

Basis of Presentation (Policies)	3 Months Ended
	Mar. 31, 2015
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations

Balance_Sheet_Components_Polic

Balance Sheet Components (Policies)	3 Months Ended
	Mar. 31, 2015
Balance Sheet Components [Abstract]
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, coal, and oil. Periodically, the Company assesses the realizability of inventory for purposes of determining that inventory is recorded at the lower of average cost or market.
Debt, Policy [Policy Text Block]	PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.
	Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and 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.

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Policies)	3 Months Ended
	Mar. 31, 2015
Fair Value of Financial Instruments [Abstract]
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 condensed consolidated balance sheets, for which it is practicable to estimate fair value as of March 31, 2015 and December 31, 2014, and then classifies these financial assets and liabilities 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 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 that 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 transfers between levels in the fair value hierarchy as of the end of the reporting period for all its financial instruments. 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.
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 condensed consolidated balance sheets and invested in 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 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 domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the reporting date.
	Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. 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 due to the availability of quoted prices for identical assets in an active market as of the reporting date. Principal markets for equity prices include published exchanges such as NASDAQ and the New York Stock Exchange. 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 are directly or indirectly observable in the marketplace.
	Assets and liabilities from price risk management activities are recorded at fair value in PGE’s condensed consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk, and reduce volatility in net variable power costs (NVPC) for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 4, 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 forward commodity prices and interest rates. Substantially all of these inputs 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 commodity forwards, futures 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.
Fair Value Transfer, Policy [Policy Text Block]	Transfers out of Level 3 occur when the significant inputs become more observable, such as when 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. Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.
Debt, Policy [Policy Text Block]	PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.
	Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The fair value of the Company’s FMBs and Pollution Control Bonds is classified as a Level 2 fair value measurement and 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_Policies

Price Risk Management (Policies)	3 Months Ended
	Mar. 31, 2015
Price Risk Management [Abstract]
Derivatives, Policy [Policy Text Block]	PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign currency exchange rate risk in order to reduce volatility in NVPC for its retail customers. These derivative instruments may include forwards, futures, swaps, and option contracts for electricity, natural gas, oil, and foreign currency, which are recorded at fair value on the condensed consolidated balance sheets, with changes in fair value recorded in the condensed consolidated statements of income. In accordance with the ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer the gains and losses from derivative instruments 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. The Company does not engage in trading activities for non-retail purposes.

Contingencies_Policies

Contingencies (Policies)	3 Months Ended
	Mar. 31, 2015
Contingencies [Abstract]
Commitments and Contingencies, Policy [Policy Text Block]	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. The Company may seek regulatory recovery of certain costs that are incurred in connection with such matters, although there can be no assurance that such recovery would be granted.
	Loss contingencies are accrued, and disclosed if material, 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 the estimate or range of potential loss is material. 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 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.
	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 are 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.

Guarantees_Policies

Guarantees (Policies)	3 Months Ended
	Mar. 31, 2015
Guarantees [Abstract]
Guarantees, Indemnifications and Warranties Policies [Policy Text Block]	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.

Balance_Sheet_Components_Table

Balance Sheet Components (Tables)	3 Months Ended
	Mar. 31, 2015
Balance Sheet Components [Abstract]
Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]	The activity in the allowance for uncollectible accounts is as follows (in millions):
		Three Months Ended March 31,
		2015				2014
	Balance as of beginning of period	$	6			$	6
	Provision, net	2				2
	Amounts written off, less recoveries	(1		)		(1		)
	Balance as of end of period	$	7			$	7
Schedule of Other Current Assets [Table Text Block]	Other current assets consist of the following (in millions):
		March 31,				December 31, 2014
		2015
	Prepaid expenses	$	58			$	39
	Current deferred income tax asset	33				33
	Margin deposits	20				11
	Accrued sales tax refund related to Tucannon River Wind Farm	11				23
	Assets from price risk management activities	7				6
	Other	4				3
	Other current assets	$	133			$	115
Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]	Electric utility plant, net consists of the following (in millions):
		March 31,				December 31,
		2015				2014
	Electric utility plant	$	8,251			$	8,161
	Construction work-in-progress	478				417
	Total cost	8,729				8,578
	Less: accumulated depreciation and amortization	(2,940		)		(2,899		)
	Electric utility plant, net	$	5,789			$	5,679
Schedule of Regulatory Assets and Liabilities [Text Block]	Regulatory assets and liabilities consist of the following (in millions):
		March 31, 2015							December 31, 2014
		Current				Noncurrent			Current			Noncurrent
	Regulatory assets:
	Price risk management	$	100			$	174		$	100		$	121
	Pension and other postretirement plans	—				242			—			247
	Deferred income taxes	—				87			—			86
	Debt issuance costs	—				15			—			15
	Deferred capital projects	14				—			19			—
	Other	11				27			14			25
	Total regulatory assets	$	125			$	545		$	133		$	494
	Regulatory liabilities:
	Asset retirement removal costs	$	—			$	813		$	—		$	804
	Trojan decommissioning activities	22				29			23			34
	Asset retirement obligations	—				40			—			39
	Other	37				29			37			29
	Total regulatory liabilities	$	59		*	$	911		$	60	*	$	906
	*	Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets.
Other Liabilities Disclosure [Text Block]	Accrued expenses and other current liabilities consist of the following (in millions):
		March 31,				December 31, 2014
		2015
	Regulatory liabilities—current	$	59			$	60
	Accrued employee compensation and benefits	39				51
	Accrued interest payable	40				26
	Accrued dividends payable	22				23
	Accrued taxes payable	26				22
	Other	57				54
	Total accrued expenses and other current liabilities	$	243			$	236
Pension and Other Postretirement Benefits Disclosure [Text Block]	Components of net periodic benefit cost are as follows for the three months ended March 31 (in millions):
		Defined Benefit							Other Postretirement
		Pension Plan							Benefits
		2015				2014			2015			2014
	Service cost	$	4			$	4		$	1		$	—
	Interest cost	8				9			1			1
	Expected return on plan assets	(10		)		(10		)	—			—
	Amortization of net actuarial loss	5				4			—			—
	Net periodic benefit cost	$	7			$	7		$	2		$	1

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments (Tables)	3 Months Ended
	Mar. 31, 2015
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 March 31, 2015
		Level 1			Level 2			Level 3			Total
	Assets:
	Nuclear decommissioning trust: (1)
	Money market funds	$	—		$	65		$	—		$	65
	Debt securities:
	Domestic government	4			10			—			14
	Corporate credit	—			11			—			11
	Non-qualified benefit plan trust: (2)
	Equity Securities:
	Domestic	5			1			—			6
	International	1			—			—			1
	Assets from price risk management activities: (1) (3)
	Electricity	—			5			2			7
	Natural gas	—			2			—			2
		$	10		$	94		$	2		$	106
	Liabilities—Liabilities from price risk management
	activities: (1) (3)
	Electricity	$	—		$	24		$	114		$	138
	Natural gas	—			109			36			145
		$	—		$	133		$	150		$	283
	-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 $27 million, which are recorded at cash surrender value.
	-3	For further information, see Note 4, Price Risk Management.
		As of December 31, 2014
		Level 1			Level 2			Level 3			Total
	Assets:
	Nuclear decommissioning trust: (1)
	Money market funds	$	—		$	65		$	—		$	65
	Debt securities:
	Domestic government	7			7			—			14
	Corporate credit	—			11			—			11
	Non-qualified benefit plan trust: (2)
	Equity securities:
	Domestic	4			1			—			5
	International	1			—			—			1
	Assets from price risk management activities: (1) (3)
	Electricity	—			4			1			5
	Natural gas	—			2			—			2
		$	12		$	90		$	1		$	103
	Liabilities—Liabilities from price risk management
	activities: (1) (3)
	Electricity	$	—		$	32		$	80		$	112
	Natural gas	—			95			21			116
		$	—		$	127		$	101		$	228
	-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 $26 million, which are recorded at cash surrender value.
	-3	For further information, see Note 4, Price Risk Management.
Fair Value, Option, Quantitative Disclosures [Table Text Block]	Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:
									Valuation Technique	Significant Unobservable Input		Price per Unit
			Fair Value													Weighted Average
	Commodity Contracts		Assets			Liabilities						Low		High
			(in millions)
	As of March 31, 2015:
	Electricity physical forward		$	—		$	112		Discounted cash flow	Electricity forward price (per MWh)		$	10.97	$	95.47	$	33.11
	Natural gas financial swaps		—			36			Discounted cash flow	Natural gas forward price (per Decatherm)		2.48		4.36		2.94
	Electricity financial futures		2			2			Discounted cash flow	Electricity forward price (per MWh)		10.97		34.63		22.82
			$	2		$	150
	As of December 31, 2014:
	Electricity physical forward		$	—		$	77		Discounted cash flow	Electricity forward price (per MWh)		$	11.97	$	122.72	$	37.43
	Natural gas financial swaps		—			21			Discounted cash flow	Natural gas forward price (per Decatherm)		2.88		4.86		3.41
	Electricity financial futures		1			3			Discounted cash flow	Electricity forward price (per MWh)		11.97		39.26		27.88
			$	1		$	101
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):
		Three Months Ended March 31,
		2015			2014
	Balance as of the beginning of the period	$	100		$	139
	Net realized and unrealized losses (gains)*	50			(11		)
	Transfers out of Level 3 to Level 2	(2		)	3
	Balance as of the end of the period	$	148		$	131
	*	Contains nominal amounts of realized losses. Both realized and unrealized losses (gains) are recorded in Purchased power and fuel expense in the condensed consolidated statements of income of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions.

Price_Risk_Management_Tables

Price Risk Management (Tables)	3 Months Ended
	Mar. 31, 2015
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions):
		March 31,			December 31,
		2015			2014
	Current assets:
	Commodity contracts:
	Electricity	$	5		$	4
	Natural gas	2			2
	Total current derivative assets	7		(1)	6			(1)
	Noncurrent assets:
	Commodity contracts:
	Electricity	2			1
	Total noncurrent derivative assets	2		(2)	1			(2)
	Total derivative assets not designated as hedging instruments	$	9		$	7
	Total derivative assets	$	9		$	7
	Current liabilities:
	Commodity contracts:
	Electricity	$	47		$	54
	Natural gas	60			52
	Total current derivative liabilities	107			106
	Noncurrent liabilities:
	Commodity contracts:
	Electricity	91			58
	Natural gas	85			64
	Total noncurrent derivative liabilities	176			122
	Total derivative liabilities not designated as hedging instruments	$	283		$	228
	Total derivative liabilities	$	283		$	228
	-1	Included in Other current assets on the condensed consolidated balance sheets.
	-2	Included in Other noncurrent assets on the condensed consolidated balance sheets.
Schedule of Derivative Instruments [Table Text Block]	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 through 2035, were as follows (in millions):
		March 31, 2015				December 31, 2014
	Commodity contracts:
	Electricity	15		MWh		16			MWh
	Natural gas	126		Decatherms		127			Decatherms
	Foreign currency	$	7	Canadian		$	7		Canadian
Price Risk Management Assets and Liabilities Subject to Master Netting Agreements [Table Text Block]	Price risk management liabilities subject to master netting agreements is as follows (in millions):
											Gross Amounts Not Offset in
		Gross Amounts Recognized			Gross Amounts Offset				Net Amounts Presented		Condensed Consolidated
											Balance Sheets					Net Amount
											Derivatives			Cash Collateral(1)
	As of March 31, 2015:
	Liabilities:
	Commodity contracts:
	Electricity(2)	$	91		$	—			$	91	$	(91	)	$	—	$	—
	Natural gas(2)	16			—				16		(16		)	—		—
		$	107		$	—			$	107	$	(107	)	$	—	$	—
	As of December 31, 2014:
	Liabilities:
	Commodity contracts:
	Electricity(2)	$	55		$	—			$	55	$	(55	)	$	—	$	—
	Natural gas(2)	17			—				17		(17		)	—		—
		$	72		$	—			$	72	$	(72	)	$	—	$	—
	-1	As of March 31, 2015 and December 31, 2014, PGE had posted collateral in the amount of $15 million and $11 million, respectively, which consisted entirely of letters of credit.
	-2	Included in Liabilities from price risk management activities—current and Liabilities from price risk management activities—noncurrent.
Schedule of Other Derivatives Not Designated as Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are recorded in Purchased power and fuel in the condensed consolidated statements of income and were as follows (in millions):
		Three Months Ended March 31,
		2015			2014
	Commodity contracts:
	Electricity	$	41		$	9
	Natural Gas	44			(36		)
	Net unrealized and certain net realized losses (gains) presented in the preceding table are offset within the condensed consolidated statements of income by the effects of regulatory accounting.
Schedule of Price Risk Derivatives [Table Text Block]	Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2015 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):
		2015			2016				2017		2018			2019		Thereafter		Total
	Commodity contracts:
	Electricity	$	35		$	22			$	6	$	6		$	6	$	56	$	131
	Natural gas	43			64				30		6			—		—		143
	Net unrealized loss	$	78		$	86			$	36	$	12		$	6	$	56	$	274
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:
		March 31,		December 31,
		2015		2014
	Assets from price risk management activities:
	Counterparty A	67	%	63	%
	Counterparty B	8		14
		75	%	77	%
	Liabilities from price risk management activities:
	Counterparty C	31	%	22	%
	Counterparty D	9		12
		40	%	34	%

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):
		Three Months Ended March 31,
		2015	2014
	Weighted-average common shares outstanding—basic	78,271	78,992
	Dilutive effect of potential common shares	3,195	1,164
	Weighted-average common shares outstanding—diluted	81,466	80,156

Equity_Tables

Equity (Tables)	3 Months Ended
	Mar. 31, 2015
Equity [Abstract]
Schedule of Stockholders Equity [Table Text Block]	The activity in equity during the three months ended March 31, 2015 and 2014 is as follows (dollars in millions):
		Common Stock				Accumulated			Retained
						Other			Earnings
						Comprehensive
		Shares	Amount			Loss
	Balances as of December 31, 2014	78,228,339	$	918		$	(7	)	$	1,000
	Issuances of shares pursuant to equity-based plans	116,352	1			—			—
	Stock-based compensation	—	(1		)	—			—
	Dividends declared	—	—			—			(22		)
	Net income	—	—			—			50
	Balances as of March 31, 2015	78,344,691	$	918		$	(7	)	$	1,028
	Balances as of December 31, 2013	78,085,559	$	911		$	(5	)	$	913
	Issuances of shares pursuant to equity-based plans	96,497	—			—			—
	Stock-based compensation	—	1			—			—
	Dividends declared	—	—			—			(22		)
	Net income	—	—			—			58
	Balances as of March 31, 2014	78,182,056	$	912		$	(5	)	$	949

Basis_of_Presentation_Details

Basis of Presentation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
	retail_customers
	sqmi
Basis of Presentation [Abstract]
Increase (Decrease) in Inventories	$13	($2)
Service Area Sq Miles	4,000
Incorporated Cities	52
Number of Retail Customers	844,393
Service Area Population	1.8
Percent of State's Population	46.00%
Other Comprehensive Income	$0	$0

Balance_Sheet_Components_Allow

Balance Sheet Components Allowance for Uncollectible Accounts (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Allowance for Uncollectible Accounts
Balance as of begining of period	$6	$6
Provision, net	2	2
Amounts written off, less recoveries	-1	-1
Balance as of end of period	$7	$7

Balance_Sheet_Components_Other

Balance Sheet Components Other Current Assets (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Other Current Assets [Line Items]
Prepaid expenses	$58	$39
Current deferred income tax asset	33	33
Margin deposits	20	11
Accrued sales tax refund related to Tucannon River Wind Farm	11	23
Assets from price risk management activities	7	6
Other	4	3
Other current assets	$133	$115

Balance_Sheet_Components_Elect

Balance Sheet Components Electric Utility Plant, Net (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Property, Plant and Equipment [Line Items]
Electric utility plant	$8,251	$8,161
Construction work-in-progress	478	417
Total cost	8,729	8,578
Less: accumulated depreciation and amortization	-2,940	-2,899
Electric utility plant, net	$5,789	$5,679

Balance_Sheet_Components_Regul

Balance Sheet Components Regulatory Assets and Liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Current Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	$100	$100
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Debt issuance costs	0	0
Deferred capital projects	14	19
Other	11	14
Total regulatory assets	125	133
Noncurrent Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	174	121
Pension and other postretirement plans	242	247
Deferred income taxes	87	86
Debt issuance costs	15	15
Deferred capital projects	0	0
Other	27	25
Total regulatory assets	545	494
Current Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	0	0
Trojan decommissioning activities	22	23
Asset retirement obligations	0	0
Other	37	37
Total regulatory liabilities	59	60
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	813	804
Trojan decommissioning activities	29	34
Asset retirement obligations	40	39
Other	29	29
Total regulatory liabilities	$911	$906

Balance_Sheet_Components_Other1

Balance Sheet Components Other Current Liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Regulatory liabilitiesbcurrent	$59	$60
Accrued employee compensation and benefits	39	51
Accrued interest payable	40	26
Accrued dividends payable	22	23
Accrued taxes payable	26	22
Other	57	54
Total accrued expenses and other current liabilities	$243	$236

Balance_Sheet_Components_Pensi

Balance Sheet Components Pension and Other Postretirement Benefits (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$4	$4
Interest cost	8	9
Expected return on plan assets	-10	-10
Amortization of net actuarial loss	5	4
Net periodic benefit cost	7	7
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	0
Interest cost	1	1
Expected return on plan assets	0	0
Amortization of net actuarial loss	0	0
Net periodic benefit cost	$2	$1

Balance_Sheet_Components_Detai

Balance Sheet Components (Details) (USD $)	3 Months Ended		0 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	22-May-15	Jan. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	21-May-15	19-May-15
Valuation and Qualifying Accounts Disclosure [Line Items]
Allowance for Doubtful Accounts Receivable, Current	$7,000,000	$7,000,000			$6,000,000	$6,000,000
Finite-Lived Intangible Assets, Accumulated Amortization	200,000,000				191,000,000
Amortization of Intangible Assets	9,000,000	6,000,000
Syndicated credit facility scheduled to expire in 2018	500,000,000
Line of Credit Facility, Current Borrowing Capacity	500,000,000				700,000,000
Debt Instrument, Covenant Description	0.65
Ratio of Indebtedness to Net Capital	0.559
Short-term Debt	0
Borrowings	46,000,000
Line of Credit Facility, Remaining Borrowing Capacity	454,000,000
Letters of Credit Outstanding, Amount	30,000,000
Letters of credit issued	58,000,000
Authorized Short-Term Debt	900,000,000
Debt Instrument, Interest Rate, Stated Percentage	3.46%			3.55%
Extinguishment of Debt, Amount	120,000,000	0
[Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Proceeds from Issuance of Long-term Debt	75,000,000
Long-term Debt [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Extinguishment of Debt, Amount	70,000,000
Notes Payable to Banks [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Extinguishment of Debt, Amount	50,000,000
Subsequent Event [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Debt Instrument, Interest Rate, Stated Percentage							6.80%	3.50%
Extinguishment of Debt, Amount			67,000,000
Subsequent Event [Member] | [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Proceeds from Issuance of Long-term Debt								70,000,000

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Nuclear decommissioning trust: (1)
Money market funds	$65	$65
Debt securities:
Domestic government	14	14
Corporate credit	11	11
Equity securities:
Domestic	6	5
International	1	1
Assets from price risk management activities: (1) (3)
Electricity	7	5
Natural gas	2	2
Total	106	103
Liabilities from price risk management activities: (1) (3)
Electricity	138	112
Natural gas	145	116
Total	283	228
Fair Value, Inputs, Level 1 [Member]
Nuclear decommissioning trust: (1)
Money market funds	0	0
Debt securities:
Domestic government	4	7
Corporate credit	0	0
Equity securities:
Domestic	5	4
International	1	1
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	10	12
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Nuclear decommissioning trust: (1)
Money market funds	65	65
Debt securities:
Domestic government	10	7
Corporate credit	11	11
Equity securities:
Domestic	1	1
International	0	0
Assets from price risk management activities: (1) (3)
Electricity	5	4
Natural gas	2	2
Total	94	90
Liabilities from price risk management activities: (1) (3)
Electricity	24	32
Natural gas	109	95
Total	133	127
Fair Value, Inputs, Level 3 [Member]
Nuclear decommissioning trust: (1)
Money market funds	0	0
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Equity securities:
Domestic	0	0
International	0	0
Assets from price risk management activities: (1) (3)
Electricity	2	1
Natural gas	0	0
Total	2	1
Liabilities from price risk management activities: (1) (3)
Electricity	114	80
Natural gas	36	21
Total	$150	$101

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Low [Member]
Commodity Contracts
Electricity physical forward	$10.97	$11.97
Natural gas financial swaps	2.48	2.88
Electricity financial futures	10.97	11.97
High [Member]
Commodity Contracts
Electricity physical forward	95.47	122.72
Natural gas financial swaps	4.36	4.86
Electricity financial futures	34.63	39.26
Weighted Average [Member]
Commodity Contracts
Electricity physical forward	33.11	37.43
Natural gas financial swaps	2.94	3.41
Electricity financial futures	22.82	27.88
Assets [Member]
Commodity Contracts
Electricity physical forward	0	0
Natural gas financial swaps	0	0
Electricity financial futures	2,000,000	1,000,000
Total commodity contracts	2,000,000	1,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forward	112,000,000	77,000,000
Natural gas financial swaps	36,000,000	21,000,000
Electricity financial futures	2,000,000	3,000,000
Total commodity contracts	$150,000,000	$101,000,000

Fair_Value_of_Financial_Instru5

Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$100	$139
Net realized and unrealized losses (gains)	50	-11
Transfers out of Level 3 to Level 2	-2	-3
Balance as of the end of the period	$148	$131

Fair_Value_of_Financial_Instru6

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers, Net	$0	$0
Cash Surrender Value, Fair Value Disclosure	27,000,000		26,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Long-term Debt	2,456,000,000		2,501,000,000
Long-term Debt, Fair Value	2,929,000,000		2,901,000,000
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	2,674,000,000		2,596,000,000
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Long-term Debt, Fair Value	$255,000,000		$305,000,000

Price_Risk_Management_Fair_val

Price Risk Management Fair values of price risk management assets and liabilities (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Current Assets, Commodity Contracts:
Electricity	$5	$4
Natural gas	2	2
Total current derivative assets	7	6
Noncurrent Assets, Commodity Contracts: [Abstract]
Electricity	2	1
Total noncurrent derivative assets	2	1
Total derivative assets not designated as hedging instruments	9	7
Total derivative assets	9	7
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	47	54
Natural gas	60	52
Total current derivative liabilities	107	106
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	91	58
Natural gas	85	64
Total noncurrent derivative liabilities	176	122
Total derivative liabilities not designated as hedging instruments	283	228
Total derivative liabilities	$283	$228

Price_Risk_Management_Net_volu

Price Risk Management Net volumes related to price risk management activities (Details) (CAD)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified	MMBTU	MWh
	MWh	MMBTU
Commodity contracts:
Electricity	15,000,000	16,000,000
Natural gas	126,000,000	127,000,000
Foreign currency	7	7

Price_Risk_Management_Price_Ri

Price Risk Management Price Risk Management assets and liabilities subject to master netting agreements (Details) (USD $)	Mar. 31, 2015	Dec. 31, 2014
In Millions, unless otherwise specified
Electricity [Member] | Energy Related Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	$91	$55
Electricity [Member] | Gross amounts offset [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Electricity [Member] | net amount presented [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	91	55
Electricity [Member] | Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	91	55
Electricity [Member] | Securities Pledged as Collateral [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Electricity [Member] | Commodity Contract [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Natural Gas [Member] | Energy Related Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	16	17
Natural Gas [Member] | Gross amounts offset [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Natural Gas [Member] | net amount presented [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	16	17
Natural Gas [Member] | Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	16	17
Natural Gas [Member] | Securities Pledged as Collateral [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Natural Gas [Member] | Commodity Contract [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Liabilities, Total [Member] | Energy Related Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	107	72
Liabilities, Total [Member] | Gross amounts offset [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Liabilities, Total [Member] | net amount presented [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	107	72
Liabilities, Total [Member] | Derivative [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	107	72
Liabilities, Total [Member] | Securities Pledged as Collateral [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	0	0
Liabilities, Total [Member] | Commodity Contract [Member]
Price Risk Management assets and liabilities subject to master netting agreements [Line Items]
Derivative Liability, Fair Value, Net	$0	$0

Price_Risk_Management_Net_real

Price Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Commodity contracts:
Electricity	$41	$9
Natural Gas	$44	($36)

Price_Risk_Management_Future_Y

Price Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) (USD $)	Mar. 31, 2015
In Millions, unless otherwise specified
Electricity [Member]
Commodity contracts:
2015	$35
2016	22
2017	6
2018	6
2019	6
Thereafter	56
Total	131
Natural Gas [Member]
Commodity contracts:
2015	43
2016	64
2017	30
2018	6
2019	0
Thereafter	0
Total	143
Net Unrealized Loss [Member]
Commodity contracts:
2015	78
2016	86
2017	36
2018	12
2019	6
Thereafter	56
Total	$274

Price_Risk_Management_Counterp

Price Risk Management Counterparties Representing 10% or More (Details)	Mar. 31, 2015	Dec. 31, 2014
Assets from price risk management activities:
Counterparty A	67.00%	63.00%
Counterparty B	8.00%	14.00%
Total	75.00%	77.00%
Liabilities from price risk management activities:
Counterparty C	31.00%	22.00%
Counterparty D	9.00%	12.00%
Total	40.00%	34.00%

Price_Risk_Management_Price_Ri1

Price Risk Management Price Risk Management (Details) (USD $)	3 Months Ended
In Millions, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Collateral, Master Netting Arrangements, Letters of Credit	$15		$11
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	83	12
Derivative, Net Liability Position, Aggregate Fair Value	274
Collateral Posted, Aggregate Fair Value	62
Letters of Credit Outstanding, Amount	52
Restricted Cash and Cash Equivalents, Current	10
Collateral cash requirement	261
Cash	$10

Earnings_Per_Share_Components_

Earnings Per Share Components of Earnings Per Share (Details)	3 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Weighted-average common shares outstanding - basic	78,271	78,992
Dilutive effect of potential common shares	3,195	1,164
Weighted-average common shares outstanding - diluted	81,466	80,156

Earnings_Per_Share_Earnings_Pe

Earnings Per Share Earnings Per Share (Details)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Earnings Per Share [Abstract]
Unvested performance-based restricted stock units and associated dividend equivalent rights	303,000	363,000

Schedule_of_Equity_Details

Schedule of Equity (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Mar. 31, 2014
Common Stock, Shares, Outstanding beginning of period	78,228,339
Stockholders' Equity	$1,911
Net Income	50	58
Common Stock, Shares, Outstanding end of period	78,344,691
Stockholders' Equity	1,939
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	78,228,339	78,085,559
Issuances of shares pursuant to equity-based plans	116,352	96,497
Common Stock, Shares, Outstanding end of period	78,344,691	78,182,056
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	1	0
Adjustments Related to Tax Withholding for Share-based Compensation	-1
Stockholders' Equity	918	911
Stock-based compensation		1
Dividends declared	0	0
Stockholders' Equity	918	912
Accumulated Other Comprehensive Income (Loss) [Member]
Stockholders' Equity	-7	-5
Stock-based compensation	0	0
Dividends declared	0	0
Stockholders' Equity	-7	-5
Retained Earnings [Member]
Stockholders' Equity	1,000	913
Stock-based compensation	0	0
Dividends declared	-22	-22
Net Income	50	58
Stockholders' Equity	$1,028	$949

Equity_Details

Equity (Details) (USD $)	3 Months Ended
In Millions, except Share data, unless otherwise specified	Mar. 31, 2015	Jun. 30, 2013
Equity [Abstract]
Share Price		$29.50
Equity Forward Sale Agreement, Settlement Threshold	10,400,000
Equity Forward Sale Agreement future settlement amount	$272
Option Indexed to Issuer's Equity, Settlement Alternatives, Cash, at Fair Value	114
Net share settlement	3,074,000
Proceeds from Issuance of Common Stock	$0

Contingencies_Details

Contingencies (Details) (USD $)	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Jun. 30, 2013	Dec. 31, 1997	Sep. 30, 2008	Dec. 31, 1993
	claims	claims
Loss Contingencies [Line Items]
Investment in Trojan					87.00%
Refund to customers for Trojan Investment including interest				$33,000,000
Class action damages sought	260,000,000
Loss Contingency, Claims Settled, Number	2
Contracts	119
Site Contingency, Names of Other Potentially Responsible Parties	100		69
Lower estimate of range of cost of Portland Harbor cleanup in total	169,000,000
Upper estimated range of total cost of Portland Harbor cleanup	1,800,000,000
Remediation cost estimate lower range	3,000,000
Remediation cost estimate upper range	8,000,000
Loss Contingency, Estimate of Possible Loss	3,000,000
Regulatory asset for recovery of loss contingencies	3,000,000
Civil Penalty Claim - Per day per violation through January 12, 2009	32,500
Civil Penalty Claim - Per day per violation after January 12, 2009	$37,500
Loss Contingency, Actions Taken by Defendant		36
projects added to plaintiff's suit	2
Loss Contingency, Pending Claims, Number	40	39