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Document and Entity Information - shares	3 Months Ended
Document and Entity Information - shares	Mar. 31, 2016	Apr. 15, 2016
Entity Information [Line Items]
Entity Registrant Name	PORTLAND GENERAL ELECTRIC CO /OR/
Entity Central Index Key	0000784977
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Amendment Flag	false
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		88,900,756
Trading Symbol	POR

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Revenues, net	$ 487	$ 473
Operating expenses:
Purchased power and fuel	149	161
Generation, transmission and distribution	66	62
Administrative and other	61	60
Depreciation and amortization	82	75
Taxes other than income taxes	30	30
Total operating expenses	388	388
Income from operations	99	85
Interest expense, net	27	30
Other income:
Allowance for equity funds used during construction	7	4
Miscellaneous income (expense), net	(1)	1
Other income, net	6	5
Income before income tax expense	78	60
Income tax expense	17	10
Net income and Comprehensive income	$ 61	$ 50
Weighted-average shares outstanding (in thousands):
Basic	88,833	78,271
Diluted	88,833	81,466
Earnings per share:
Basic	$ 0.68	$ 0.64
Diluted	0.68	0.62
Dividends declared per common share	$ 0.30	$ 0.28

Condensed Consolidated Balance Sheets (Unaudited) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Current assets:
Cash and cash equivalents	$ 4,000,000	$ 4,000,000
Accounts receivable, net	130,000,000	158,000,000
Unbilled revenues	77,000,000	95,000,000
Inventories	82,000,000	83,000,000
Regulatory assets - current	131,000,000	129,000,000
Other current assets	113,000,000	88,000,000
Total current assets	537,000,000	557,000,000
Electric utility plant, net	6,160,000,000	6,012,000,000
Regulatory assets - noncurrent	526,000,000	524,000,000
Nuclear decommissioning trust	41,000,000	40,000,000
Non-qualified benefit plan trust	32,000,000	33,000,000
Other noncurrent assets	48,000,000	44,000,000
Total assets	7,344,000,000	7,210,000,000
Current liabilities
Accounts payable	98,000,000	98,000,000
Liabilities from price risk mangement activities - current	142,000,000	130,000,000
Short-term debt	0	6,000,000
Current portion of long-term debt	0	133,000,000
Accrued expenses and other current liabilities	268,000,000	259,000,000
Total current liabilities	508,000,000	626,000,000
Long-term debt, net of current portion	2,199,000,000	2,060,000,000
Regulatory liabilities - noncurrent	938,000,000	928,000,000
Deferred income taxes	646,000,000	632,000,000
Unfunded status of pension and postretirement plans	261,000,000	259,000,000
Liabilities from price risk mangement activities - noncurrent	161,000,000	161,000,000
Asset retirement obligations	152,000,000	151,000,000
Non-qualified benefit plan liabilities	106,000,000	106,000,000
Other noncurrent liabilities	82,000,000	29,000,000
Total liabilities	5,053,000,000	4,952,000,000
Commitments and contingencies (see notes)
Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of March 31, 2016 and December 31, 2015	0	0
Common stock, no par value, 160,000,000 shares authorized; 88,899,359 and 88,792,751 shares issued and outstanding as of March 31, 2016 and December 31, 2015, respectively	1,195,000,000	1,196,000,000
Accumulated other comprehensive loss	(8,000,000)	(8,000,000)
Retained earnings	1,104,000,000	1,070,000,000
Total equity	2,291,000,000	2,258,000,000
Total liabilities and equity	$ 7,344,000,000	$ 7,210,000,000

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Mar. 31, 2016	Dec. 31, 2015
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	88,899,359	88,792,751
Common stock, shares outstanding	88,899,359	88,792,751

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Cash flows from operating activities:
Net income	$ 61	$ 50
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	82	75
Increase in net liabilities from price risk management activities	2	53
Regulatory deferrals-price risk management activities	(2)	(53)
Deferred income taxes	14	10
Pension and other postretirement benefits	7	9
Allowance for equity funds used during construction	(7)	(4)
Other non-cash income and expenses, net	4	5
Changes in working capital:
Decrease in accounts receivable and unbilled revenues	46	37
Decrease (increase) in inventories	1	(13)
Increase in margin deposits, net	(7)	(9)
Decrease in accounts payable and accrued liabilities	(11)	(1)
Other working capital items, net	(16)	(20)
Other, net	(13)	(5)
Net cash provided by operating activities	161	134
Cash flows from investing activities:
Capital expenditures	(131)	(178)
Sales tax refund received related to Tucannon River Wind Farm	0	12
Sales of Nuclear decommissioning trust securities	6	4
Purchases of Nuclear decommissioning trust securities	(6)	(5)
Other, net	(2)	0
Net cash used in investing activities	(133)	(167)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	140	75
Payments on long-term debt	(133)	(120)
Change in short-term debt	(6)	0
Dividends paid	(27)	(22)
Payments on capital leases	(1)	0
Debt issuance costs	(1)	0
Net cash used in financing activities	(28)	(67)
Decrease in cash and cash equivalents	0	(100)
Cash and cash equivalents, beginning of period	4	127
Cash and cash equivalents, end of period	4	27
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	10	14
Non-cash investing and financing activities:
Accrued capital additions	49	62
Accrued dividends payable	28	22
Assets obtained under capital lease	$ 54	$ 0

Basis of Presentation (Notes)	3 Months Ended
Basis of Presentation (Notes)	Mar. 31, 2016
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 is 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, 2016, PGE served 855,573 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 2016 presentation, PGE has reclassified Regulatory deferral of settled derivative instruments of $2 million and Decoupling mechanism deferrals, net amortization of $(3) million to Other non-cash income and expenses, net within the operating activities section of the condensed consolidated statement of cash flows for the three months ended March 31, 2015. In addition, Cash received pursuant to the Residential Exchange Program of $1 million has been reclassified to Other, net in the operating activities section of the condensed consolidated statement of cash flows, for the three months ended March 31, 2015. The financial information included herein for the three months ended March 31, 2016 and 2015 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 income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. The financial information as of December 31, 2015 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2015, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 12, 2016, 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, 2016 and 2015. 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. 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. 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 was originally January 1, 2017 for the Company. In August 2015, the Financial Accounting Standards Board (FASB) issued ASU 2015-14, Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date (ASU 2014-14) that defers the effective date by one year, although it permits early adoption as of the original effective date. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2014-09. In July 2015, the FASB issued ASU 2015-11, Inventory (Topic 330), Simplifying the Measurement of Inventory (ASU 2015-11), which changes the measurement principle for inventory from the lower of cost or market to lower of cost and net realizable value. Net realizable value is defined as the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal and transportation.” ASU 2015-11 eliminates the guidance that entities consider replacement cost or net realizable value less an approximately normal profit margin in the subsequent measurement of inventory when cost is determined on a first-in, first-out or average cost basis. The provisions of ASU 2015-11 are effective for public entities with fiscal years beginning after December 15, 2016, or January 1, 2017 for PGE, and interim periods within those fiscal years. Early adoption is permitted. The Company does not expect the adoption of this guidance to have a material impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows. In January 2016, the FASB issued ASU 2016-01, Financial Instrument-Overall (Subtopic 825-10), Recognition and Measurement of Financial Assets and Financial Liabilities (ASU 2016-01), which enhances the reporting model for certain financial instruments and related disclosures. The main provisions of this ASU affect the accounting for equity investments, financial liabilities under the fair value option, and the presentation and disclosure requirements for financial instruments. This guidance is effective for public entities with fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. Early adoption is permitted, in certain circumstances. The Company does not expect the adoption of this guidance to have a material impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842) which supersedes the current lease accounting requirements for lessees and lessors within Topic 840, Leases. Pursuant to the new standard, lessees will be required to recognize all leases, including operating leases, on the balance sheet and record corresponding right-of-use assets and lease liabilities. Accounting for lessors is substantially unchanged from current accounting principles. Lessees will be required to classify leases as either finance (formerly referred to as capital) leases or operating leases. Initial balance sheet measurement is similar for both types of leases; however, expense recognition and amortization of right-of-use assets will differ. Operating leases will reflect lease expense on a straight-line basis, while finance leases will result in the separate presentation of interest expense on the lease liability (as calculated using the effective interest method) and amortization expense of the right-of-use asset. Quantitative and qualitative disclosures will also be required surrounding significant judgments made by management. The provisions of this pronouncement are effective for calendar year-end, public entities on January 1, 2019 and must be applied on a modified retrospective basis as of the beginning of the earliest comparative period presented. The new standard also provides reporting entities the option to elect a package of practical expedients for existing leases that commenced before the effective date. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-02. In March 2016, the FASB issued ASU 2016-09, Compensation-Stock Compensation (Topic 718), Improvements to Employee Share-Based Payment Accounting (ASU 2016-09), which is designed to simplify the presentation and accounting for certain income tax effects, employer tax withholding requirements, forfeiture assumptions, and statement of cash flows presentation related to share-based payment awards. Under this standard, all excess tax benefits and tax deficiencies should be recognized within the income statement, and excess tax benefits should be recognized regardless of whether the benefit reduces taxes payable in the current period. The update also allows reporting entities to make a policy election regarding its accounting for forfeitures either by estimating the number of awards that are expected to vest or account for forfeitures when they occur. Within the statement of cash flows, this update will now require tax windfalls to be classified along with other income tax cash flows as an operating activity and cash payments made on behalf of employees when directly withholding shares for tax-withholding purposes should be classified as a financing activity. Most of the provisions of this update require transition on a modified retrospective basis by means of a cumulative-effect adjustment to equity as of the beginning of the period in which the guidance is adopted. For calendar year-end public entities, the update will be effective for annual periods beginning January 1, 2017, and interim periods within those annual periods. Early adoption is permitted. The Company is in the process of evaluating the impact to its consolidated financial position, consolidated results of operations, and consolidated cash flows of the adoption of ASU 2016-09. Newly Adopted Accounting Standards In April 2015, the FASB 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 Company has retrospectively adopted the provisions of ASU 2015-03 as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, unamortized debt expense of $12 million and $11 million at March 31, 2016 and December 31, 2015, respectively, have been reclassified from Other noncurrent assets to a deduction of Long-term debt, net of current portion on the condensed consolidated balance sheets. Adoption of this guidance had no impact on the Company’s consolidated results of operations or consolidated cash flows. In August 2015, the FASB issued ASU 2015-15, Interest-Imputation of Interest (Subtopic 835-30): Presentation of Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements-Amendments to SEC Paragraphs Pursuant to Staff Announcement at June 18, 2015 EITF Meeting (SEC Update) (ASU 2015-15), which clarifies that the SEC staff would “not object to an entity deferring and presenting debt issuance costs as an asset and subsequently amortizing the deferred debt issuance costs ratably over the term of the line-of-credit arrangement” given the lack of guidance on this topic in ASU 2015-03. Therefore, as allowed under this update, the Company records debt issuance costs associated with its line-of-credit arrangements as an asset within Other current assets, and amortizes the costs over the term of the agreement. In May 2015, the FASB issued ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent) (ASU 2015-07), which removes the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. The amendments also remove the requirement to make certain disclosures for all investments that are eligible to be measured at fair value using the net asset value per share as a practical expedient. Instead, such disclosures are restricted only to investments that the entity has decided to measure using the practical expedient. The Company has retrospectively adopted the provisions of this update as of January 1, 2016, which was the original effective date for calendar year-end, public entities. As a result, certain investments have been retrospectively reclassified within the Company’s fair value disclosures of its Nuclear decommissioning trust and Non-qualified benefit plan trust. See Note 3, Fair Value of Financial Instruments for more information. The Company also anticipates that adoption of this standard will require certain benefit plan assets to be reclassified in disclosures made in the Company’s Annual Report on Form 10-K. The adoption of this guidance had no impact on the Company’s consolidated financial position, consolidated results of operations, or consolidated cash flows.

Balance Sheet Components (Notes)

3 Months Ended

Mar. 31, 2016

Balance Sheet Components [Abstract]

BALANCE SHEET COMPONENTS

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as 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, 2016		December 31, 2015
Prepaid expenses	$	55	$	43
Margin deposits	40		33
Assets from price risk management activities	18		10
Other	—		2
Other current assets	$	113	$	88

Electric Utility Plant, Net

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



	March 31, 2016			December 31, 2015
Electric utility plant	$	8,663		$	8,560
Construction work-in-progress	647			545
Total cost	9,310			9,105
Less: accumulated depreciation and amortization	(3,150		)	(3,093		)
Electric utility plant, net	$	6,160		$	6,012

Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $238 million and $227 million as of March 31, 2016 and December 31, 2015, respectively. Amortization expense related to intangible assets was $11 million and $9 million for the three months ended March 31, 2016 and 2015, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs.

Capital Lease—PGE has entered into agreements to purchase natural gas transportation capacity to serve the Carty Generating Station (Carty), a 440 MW natural gas-fired baseload resource under construction in eastern Oregon, located adjacent to the Boardman coal-fired generating plant. A new natural gas pipeline, Carty Lateral, was recently completed and is a 24 mile, 20-inch diameter steel pipe, which extends from Ione, Oregon, and terminates at a connection within the Carty facility. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175,000 decatherms per day. At the end of the initial contract term, the Company has the option to renew the agreement in continuous three-year increments with at least 24-months prior written notice. For accounting purposes, this transportation capacity agreement is treated as a capital lease.

As of March 31, 2016, a capital lease asset of $54 million was reflected within Electric utility plant, and accumulated amortization of such assets of $1 million reflected within Accumulated depreciation and amortization in the table above. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $51 million in Other noncurrent liabilities on the condensed consolidated balance sheets, respectively. For ratemaking purposes capital leases are treated as operating leases; therefore, in accordance with the accounting rules for regulated operations, the amortization of the leased asset is based on the rental payments recovered from customers. Also for ratemaking purposes, such rental payments are capitalized to the project during the construction period. Amortization of the leased asset of $1 million and interest expense of $2 million has been capitalized to Construction work-in-progress (CWIP) during the construction period of Carty.

For the remainder of 2016, PGE expects $5 million in minimum lease payments, with $3 million imputed interest and present value of net minimum lease payments of $2 million. As of March 31, 2016, PGE’s estimated future minimum lease payments for the following five years and thereafter are as follows (in millions):



	Payments Due
	2017		2018		2019		2020		2021		Thereafter		Total
Total minimum lease payments	$	6	$	6	$	6	$	6	$	5	$	73	$	102
Less imputed interest													49
Present value of net minimum lease payments													$	53

Regulatory Assets and Liabilities

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



	March 31, 2016					December 31, 2015
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	124		$	159	$	120		$	161
Pension and other postretirement plans	—			235		—			239
Deferred income taxes	—			86		—			86
Debt issuance costs	—			24		—			16
Other	7			22		9			22
Total regulatory assets	$	131		$	526	$	129		$	524
Regulatory liabilities:
Asset retirement removal costs	$	—		$	850	$	—		$	837
Trojan decommissioning activities	21			11		17			15
Asset retirement obligations	—			46		—			45
Other	36			31		38			31
Total regulatory liabilities	$	57	^*	$	938	$	55	^*	$	928


*	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, 2016		December 31, 2015
Regulatory liabilities—current	$	57	$	55
Accrued employee compensation and benefits	42		51
Accrued interest payable	40		25
Accrued dividends payable	28		28
Accrued taxes payable	30		25
Other	71		75
Total accrued expenses and other current liabilities	$	268	$	259

Credit Facilities

As of March 31, 2016, PGE had a $500 million revolving credit facility scheduled to expire in November 2019.

Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, as backup for commercial paper borrowings, and to permit the issuance of standby letters of credit. PGE may borrow for one, two, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. 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, 2016, PGE was in compliance with this covenant with a 49.9% debt-to-total capital ratio.

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

PGE classifies any borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets.

Under the revolving credit facility, as of March 31, 2016, PGE had no borrowings, commercial paper, or letters of credit issued. As of March 31, 2016, the aggregate unused available credit capacity under the revolving credit facility was $500 million.

In addition, PGE has four letter of credit facilities that provide a total of $160 million capacity under which the Company can request letters of credit for original terms not to exceed one year. The issuance of such letters of credit is subject to the approval of the issuing institution. Under these four facilities, $111 million of letters of credit were outstanding, as of March 31, 2016.

Pursuant to an order issued by the Federal Energy Regulatory Commission (FERC), the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2018.

Long-term Debt

During the three months ended March 31, 2016, PGE had the following long-term debt transactions, all of which occurred in early January:


•	Issued $140 million of 2.51% Series First Mortgage Bonds (FMBs) due 2021;


•	Repaid $75 million of 5.80% Series FMBs, due in 2018; and


•	Repaid $58 million of 3.81% Series FMBs, due in 2017.

Due to the anticipated repayment of the $133 million in early January 2016, this amount of long-term debt was classified as current on the Company’s condensed consolidated balance sheets as of December 31, 2015.

Defined Benefit Pension Plan Costs

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):



	Three Months Ended March 31,
	2016			2015
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	4			5
Net periodic benefit cost	$	6		$	7

Fair Value of Financial Instruments (Notes)

3 Months Ended

Mar. 31, 2016

Fair Value of Financial Instruments [Abstract]

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, 2016 and December 31, 2015, and then classifies these financial assets and liabilities based on a fair value hierarchy that is applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy 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. Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 1, Basis of Presentation, assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements, and prior period amounts have been retrospectively reclassified to conform to current presentation.

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 month periods ended March 31, 2016 and 2015, 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, 2016
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	5	$	9	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		19		19
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		11		—		—		11
Natural gas	—		9		—		—		9
	$	9	$	37	$	—	$	22	$	68
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	29	$	117	—		$	146
Natural gas	—		143		14		—		157
	$	—	$	172	$	131	$	—	$	303


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.


(3)	Excludes insurance policies of $25 million, which are recorded at cash surrender value.


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



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 1, Basis of Presentation.


(3)	Excludes insurance policies of $26 million, which are recorded at cash surrender value.


(4)	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:

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 yields 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.

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 not classified in the fair value hierarchy since they are valued at NAV as a practical expedient. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

Common and collective trust funds—PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient.

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 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:



	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
As of March 31, 2016:
Electricity physical forwards	$	—	$	117	Discounted cash flow	Electricity forward price (per MWh)	$	4.25	$	73.32	$	29.16
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	0.90		3.61		2.46
	$	—	$	131
As of December 31, 2015:
Electricity physical forwards	$	—	$	105	Discounted cash flow	Electricity forward price (per MWh)	$	8.50	$	84.47	$	30.69
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	2.06		3.70		2.54
	$	—	$	119

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 bid-ask spread of the market 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 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.

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:

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,
	2016		2015
Balance as of the beginning of the period	$	119	$	100
Net realized and unrealized losses^*	12		50
Transfers out of Level 3 to Level 2	—		(2		)
Balance as of the end of the period	$	131	$	148


*	Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

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, 2016 and 2015, 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 derivative 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 Revenue 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 was classified as Level 3 in the fair value hierarchy and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

As of March 31, 2016, the carrying amount of PGE’s long-term debt was $2,199 million, net of $12 million of unamortized debt expense, and its estimated aggregate fair value was $2,617 million, classified as Level 2 in the fair value hierarchy. As of December 31, 2015, the carrying amount of PGE’s long-term debt was $2,193 million, net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $2,455 million classified as Level 2 in the fair value hierarchy.

- Definition

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

+ References + Details

Price Risk Management (Notes)

3 Months Ended

Mar. 31, 2016

Price Risk Management [Abstract]

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 and manage risk. Such activities include purchases and sales of both power and fuel 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, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, 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 Public Utility Commission of Oregon (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, 2016			December 31, 2015
Current assets:
Commodity contracts:
Electricity	$	11		$	7
Natural gas	7			3
Total current derivative assets	18		⁽¹⁾	10		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Natural gas	2			—
Total noncurrent derivative assets	2		⁽²⁾	—		⁽²⁾
Total derivative assets not designated as hedging instruments	$	20		$	10
Total derivative assets	$	20		$	10
Current liabilities:
Commodity contracts:
Electricity	$	37		$	36
Natural gas	105			94
Total current derivative liabilities	142			130
Noncurrent liabilities:
Commodity contracts:
Electricity	109			97
Natural gas	52			64
Total noncurrent derivative liabilities	161			161
Total derivative liabilities not designated as hedging instruments	$	303		$	291
Total derivative liabilities	$	303		$	291


(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, 2016			December 31, 2015
Commodity contracts:
Electricity	12		MWh	12		MWh
Natural gas	118		Decatherms	124		Decatherms
Foreign currency	$	21	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. As of March 31, 2016 and December 31, 2015, gross amounts included as Price risk management liabilities subject to master netting agreements were $123 million and $111 million, respectively, for which PGE posted collateral of $14 million, which consisted primarily of letters of credit and a nominal amount of cash. As of March 31, 2016, of the gross amounts recognized, $117 million was for electricity and $6 million was for natural gas compared to $104 million for electricity and $7 million for natural gas recognized as of December 31, 2015.

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,
	2016			2015
Commodity contracts:
Electricity	$	25		$	41
Natural Gas	17			44
Foreign currency exchange	$	(1	)	$	—

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 month periods ended March 31, 2016 and 2015, net losses of $34 million and $83 million have been offset, respectively.

Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss recorded as of March 31, 2016 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):



	2016		2017		2018		2019		2020		Thereafter		Total
Commodity contracts:
Electricity	$	24	$	8	$	8	$	8	$	7	$	80	$	135
Natural gas	85		50		11		2		—		—		148
Net unrealized loss	$	109	$	58	$	19	$	10	$	7	$	80	$	283

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, 2016 was $287 million, for which PGE has posted $88 million in collateral, consisting of $64 million in letters of credit and $24 million in cash. If the credit-risk-related contingent features underlying these agreements were triggered at March 31, 2016, the cash requirement to either post as collateral or settle the instruments immediately would have been $256 million. As of March 31, 2016, PGE had posted an additional $15 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, 2016		December 31, 2015
Assets from price risk management activities:
Counterparty A	48	%	59	%
Counterparty B	11		8
Counterparty C	9		10
	68	%	77	%
Liabilities from price risk management activities:
Counterparty D	38	%	36	%
Counterparty B	10		10
Counterparty E	9		10
	57	%	56	%

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.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

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-Subparagraph (SX 210.4-08.(n))
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+ Details

Earnings Per Share (Notes)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the period. Diluted earnings per share are 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) unvested employee stock purchase plan shares; ii) contingently issuable time-based and performance-based restricted stock units, along with associated 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 month periods ended March 31, 2016 and 2015 unvested performance-based restricted stock units and related dividend equivalent rights of approximately 304,000 and 303,000, respectively, were excluded from the dilutive calculation because the performance goals had not been met.

Net income 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,
	2016	2015
Weighted-average common shares outstanding—basic	88,833	78,271
Dilutive effect of potential common shares	—	3,195
Weighted-average common shares outstanding—diluted	88,833	81,466

Equity (Notes)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Equity

EQUITY

The activity in equity during the three months ended March 31, 2016 and 2015 is as follows (dollars in millions):



	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Common Stock
	Shares	Amount									Total
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

Balances as of December 31, 2014	78,228,339	$	918		$	(7	)	$	1,000		$	1,911
Issuances of shares pursuant to equity-based plans	116,352	1			—			—			1
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(22		)	(22		)
Net income	—	—			—			50			50
Balances as of March 31, 2015	78,344,691	$	918		$	(7	)	$	1,028		$	1,939

During the second quarter of 2015, PGE physically settled in full the EFSA, with the issuance of 10,400,000 shares of common stock in exchange for net proceeds of $271 million. Prior to settlement, the potentially issuable shares pursuant to the EFSA were 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).

- Definition

The entire disclosure for shareholders' equity comprised of portions attributable to the parent entity and noncontrolling interest, including other comprehensive income. Includes, but is not limited to, balances of common stock, preferred stock, additional paid-in capital, other capital and retained earnings, accumulated balance for each classification of other comprehensive income and amount of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
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-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.29-31)
-URI http://asc.fasb.org/extlink&oid=6877327&loc=d3e13212-122682

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 4
-Subparagraph (SAB TOPIC 4.C)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187143-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21506-112644

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=6405834&loc=d3e23285-112656

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

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-Publisher FASB
-Name Accounting Standards Codification
-Glossary Preferred Stock
-URI http://asc.fasb.org/extlink&oid=6521494

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
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-Paragraph 2
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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=6928386&loc=d3e21564-112644

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-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section E

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher SEC
-Name Staff Accounting Bulletin (SAB)
-Number Topic 4
-Section C

+ Details

Contingencies (Notes)	3 Months Ended
Contingencies (Notes)	Mar. 31, 2016
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 circumstances in which 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 (OSC) in October 2014. In 2003, in two separate legal proceedings, lawsuits were filed in Marion County Circuit Court (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 August 2006, the OSC issued a ruling ordering the abatement of the class action proceedings. The OSC 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 OSC 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 OSC added that, if the OPUC determined that it cannot provide a remedy, the court system may have a role to play. The OSC also ruled that the plaintiffs retain the right to return to the Circuit Court for disposition of whatever issues remain unresolved from the remanded OPUC proceedings. In October 2006, the Circuit Court abated the class actions in response to the ruling of the OSC. In June 2015, based on a motion filed by PGE, the Circuit Court lifted the abatement and in July 2015, the Circuit Court heard oral argument on the Company’s motion for Summary Judgment. Following oral argument on PGE’s motion for summary judgment, the plaintiffs moved to amend the complaints. PGE opposed the request to amend. On February 22, 2016, the Circuit Court denied the plaintiff’s motion to amend the complaint and on March 16, 2016, the Circuit Court entered a general judgment that granted the Company’s motion for summary judgment and dismissed all claims by the plaintiffs. However, on April 14, 2016, the plaintiffs appealed the Circuit Court dismissal to the Court of Appeals for the State of Oregon. PGE believes that the October 2, 2014 OSC decision and the recent Circuit Court decisions have 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 subject to appeal, 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 response to the Western energy crisis of 2000-2001, the FERC initiated, beginning in 2001, a series of proceedings to determine whether refunds are warranted for bilateral sales of electricity in the Pacific Northwest wholesale spot market during the period December 25, 2000 through June 20, 2001. In an order issued in 2003, the FERC denied refunds. Various parties appealed the order to the Ninth Circuit Court of Appeals (Ninth Circuit) and, on appeal, the Ninth Circuit remanded the issue of refunds to the FERC for further consideration. On remand, in 2011 and thereafter, the FERC issued several procedural orders that established an evidentiary hearing, defined the scope of the hearing, expanded the refund period to include January 1, 2000 through December 24, 2000 for certain types of claims, and described the burden of proof that must be met to justify abrogation of the contracts at issue and the imposition of refunds. Those orders included a finding by the FERC 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 held that a market-wide remedy was not appropriate, given the bilateral contract nature of the Pacific Northwest spot markets. Refund proponents appealed these procedural orders at the Ninth Circuit. On December 17, 2015, the Ninth Circuit held that the FERC reasonably applied the Mobile-Sierra presumption to the class of contracts at issue in the proceedings and dismissed evidentiary challenges related to the scope of the proceeding. Plaintiffs on behalf of the California Energy Resources Scheduling division of the California Department of Water Resources filed a request for rehearing on February 1, 2016. By order issued April 18, 2016, the Ninth Circuit denied plaintiffs’ request for panel rehearing of its decision regarding application of the Mobile-Sierra presumption. In response to the evidence and arguments presented during the hearing, in May 2015, the FERC issued an order finding that the refund proponents had failed to meet the Mobile-Sierra burden with respect to all but one respondent. In December 2015, the FERC denied all requests for rehearing of its order. With respect to the remaining respondent, FERC ordered additional proceedings, and a January 2016 revised initial decision has now recommended that certain contracts by such respondent be subject to refund. The Company has settled all of the direct claims asserted against it in the proceedings for an immaterial amount. The settlements and associated FERC orders have not fully eliminated the potential for so-called “ripple claims,” which have been described by the FERC as “sequential claims against a succession of sellers in a chain of purchases that are triggered if the last wholesale purchaser in the chain is entitled to a refund.” However, the remaining respondent subject to the revised initial decision has stated on the record that it will not pursue ripple claims, and on February 1, 2016, the Acting Chief Administrative Law Judge issued an order holding that the issue of ripple claims is terminated for purposes of Phase II of these proceedings. Therefore, unless the current FERC orders are overturned or modified on appeal, the Company does not believe that it will incur any material loss in connection with this matter. Management cannot predict the outcome of the various pending appeals and remands concerning this matter. If, on rehearing, appeal, or subsequent remand, the Ninth Circuit or the FERC were to reverse previous FERC rulings on liability or find that a market-wide remedy is appropriate, it is possible that additional refund claims could be asserted against the Company. However, management cannot predict, under such circumstances, 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, would 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 A 1997 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 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 remedial investigation (RI) has been completed pursuant to an Administrative Order on Consent 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 feasibility study (FS) to the EPA for review and approval. In August 2015, the EPA substantially revised the draft FS, as submitted by the LWG, and issued its own draft FS, which is currently in the process of undergoing further consideration and comment. The draft FS, along with the RI, is expected to provide the framework for the EPA to determine a clean-up remedy for Portland Harbor that will be documented in a Record of Decision (ROD). The EPA’s draft FS evaluates several alternative clean-up approaches, which would take from four to 18 years with the present value of estimated costs ranging from $800 million to $2.4 billion, depending on the selected remedial action levels and the choice of remedy. While the revised draft FS aids in the development of a proposed plan to remediate Portland Harbor, 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. In November 2015, the EPA proposed its preferred alternative remedy to the National Remedy Review Board for comment. The EPA’s preferred alternative has an estimated present value cost of $1.5 billion and would take approximately seven years to complete. The EPA anticipates it will release, for public review and comment, a Proposed Cleanup Plan in the second quarter of 2016. The Company currently expects the EPA to issue a determination of its preferred remedy in a final ROD in late 2016; however, responsibility for funding and implementing the EPA’s selected remedy is not expected to be known for some time. PGE is participating in a voluntary process to develop a method for allocation of costs. Where injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which is referred to as natural resource damages. As it relates to the Portland Harbor, PGE has been participating in the Portland Harbor Natural Resource Damages assessment (NRDA) process. The EPA does not manage NRDA activities, but provides claims information and coordination support to the Natural Resource Damages (NRD) trustees. Damage assessment activities are typically conducted by a Trustee Council made up of the trustee entities for the site, and claims are not concluded until a final remedy for clean-up has been settled. The Portland Harbor NRD trustees are the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the state of Oregon, and certain tribal entities. After the claimed damages at a site are assessed, the NRD trustees may seek to negotiate legal settlements or take other legal actions against the parties responsible for the damages. Funds from such settlements must be used to restore injured resources and may also compensate the trustees for costs incurred in assessing the damages. It is uncertain what portion, if any, PGE may be held responsible related to Portland Harbor. As discussed above, significant uncertainties still remain concerning the precise boundaries for clean-up, the assignment of responsibility for clean-up costs, the final selection of a proposed remedy by the EPA, the amount of natural resource damages, and the method of allocation of costs amongst PRPs. Although it is probable that the Company’s share of these costs could be material, the Company does not currently have sufficient information to reasonably estimate the amount, or range, of its potential costs for investigation or remediation of the Portland Harbor site and NRDA. The Company plans to seek recovery of any costs resulting from the Portland Harbor proceeding through regulatory recovery in customer prices and through claims under insurance policies. 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 Talen 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. In August 2014, the plaintiffs filed a second amended complaint to which the defendants’ response was filed in September 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. The parties filed various summary judgment motions during the summer of 2015 andon or about December 31, 2015, the Magistrate Judge issued Findings and Recommendations that, if adopted by the trial court, would result in dismissal of several of the plaintiffs’ claims. The parties have reached a preliminary agreement on key terms of a settlement that would resolve the claims raised in this litigation, and accordingly, on April 26, 2016, filed a joint motion to vacate the trial date and stay all deadlines in this case in order to provide the parties a reasonable period of time to develop and finalize appropriate settlement documents. On April 27, 2016, the Court granted the stay until June 28, 2016. In the event the case does not settle by June 28, 2016, the parties shall either move to extend the stay or propose a revised bench trial schedule. The parties anticipate that a final agreement will be reached sometime in the second quarter of 2016. Management believes that it is reasonably possible that this litigation could result in a loss to the Company. However, due to the uncertainties concerning this litigation, including the outcome of the foregoing settlement discussions, PGE cannot predict the outcome or estimate a range of potential loss. 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 that 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)	3 Months Ended
Guarantees (Notes)	Mar. 31, 2016
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, 2016, 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.

Carty Generating Station (Notes)	3 Months Ended
Carty Generating Station (Notes)	Mar. 31, 2016
Carty Generating Station [Abstract]
contractors [Text Block]	CARTY GENERATING STATION The Company is constructing the Carty Generating Station (Carty), a 440 MW baseload natural gas-fired generating plant in Eastern Oregon, located adjacent to the Boardman coal plant. As of March 31, 2016, PGE had $501 million, including $50 million of AFDC, included in CWIP for the project as compared to $424 million, including $41 million of AFDC, as of December 31, 2015. The final order issued by the OPUC on November 3, 2015 in connection with the Company’s 2016 GRC, authorized the inclusion in customer prices of capital costs for Carty of up to $514 million, including AFDC, as well as Carty’s operating costs, at such time that the plant is placed in service, provided that occurs by July 31, 2016. In 2013, the Company entered into an agreement (Construction Agreement) for engineering, procurement and construction of Carty with Abeinsa Abener Teyma General Partnership (Contractor or Abeinsa). On December 18, 2015, the Company declared Abeinsa in default under multiple provisions of the Construction Agreement and terminated the Construction Agreement. Liberty Mutual Insurance Company and Zurich American Insurance Company (hereinafter referred to collectively as the Sureties) have provided a performance bond (Performance Bond) of $145.6 million under the Construction Agreement. Following termination of the Construction Agreement, PGE, in consultation with the Sureties, brought on new contractors and construction resumed during the week of December 21, 2015. On January 28, 2016, PGE received notice from the International Court of Arbitration that Abengoa S.A., the parent company of the Contractor, had submitted a Request for Arbitration in which it alleged that the Company’s termination of the Construction Agreement was wrongful and in breach of the agreement terms and does not give rise to liability of Abengoa S.A. under the terms of a guaranty in favor of PGE pursuant to which Abengoa S.A. agreed to guaranty certain obligations of the Contractor under the Construction Agreement. PGE disagrees with the assertions in the Request for Arbitration and on February 29, 2016 filed a Complaint and Motion for Preliminary Injunction in the U.S. District Court for the District of Oregon seeking to have the arbitration claim dismissed on the grounds that the Company has not made a demand under the Abengoa S.A. guaranty, and therefore the matter is not ripe for arbitration. On March 28, 2016, Abengoa S.A. and several of its foreign affiliates filed petitions for recognition under Chapter 15 of the U.S. Bankruptcy Code requesting interim relief, including an injunction precluding the prosecution of any proceedings against the Chapter 15 debtors. On March 29, 2016, a number of Abengoa S.A.’s U.S. subsidiaries filed voluntary petitions for relief under Chapter 11 of the U.S. Bankruptcy Code, including the four entities that collectively comprise the Contractor. On March 31, 2016, the Delaware Bankruptcy Court granted the petition for interim relief. As a result, on April 5, 2016, the U.S. District Court issued an order stating that the District Court action was stayed. On March 9, 2016, the Sureties delivered a letter to the Company denying liability in whole under the Performance Bond. In the letter, the Sureties made the following assertions in support of their determination: 1. that, because the Contractor and its parent company, Abengoa S.A. have alleged that PGE wrongfully terminated the Construction Agreement and have requested arbitration of the claim, PGE must disprove such claim as a condition precedent to recovery under the Performance Bond; and 2. that, irrespective of the outcome of the foregoing wrongful termination claim, the Sureties have various contractual and equitable defenses to payment and are not liable to PGE for any amount under the Performance Bond. The Company disagrees with the Sureties’ assertions and on March 23, 2016 filed a breach of contract action against the Sureties in the U.S. District Court for the District of Oregon. The Company’s complaint disputes the Sureties’ assertion that the Company wrongfully terminated the Construction Agreement and asserts that the Sureties are responsible for the payment of all damages sustained by PGE as a result of the Sureties’ breach of contract, including damages in excess of the $145.6 million stated amount of the Performance Bond. Such damages include additional costs incurred by PGE to complete Carty. On April 15, 2016, the Sureties filed a motion to stay the proceeding, alleging that PGE’s claims should be addressed in the arbitration proceeding initiated by Abengoa S.A. in January, 2016 and referenced above because PGE’s claims are intertwined with the issues involved in such arbitration and all parties necessary to resolve PGE’s claims are parties to the arbitration. PGE disagrees with this assertion and will oppose the Sureties’ motion to stay the proceeding. As a result of the termination of the Construction Agreement, the transition to a new construction team, and related matters, additional costs have been and are expected to be incurred to complete construction of Carty. PGE currently expects the total cost of Carty could range from $635 million to $670 million, including AFDC. The Company is targeting an in service date in July 2016. However, due to uncertainties relating to the work performed by the Contractor and the work necessary to correct defects and complete construction, the costs and completion date for Carty could vary from the Company’s current projection. In the event the total project costs incurred by PGE, net of any amounts received from the Sureties, Abengoa S.A. or the Contractor, exceed the OPUC’s approved amount of $514 million, including AFDC, the Company intends to seek approval to recover the excess amounts in customer prices. The Company will also likely seek a regulatory deferral of the revenue requirements associated with any costs in excess of the $514 million approved by the OPUC from Carty’s in service date until such amounts are approved in a subsequent GRC proceeding. However, there is no assurance that such recovery would be allowed by the OPUC. In accordance with GAAP and the Company’s accounting policies, these costs would be charged to expense at the time disallowance of recovery becomes probable and a reasonable estimate of the amount of such disallowance can be made. As of the date of this report, the Company has concluded that the likelihood that a portion of the cost of Carty will be disallowed for recovery in customer prices is less than probable. Accordingly, no loss has been recorded to date related to the project. If the in service date for Carty were to be delayed beyond July 31, 2016, PGE intends to pursue one or more alternative avenues to obtain OPUC approval for the inclusion of Carty costs in customer prices. Under such circumstance, the Company might not be able to recover some, or all, of the net revenue requirements for Carty from the date Carty is placed into service until the time approved prices go in effect.

Basis of Presentation (Policies)	3 Months Ended
Basis of Presentation (Policies)	Mar. 31, 2016
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 (Policies)	3 Months Ended
Balance Sheet Components (Policies)	Mar. 31, 2016
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, as well as 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 Revenue 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 was classified as Level 3 in the fair value hierarchy and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

- Definition

Disclosure of accounting policy for major classes of inventories, bases of stating inventories (for example, lower of cost or market), methods by which amounts are added and removed from inventory classes (for example, FIFO, LIFO, or average cost), loss recognition on impairment of inventories, and situations in which inventories are stated above cost. If inventory is carried at cost, this disclosure includes the nature of the cost elements included in inventory.

+ References + Details

Fair Value of Financial Instruments (Policies)	3 Months Ended
Fair Value of Financial Instruments (Policies)	Mar. 31, 2016
Fair Value of Financial Instruments [Abstract]
Fair Value of Financial Instruments, Policy [Policy Text Block]	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. Pursuant to the adoption of ASU 2015-07, Fair Value Measurement (Topic 820), Disclosures for Investments in Certain Entities that Calculate Net Asset Value per share (or Its Equivalent), as disclosed in Note 1, Basis of Presentation, assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements, and prior period amounts have been retrospectively reclassified to conform to current presentation. 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: 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 yields 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. 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 not classified in the fair value hierarchy since they are valued at NAV as a practical expedient. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. Common and collective trust funds—PGE invests in common and collective trust funds that invests in equity securities. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value as a practical expedient. A majority of the funds provide for daily liquidity with appropriate written notice. One fund allows for withdrawal from all accounts as of the last day on each calendar month, with at least 10 days’ prior written notice, and provides for a 95% payment to be made within 30 days, and the balance paid after the annual fund audit is complete. Common and collective trusts are not classified in the fair value hierarchy as they are valued at NAV as a practical expedient. 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 derivative 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 Revenue 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 was classified as Level 3 in the fair value hierarchy and was estimated based on the terms of the loans and the Company’s creditworthiness. The significant unobservable inputs to the Level 3 fair value measurement included the interest rate and the length of the loan. The estimated fair value of the Company’s unsecured term bank loans approximated their carrying value.

Price Risk Management (Policies)	3 Months Ended
Price Risk Management (Policies)	Mar. 31, 2016
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, which are recorded at fair value on the condensed consolidated balance sheets, for electricity, natural gas, oil, and foreign currency, 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 Public Utility Commission of Oregon (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)	3 Months Ended
Contingencies (Policies)	Mar. 31, 2016
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 circumstances in which 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)	3 Months Ended
Guarantees (Policies)	Mar. 31, 2016
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 (Tables)

3 Months Ended

Mar. 31, 2016

Balance Sheet Components [Abstract]

Schedule of Other Current Assets [Table Text Block]

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



	March 31, 2016		December 31, 2015
Prepaid expenses	$	55	$	43
Margin deposits	40		33
Assets from price risk management activities	18		10
Other	—		2
Other current assets	$	113	$	88

Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]

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



	March 31, 2016			December 31, 2015
Electric utility plant	$	8,663		$	8,560
Construction work-in-progress	647			545
Total cost	9,310			9,105
Less: accumulated depreciation and amortization	(3,150		)	(3,093		)
Electric utility plant, net	$	6,160		$	6,012

Capital Leases in Financial Statements of Lessee Disclosure [Text Block]

As of March 31, 2016, PGE’s estimated future minimum lease payments for the following five years and thereafter are as follows (in millions):



	Payments Due
	2017		2018		2019		2020		2021		Thereafter		Total
Total minimum lease payments	$	6	$	6	$	6	$	6	$	5	$	73	$	102
Less imputed interest													49
Present value of net minimum lease payments													$	53

Schedule of Regulatory Assets and Liabilities [Text Block]

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



	March 31, 2016					December 31, 2015
	Current			Noncurrent		Current			Noncurrent
Regulatory assets:
Price risk management	$	124		$	159	$	120		$	161
Pension and other postretirement plans	—			235		—			239
Deferred income taxes	—			86		—			86
Debt issuance costs	—			24		—			16
Other	7			22		9			22
Total regulatory assets	$	131		$	526	$	129		$	524
Regulatory liabilities:
Asset retirement removal costs	$	—		$	850	$	—		$	837
Trojan decommissioning activities	21			11		17			15
Asset retirement obligations	—			46		—			45
Other	36			31		38			31
Total regulatory liabilities	$	57	^*	$	938	$	55	^*	$	928


*	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, 2016		December 31, 2015
Regulatory liabilities—current	$	57	$	55
Accrued employee compensation and benefits	42		51
Accrued interest payable	40		25
Accrued dividends payable	28		28
Accrued taxes payable	30		25
Other	71		75
Total accrued expenses and other current liabilities	$	268	$	259

Pension and Other Postretirement Benefits Disclosure [Text Block]

Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions):



	Three Months Ended March 31,
	2016			2015
Service cost	$	4		$	4
Interest cost	8			8
Expected return on plan assets	(10		)	(10		)
Amortization of net actuarial loss	4			5
Net periodic benefit cost	$	6		$	7

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2016

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, 2016
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	5	$	9	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		19		19
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		11		—		—		11
Natural gas	—		9		—		—		9
	$	9	$	37	$	—	$	22	$	68
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	29	$	117	—		$	146
Natural gas	—		143		14		—		157
	$	—	$	172	$	131	$	—	$	303


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure.


(3)	Excludes insurance policies of $25 million, which are recorded at cash surrender value.


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



	As of December 31, 2015
	Level 1		Level 2		Level 3		Other⁽²⁾		Total
Assets:
Nuclear decommissioning trust: ⁽¹⁾
Debt securities:
Domestic government	$	6	$	8	$	—	$	—	$	14
Corporate credit	—		8		—		—		8
Money market funds measured at NAV⁽²⁾	—		—		—		18		18
Non-qualified benefit plan trust: ⁽³⁾
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	1		—		—		—		1
Money market funds measured at NAV⁽²⁾	—		—		—		1		1
Collective trust—domestic equity measured at NAV⁽²⁾	—		—		—		2		2
Assets from price risk management activities: ^{(1) (4)}
Electricity	—		7		—		—		7
Natural gas	—		3		—		—		3
	$	10	$	26	$	—	$	21	$	57
Liabilities from price risk management activities: ^{(1) (4)}
Electricity	$	—	$	28	$	105	$	—	$	133
Natural gas	—		144		14		—		158
	$	—	$	172	$	119	$	—	$	291


(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)	Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure, and have been retrospectively reclassified pursuant to the implementation of ASU 2015-07. For further information see Note 1, Basis of Presentation.


(3)	Excludes insurance policies of $26 million, which are recorded at cash surrender value.


(4)	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:



	Fair Value				Valuation Technique	Significant Unobservable Input	Price per Unit
Commodity Contracts	Assets		Liabilities		Valuation Technique	Significant Unobservable Input	Low		High		Weighted Average
	(in millions)
As of March 31, 2016:
Electricity physical forwards	$	—	$	117	Discounted cash flow	Electricity forward price (per MWh)	$	4.25	$	73.32	$	29.16
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	0.90		3.61		2.46
	$	—	$	131
As of December 31, 2015:
Electricity physical forwards	$	—	$	105	Discounted cash flow	Electricity forward price (per MWh)	$	8.50	$	84.47	$	30.69
Natural gas financial swaps	—		14		Discounted cash flow	Natural gas forward price (per Decatherm)	2.06		3.70		2.54
	$	—	$	119

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



	Three Months Ended March 31,
	2016		2015
Balance as of the beginning of the period	$	119	$	100
Net realized and unrealized losses^*	12		50
Transfers out of Level 3 to Level 2	—		(2		)
Balance as of the end of the period	$	131	$	148


*	Both realized and unrealized losses, of which the unrealized portion is fully offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Purchased power and fuel expense in the condensed consolidated statements of income.

- Definition

Tabular disclosure of the application of the fair value option for measurement and reporting of eligible financial assets and liabilities (as defined), as well as certain other eligible items (as defined) included in the statement of financial position, whether such option is elected for a single eligible item or a group of similar eligible items and is in addition to other disclosures concerning fair value which the company may be required to provide. Such disclosure might be expected to include: (1) for items included in the statement of financial position: (a) for each line item in the statement of financial position that includes an item or items for which the fair value option has been elected, provide the aggregate carrying amount of ineligible items included in each line item in the balance sheet, if any; (b) the difference between the aggregate fair value and the aggregate unpaid principal balance (assuming contractual principal amounts and fair value option elected) of: (i) loans and long-term receivables (other than securities otherwise reported at fair value) and (ii) long-term debt instruments; (c) for loans held as assets for which the fair value option has been elected: (i) the aggregate fair value of loans that are 90 days or more past due, (ii) if the policy is to recognize interest income separately from other changes in fair value, the aggregate fair value of loans in nonaccrual status, and (iii) the difference between the aggregate fair value and the aggregate unpaid principal balance for loans that are 90 days or more past due, in nonaccrual status, or both; (2) for items included in the income statement: (a) the amounts of gains and losses from fair value changes included in earnings and in which line in the income statement those gains and losses are reported whether or not combined with gains and losses from items required to be accounted for at fair value; (b) for loans and other receivables held as assets, the estimated amount of gains or losses included in earnings attributable to changes in instrument-specific credit risk; (c) for liabilities with fair values that have been significantly affected during the reporting period by changes in the instrument-specific credit risk, the estimated amount of gains and losses from fair value changes included in earnings that are attributable to changes in the instrument-specific credit risk; and (3) certain other disclosures as required or determined to be provided.

+ References + Details

Price Risk Management (Tables)

3 Months Ended

Mar. 31, 2016

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, 2016			December 31, 2015
Current assets:
Commodity contracts:
Electricity	$	11		$	7
Natural gas	7			3
Total current derivative assets	18		⁽¹⁾	10		⁽¹⁾
Noncurrent assets:
Commodity contracts:
Natural gas	2			—
Total noncurrent derivative assets	2		⁽²⁾	—		⁽²⁾
Total derivative assets not designated as hedging instruments	$	20		$	10
Total derivative assets	$	20		$	10
Current liabilities:
Commodity contracts:
Electricity	$	37		$	36
Natural gas	105			94
Total current derivative liabilities	142			130
Noncurrent liabilities:
Commodity contracts:
Electricity	109			97
Natural gas	52			64
Total noncurrent derivative liabilities	161			161
Total derivative liabilities not designated as hedging instruments	$	303		$	291
Total derivative liabilities	$	303		$	291


(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]



	March 31, 2016			December 31, 2015
Commodity contracts:
Electricity	12		MWh	12		MWh
Natural gas	118		Decatherms	124		Decatherms
Foreign currency	$	21	Canadian	$	7	Canadian

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



	Three Months Ended March 31,
	2016			2015
Commodity contracts:
Electricity	$	25		$	41
Natural Gas	17			44
Foreign currency exchange	$	(1	)	$	—

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]



	2016		2017		2018		2019		2020		Thereafter		Total
Commodity contracts:
Electricity	$	24	$	8	$	8	$	8	$	7	$	80	$	135
Natural gas	85		50		11		2		—		—		148
Net unrealized loss	$	109	$	58	$	19	$	10	$	7	$	80	$	283

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, 2016		December 31, 2015
Assets from price risk management activities:
Counterparty A	48	%	59	%
Counterparty B	11		8
Counterparty C	9		10
	68	%	77	%
Liabilities from price risk management activities:
Counterparty D	38	%	36	%
Counterparty B	10		10
Counterparty E	9		10
	57	%	56	%

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2016

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,
	2016	2015
Weighted-average common shares outstanding—basic	88,833	78,271
Dilutive effect of potential common shares	—	3,195
Weighted-average common shares outstanding—diluted	88,833	81,466

Equity (Tables)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Schedule of Stockholders Equity [Table Text Block]

The activity in equity during the three months ended March 31, 2016 and 2015 is as follows (dollars in millions):



	Common Stock				Accumulated Other Comprehensive Loss			Retained Earnings
	Common Stock
	Shares	Amount									Total
Balances as of December 31, 2015	88,792,751	$	1,196		$	(8	)	$	1,070		$	2,258
Issuances of shares pursuant to equity-based plans	106,608	—			—			—			—
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(27		)	(27		)
Net income	—	—			—			61			61
Balances as of March 31, 2016	88,899,359	$	1,195		$	(8	)	$	1,104		$	2,291

Balances as of December 31, 2014	78,228,339	$	918		$	(7	)	$	1,000		$	1,911
Issuances of shares pursuant to equity-based plans	116,352	1			—			—			1
Stock-based compensation	—	(1		)	—			—			(1		)
Dividends declared	—	—			—			(22		)	(22		)
Net income	—	—			—			50			50
Balances as of March 31, 2015	78,344,691	$	918		$	(7	)	$	1,028		$	1,939

Basis of Presentation (Details) shares in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) mi² retail_customers shares	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Basis of Presentation [Abstract]
Regulatory deferral of settled derivative instruments		$ 2
Service Area Sq Miles \| mi²	4,000
Incorporated Cities	52
Number of Retail Customers \| retail_customers	855,573
Service Area Population \| shares	1.8
Percent of State's Population	46.00%
Other Comprehensive Income	$ 0	0
Unamortized Debt Issuance Expense	$ 12		$ 11
Decoupling Mechanism Deferrals, Net		(3)
Cash received pursuant to the Residential Exchange Program		$ 1

Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Other Current Assets [Line Items]
Prepaid expenses	$ 55	$ 43
Margin deposits	40	33
Assets from price risk management activities	18	10
Other	0	2
Other current assets	$ 113	$ 88

Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Derivative Liability, Fair Value of Collateral	$ 15
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	2
Capital Leases, Future Minimum Payments, Interest Included in Payments	3
Capital Leased Assets, Gross	54
Electric utility plant	8,663	$ 8,560
Construction work-in-progress	647	545
Total cost	9,310	9,105
Less: accumulated depreciation and amortization	(3,150)	(3,093)
Electric utility plant, net	6,160	$ 6,012
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	1
Capital Lease Obligations, Current	2
Capital Lease Obligations, Noncurrent	51
Amortization of Leased Asset	1
Capital Leases, Income Statement, Interest Expense	$ 2

Balance Sheet Components Schedule of Capital Leases (Details) $ in Millions	Mar. 31, 2016 USD ($)
Capital Leased Assets [Line Items]
Capital Leases, Future Minimum Payments Due, Next Twelve Months	$ 6
Capital Leases, Future Minimum Payments Due in Two Years	6
Capital Leases, Future Minimum Payments Due in Three Years	6
Capital Leases, Future Minimum Payments Due in Four Years	6
Capital Leases, Future Minimum Payments Due in Five Years	5
Capital Leases, Future Minimum Payments Due Thereafter	73
Capital Leases, Future Minimum Payments Due	102
Capital Leases, Future Minimum Payments, Interest Included in Payments	49
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments	$ 53

Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	$ 124	$ 120
Pension and other postretirement plans	0	0
Deferred income taxes	0	0
Debt issuance costs	0	0
Other	7	9
Total regulatory assets	131	129
Noncurrent Regulatory Assets [Member]
Regulatory Assets and Liabilities [Line Items]
Price risk management	159	161
Pension and other postretirement plans	235	239
Deferred income taxes	86	86
Debt issuance costs	24	16
Other	22	22
Total regulatory assets	526	524
Current Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	0	0
Trojan decommissioning activities	21	17
Asset retirement obligations	0	0
Other	36	38
Total regulatory liabilities	57	55
Noncurrent Regulatory Liabilities [Member]
Regulatory Assets and Liabilities [Line Items]
Asset retirement removal costs	850	837
Trojan decommissioning activities	11	15
Asset retirement obligations	46	45
Other	31	31
Total regulatory liabilities	$ 938	$ 928

Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Regulatory liabilities—current	$ 57	$ 55
Accrued employee compensation and benefits	42	51
Accrued interest payable	40	25
Accrued dividends payable	28	28
Accrued taxes payable	30	25
Other	71	75
Total accrued expenses and other current liabilities	$ 268	$ 259

Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4	$ 4
Interest cost	8	8
Expected return on plan assets	(10)	(10)
Amortization of net actuarial loss	4	5
Net periodic benefit cost	$ 6	$ 7

Balance Sheet Components (Details)		3 Months Ended
Balance Sheet Components (Details)	Jan. 09, 2016 USD ($)	Mar. 31, 2016 USD ($)	Mar. 31, 2015 USD ($)	Jan. 31, 2016	Jan. 11, 2016	Jan. 08, 2016 USD ($)	Dec. 31, 2015 USD ($)
Valuation and Qualifying Accounts Disclosure [Line Items]
Finite-Lived Intangible Assets, Accumulated Amortization		$ 238,000,000					$ 227,000,000
Amortization of Intangible Assets		11,000,000	$ 9,000,000
Syndicated credit facility scheduled to expire in 2019		500,000,000
Line of Credit Facility, Current Borrowing Capacity		$ 160,000,000
Debt Instrument, Covenant Description		.65
Ratio of Indebtedness to Net Capital		0.499
Short-term debt		$ 0					$ 6,000,000
Line of Credit Facility, Remaining Borrowing Capacity		500,000,000
Letters of credit issued		111,000,000
Authorized Short-Term Debt		900,000,000
Proceeds from Issuance of Long-term Debt						$ 140,000,000
Debt Instrument, Interest Rate, Stated Percentage				3.81%	5.80%	2.51%
Extinguishment of Debt, Amount		133,000,000	$ 120,000,000
Capital Leases, Future Minimum Payments, Remainder of Fiscal Year		$ 5,000,000
Notes Payable to Banks [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Extinguishment of Debt, Amount	$ 75,000,000
Long-term Debt [Member]
Valuation and Qualifying Accounts Disclosure [Line Items]
Extinguishment of Debt, Amount	$ 58,000,000

Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Debt securities:
Domestic government	$ 14	$ 14
Corporate credit	8	8
Money market funds	19	18
Investments, Fair Value Disclosure	2	2
Non-qualified benefit plan trust: (2)
Domestic	3	3
Debt securities—domestic government	1	1
Alternative Investments, Fair Value Disclosure	1	1
Assets from price risk management activities: (1) (3)
Electricity	11	7
Natural gas	9	3
Total	68	57
Liabilities from price risk management activities: (1) (3)
Electricity	146	133
Natural gas	157	158
Total	303	291
Fair Value, Inputs, Level 1 [Member]
Debt securities:
Domestic government	5	6
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Domestic	3	3
Debt securities—domestic government	1	1
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	9	10
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Debt securities:
Domestic government	9	8
Corporate credit	8	8
Non-qualified benefit plan trust: (2)
Domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	11	7
Natural gas	9	3
Total	37	26
Liabilities from price risk management activities: (1) (3)
Electricity	29	28
Natural gas	143	144
Total	172	172
Fair Value, Inputs, Level 3 [Member]
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Liabilities from price risk management activities: (1) (3)
Electricity	117	105
Natural gas	14	14
Total	131	119
Estimate of Fair Value Measurement [Member]
Debt securities:
Money market funds	19	18
Investments, Fair Value Disclosure	2	2
Non-qualified benefit plan trust: (2)
Alternative Investments, Fair Value Disclosure	1	1
Assets from price risk management activities: (1) (3)
Total	$ 22	$ 21

Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Mar. 31, 2016	Dec. 31, 2015
Low [Member]
Commodity Contracts
Electricity physical forward	$ 4.25	$ 8.50
Natural gas financial swaps	0.90	2.06
High [Member]
Commodity Contracts
Electricity physical forward	73.32	84.47
Natural gas financial swaps	3.61	3.70
Weighted Average [Member]
Commodity Contracts
Electricity physical forward	29.16	30.69
Natural gas financial swaps	2.46	2.54
Assets [Member]
Commodity Contracts
Electricity physical forward	0	0
Natural gas financial swaps	0	0
Total commodity contracts	0	0
Liabilities [Member]
Commodity Contracts
Electricity physical forward	117,000,000	105,000,000
Natural gas financial swaps	14,000,000	14,000,000
Total commodity contracts	$ 131,000,000	$ 119,000,000

Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 119	$ 100
Net realized and unrealized losses (gains)	12	50
Transfers out of Level 3 to Level 2	0	2
Balance as of the end of the period	$ 131	$ 148

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($)	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
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	25,000,000		$ 26,000,000
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	$ 0
Long-term Debt	2,199,000,000		2,193,000,000
Unamortized Debt Issuance Expense	12,000,000		11,000,000
Long-term Debt, Fair Value	$ 2,617,000,000		$ 2,455,000,000

Price Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Current Assets, Commodity Contracts:
Electricity	$ 11	$ 7
Natural gas	7	3
Total current derivative assets	18	10
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Natural Gas	2	0
Total noncurrent derivative assets	2	0
Total derivative assets not designated as hedging instruments	20	10
Total derivative assets	20	10
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	37	36
Natural gas	105	94
Total current derivative liabilities	142	130
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	109	97
Natural gas	52	64
Total noncurrent derivative liabilities	161	161
Total derivative liabilities not designated as hedging instruments	303	291
Total derivative liabilities	$ 303	$ 291

Price Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Mar. 31, 2016 CAD ($) MMBTU MWh	Dec. 31, 2015 CAD ($) MMBTU MWh
Commodity contracts:
Electricity \| MWh	12	12
Natural gas \| MMBTU	118	124
Foreign currency \| $	$ 21	$ 7

Price Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Commodity contracts:
Electricity	$ 25	$ 41
Natural Gas	17	44
Derivative, Forward Exchange Rate	$ (1)	$ 0

Price Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Mar. 31, 2016 USD ($)
Electricity [Member]
Commodity contracts:
2015	$ 24
2016	8
2017	8
2018	8
2019	7
Thereafter	80
Total	135
Natural Gas [Member]
Commodity contracts:
2015	85
2016	50
2017	11
2018	2
2019	0
Thereafter	0
Total	148
Net Unrealized Loss [Member]
Commodity contracts:
2015	109
2016	58
2017	19
2018	10
2019	7
Thereafter	80
Total	$ 283

Price Risk Management Counterparties Representing 10% or More of Assets and Liabilities from price risk management activities (Details)	Mar. 31, 2016	Dec. 31, 2015
Assets from price risk management activities:
Counterparty A	48.00%	59.00%
Counterparty B	11.00%	8.00%
Counterparty C	9.00%	10.00%
Total	68.00%	77.00%
Liabilities from price risk management activities:
Counterparty D	38.00%	36.00%
Counterparty B	10.00%	10.00%
Counterparty E	9.00%	10.00%
Total	57.00%	56.00%

Price Risk Management Price Risk Management (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Sep. 30, 2014	Dec. 31, 2015
Collateral, Master Netting Arrangements, Letters of Credit	$ 14			$ 14
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	34	$ 83
Derivative, Net Liability Position, Aggregate Fair Value	287
Collateral Posted, Aggregate Fair Value	88
Letters of Credit Outstanding, Amount	64
Restricted Cash and Cash Equivalents, Current	24
Collateral cash requirement	256
Derivative Liability, Fair Value of Collateral	15
Natural Gas [Member]
Derivative Instruments and Hedges, Liabilities	6			7
4911 Electric Services [Member]
Derivative Instruments and Hedges, Liabilities	117			104
Liabilities, Total [Member]
Derivative Instruments and Hedges, Liabilities	$ 123			$ 111

Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Weighted-average common shares outstanding - basic	88,833	78,271
Dilutive effect of potential common shares	0	3,195
Weighted-average common shares outstanding - diluted	88,833	81,466

Earnings Per Share Earnings Per Share (Details) - shares	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Earnings Per Share [Abstract]
Unvested performance-based restricted stock units and associated dividend equivalent rights	304,000	303,000

Schedule of Equity (Details) - USD ($) $ in Millions	3 Months Ended
Schedule of Equity (Details) - USD ($) $ in Millions	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015
Stock Issued During Period, Shares, New Issues		10,400,000
Proceeds from Issuance of Common Stock		$ 271
Common Stock, Shares, Outstanding beginning of period	88,792,751
Stockholders' Equity	$ 2,258
Common Stock, Shares, Outstanding end of period	88,899,359
Stockholders' Equity	$ 2,291
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	88,792,751	78,344,691	78,228,339
Issuances of shares pursuant to equity-based plans	106,608		116,352
Common Stock, Shares, Outstanding end of period	88,899,359		78,344,691
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 0		$ 1
Adjustments Related to Tax Withholding for Share-based Compensation	(1)		(1)
Stockholders' Equity	1,196	$ 918	918
Dividends declared	0		0
Stockholders' Equity	1,195		918
AOCI Attributable to Parent [Member]
Stockholders' Equity	(8)	(7)	(7)
Stock-based compensation	0		0
Dividends declared	0		0
Stockholders' Equity	(8)		(7)
Retained Earnings [Member]
Stockholders' Equity	1,070	1,028	1,000
Stock-based compensation	0		0
Dividends declared	(27)		(22)
Net Income	61		50
Stockholders' Equity	1,104		1,028
Stockholders' Equity, Total [Member]
Issuance of shares pursuant to equity-based plans	0		1
Adjustments Related to Tax Withholding for Share-based Compensation	(1)		(1)
Stockholders' Equity	2,258	$ 1,939	1,911
Dividends declared	(27)		(22)
Net Income	61		50
Stockholders' Equity	$ 2,291		$ 1,939

Equity (Details) $ in Millions	3 Months Ended
Equity (Details) $ in Millions	Jun. 30, 2015 USD ($) shares
Stock Issued During Period, Shares, New Issues \| shares	10,400,000
Proceeds from Issuance of Common Stock \| $	$ 271

Contingencies (Details)	3 Months Ended		12 Months Ended
Contingencies (Details)	Mar. 31, 2016 USD ($) claims	Jun. 30, 2013 claims	Dec. 31, 1997	Dec. 31, 2015 USD ($)	Sep. 30, 2008 USD ($)	Dec. 31, 1993
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
Site Contingency, Names of Other Potentially Responsible Parties	100		69
Remediation cost estimate lower range	$ 800,000,000
Remediation cost estimate upper range	2,400,000,000			$ 1,500,000,000
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 \| claims	2
Loss Contingency, Pending Claims, Number \| claims	40	39

Carty Generating Station (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
Carty Generating Station (Details) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Additions	$ 501.0	$ 424.0
Phase-in Plan, Amount of Costs Deferred for Rate-making Purposes		514.0
Allowance for Funds Used During Construction, Capitalized Interest	50.0	41.0
Malpractice Loss Contingency, Letters of Credit and Surety Bonds	145.6
Construction work-in-progress	647.0	$ 545.0
Minimum [Member]
Property, Plant and Equipment [Line Items]
Construction work-in-progress	635.0
Maximum [Member]
Property, Plant and Equipment [Line Items]
Construction work-in-progress	$ 670.0