Portland General Electric (POR) 10-K 14 Feb 20 2019 FY Annual report Financial data

Cover Page Document

Cover Page Document - USD ($)	12 Months Ended
	Dec. 31, 2019	Feb. 04, 2020	Jun. 30, 2019
Entity Incorporation, State or Country Code	OR
Document Transition Report	false
Document Annual Report	true
Entity Registrant Name	PORTLAND GENERAL ELECTRIC COMPANY
Entity Central Index Key	0000784977
Document Type	10-K
Document Period End Date	Dec. 31, 2019
Entity File Number	001-05532-99
Entity Address, Address Line One	121 S.W. Salmon Street
Entity Address, City or Town	Portland
Entity Address, State or Province	OR
Entity Address, Postal Zip Code	97204
City Area Code	503
Local Phone Number	464-8000
Amendment Flag	false
Document Fiscal Year Focus	2019
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Voluntary Filers	No
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		89,391,379
Entity Public Float			$ 4,823,580,272
Entity Tax Identification Number	93-0256820
Common Stock [Member]
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
Medium-term Notes [Member]
Title of 12(b) Security	9.31% Medium-Term Notes due 2021
Trading Symbol	POR 21
Security Exchange Name	NYSE

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues, net	$ 2,121	$ 1,988	$ 2,009
Alternative revenue programs, net of amortization	2	3	0
Total Revenues	2,123	1,991	2,009
Operating expenses:
Purchased power and fuel	614	571	592
Generation, transmission and distribution	323	292	309
Administrative and other	290	271	260
Depreciation and amortization	409	382	345
Taxes other than income taxes	134	129	123
Total operating expenses	1,770	1,645	1,629
Income from operations	353	346	380
Interest expense, net	128	124	120
Other income:
Allowance for equity funds used during construction	10	11	12
Miscellaneous income, net	6	(4)	1
Other income, net	16	7	13
Income before income taxes	241	229	273
Income tax expense	27	17	86
Net income	$ 214	$ 212	$ 187
Weighted-average shares outstanding (in thousands):
Basic	89,353	89,215	89,056
Diluted	89,559	89,347	89,176
Earnings per share:
Basic	$ 2.39	$ 2.38	$ 2.10
Diluted	$ 2.39	$ 2.37	$ 2.10

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Net income	$ 214	$ 212	$ 187
Other comprehensive (loss) income - Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2019, 2018, and 2017	(1)	1	(1)
Comprehensive income	$ 213	$ 213	$ 186

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 30	$ 119
Accounts receivable, net	167	193
Unbilled revenues	86	96
Inventories, at average cost:
Materials and supplies	56	53
Fuel	40	31
Regulatory assets--current	17	61
Other current assets	104	90
Total current assets	500	643
Electric utility plant:
In service	10,928	10,344
Accumulated depreciation and amortization	(4,095)	(3,803)
In service, net	6,833	6,541
Construction work-in-progress	328	346
Property, Plant and Equipment, Net	7,161	6,887
Regulatory assets--noncurrent	483	401
Nuclear decommissioning trust	46	42
Non-qualified benefit plan trust	38	36
Other noncurrent assets	166	101
Total assets	8,394	8,110
Current liabilities:
Accounts payable	165	168
Liabilities from price risk management activities-current	23	55
Current portion of long-term debt	0	300
Current portion of long-term debt	16	0
Accrued expenses and other current liabilities	315	268
Total current liabilities	519	791
Long-term debt, net of current portion	2,597	2,178
Regulatory liabilities--noncurrent	1,377	1,355
Deferred income taxes	378	369
Unfunded status of pension and postretirement plans	247	307
Liabilities from price risk management activities--noncurrent	108	101
Asset retirement obligations	263	197
Non-qualified benefit plan liabilities	103	103
Finance lease obligations, net of current portion	135	0
Other noncurrent liabilities	76	203
Total liabilities	5,803	5,604
Commitments and Contingencies (see notes)
Shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,387,124 and 89,267,959 shares issued and outstanding as of December 31, 2019 and 2018, respectively	1,220	1,212
Accumulated other comprehensive loss	(10)	(7)
Retained earnings	1,381	1,301
Total shareholders' equity	2,591	2,506
Total liabilities and shareholders' equity	$ 8,394	$ 8,110

Consolidated Balance Sheets Con

Consolidated Balance Sheets Consolidated Balance Sheet Parentheticals - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Preferred Stock, No Par Value	$ 0	$ 0
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Outstanding	0	0
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	160,000,000	160,000,000
Common Stock, Shares, Issued	89,387,124	89,267,959
Common Stock, Shares, Outstanding	89,387,124	89,267,959

Consolidated Statements of Equi

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock Shares	Common Stock Amount	Accumulated Other Comprehensive Loss	Retained Earnings
Balance, shares at Dec. 31, 2016		88,946,704
Balance at Dec. 31, 2016	$ 2,344		$ 1,201	$ (7)	$ 1,150
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		167,561
Proceeds from issuance of shares pursuant to equity-based plans	2		2
Stock-based compensation	4		4	0	0
Dividends declared	(120)		0	0	(120)
Net income	187		0	0	187
Other comprehensive income (loss)	(1)		0	(1)	0
Balance, shares at Dec. 31, 2017		89,114,265
Balance at Dec. 31, 2017	2,416		1,207	(8)	1,217
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		153,694
Proceeds from issuance of shares pursuant to equity-based plans	1		1
Stock-based compensation	4		4	0	0
Dividends declared	(128)		0	0	(128)
Net income	212		0	0	212
Other comprehensive income (loss)	1		0	1	0
Balance, shares at Dec. 31, 2018		89,267,959
Balance at Dec. 31, 2018	2,506		1,212	(7)	1,301
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		119,165
Proceeds from issuance of shares pursuant to equity-based plans	1		1
Stock-based compensation	7		7	0	0
Dividends declared	(136)		0	0	(136)
Net income	214		0	0	214
Reclassification of stranded tax effects due to Tax Reform				(2)	(2)
Other comprehensive income (loss)	(1)		0	(1)	0
Balance, shares at Dec. 31, 2019		89,387,124
Balance at Dec. 31, 2019	$ 2,591		$ 1,220	$ (10)	$ 1,381

Consolidated Statements of Eq_2

Consolidated Statements of Equity Consolidated Statement of Equity Parenthetical - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Common Stock, Dividends, Per Share, Declared	$ 1.5175	$ 1.4275	$ 1.34

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income	$ 214	$ 212	$ 187
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	409	382	345
Deferred income taxes	6	(17)	70
Allowance for equity funds used during construction	(10)	(11)	(12)
Pension and other postretirement benefits	21	30	24
Decoupling mechanism deferrals, net of amortization	(2)	(2)	(22)
(Amortization) Deferral of net benefits due to Tax Reform	(23)	45	0
Share-based Payment Arrangement, Noncash Expense	9	5	7
Other non-cash income and expenses, net	34	16	24
Changes in working capital:
Decrease (increase) in receivables and unbilled revenues	30	(29)	(3)
(Increase) in margin deposits	0	(5)	(3)
(Decrease) increase in payables and accrued liabilities	(16)	51	5
Other working capital items, net	(12)	(11)	1
Contribution to non-qualified employee benefit trust	(11)	(11)	(8)
Contribution to pension and other postretirement plans	(65)	(12)	(5)
Other, net	(38)	(13)	(13)
Net cash provided by operating activities	546	630	597
Cash flows from investing activities:
Capital expenditures	(606)	(595)	(514)
Purchases of nuclear decommissioning trust securities	(8)	(12)	(18)
Sales of nuclear decommissioning trust securities	13	15	21
Proceeds from Carty Settlement	0	120	0
Other, net	(3)	1	(3)
Net cash used in investing activities	(604)	(471)	(514)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	470	75	225
Payments on long-term debt	(350)	(24)	(150)
Debt extinguishment costs	(9)	0	0
Dividends paid	(134)	(125)	(118)
Other	(8)	(5)	(7)
Net cash used in financing activities	(31)	(79)	(50)
(Decrease) increase in cash and cash equivalents	(89)	80	33
Cash and cash equivalents, beginning of year	119	39	6
Cash and cash equivalents, end of year	30	119	39
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	116	117	110
Cash paid for income taxes	33	25	18
Non-cash investing and financing activities:
Accrued capital additions	76	61	53
Accrued dividends payable	36	34	31
Assets obtained under leasing arrangements	$ 210	$ 24	$ 87

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2019
Basis of Presentation [Abstract]
Basis of Presentation	BASIS OF PRESENTATION Nature of Operations Portland General Electric Company (PGE or the Company) is a single, vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon. The Company also 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. The Company’s corporate headquarters is located in Portland, Oregon and its approximately 4,000 square mile, state-approved service area is located entirely within the state of Oregon. PGE’s allocated service area includes 51 incorporated cities. As of December 31, 2019 , PGE served approximately 895,000 thousand retail customers with a service area population of approximately 1.9 million . As of December 31, 2019 , PGE had 2,949 employees, with 775 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. Such agreements cover 719 and 56 employees and expire March 2022 and August 2022, respectively. PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. Consolidation Principles The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 18, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Reclassifications To conform with the 2019 presentation, PGE has condensed the functional asset class presentation for Electric utility plant on the consolidated balance sheets for 2018, which is now presented within Note 4, Balance Sheet Components. PGE also reclassified Stock-based compensation expense of $5 million in 2018 and $7 million in 2017 from Other non-cash income and expense, net to its own line item within the operations section of the consolidated statements of cash flows.

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES Cash and Cash Equivalents Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $26 million as of December 31, 2019 and $112 million as of December 31, 2018 included within Cash and cash equivalents in the consolidated balance sheets. Accounts Receivable Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning eight business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors. Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2019 , 2018 , or 2017 . Price Risk Management PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statements of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net variable power costs (NVPC). In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, the Company recognizes a realized gain or loss on the derivative instrument. Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement . Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral to certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets and were $16 million as of December 31, 2019 and 2018 . Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheets and were $15 million and $48 million as of December 31, 2019 and 2018 , respectively. Inventories PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value. Electric Utility Plant Capitalization Policy Electric utility plant is capitalized at original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at PGE’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining FERC licenses for the Company’s hydroelectric projects are capitalized and amortized over the related license period. During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress (CWIP) in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, PGE may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. Costs disallowed for recovery in customer prices, if any, are charged to expense at the time such disallowance becomes probable. PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 7.1% in 2019, and 7.3% in 2018 and 2017 . AFDC from borrowed funds was $5 million in 2019 and $6 million in 2018 and 2017 and is reflected as a reduction to Interest expense, net. AFDC from equity funds, included in Other income, net, was $10 million in 2019 , $11 million in 2018 , and $12 million in 2017 . On December 31, 2019, the FERC approved PGE’s request to reclassify the functional asset classification of certain 115kV facilities from Distribution to Transmission to align classification with the primary function of these assets. As a result, on December 31, 2019, PGE reclassified $223 million of Electric utility plant in service assets from Distribution to Transmission. Accumulated depreciation and amortization related to these facilities is $113 million as of December 31, 2019. Additions to such assets, or construction of similar types of assets, will be classified as Transmission going forward. Depreciation and Amortization Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2019 , 2018 and 2017 . A component of depreciation expense includes estimated asset retirement removal costs allowed in customer prices. Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. The most recent depreciation study was completed based on 2015 data, with an order received from the OPUC in September 2017 authorizing new depreciation rates effective January 1, 2018. This study was incorporated into the Company’s 2018 general rate case filed with the OPUC in 2017. Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059 . Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years): Generation, excluding thermal: Hydro 98 Wind 30 Transmission 59 Distribution 46 General 12 When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities. Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $366 million and $302 million as of December 31, 2019 and 2018 , respectively, with amortization expense of $64 million in 2019 , $59 million in 2018 , and $46 million in 2017 . Future estimated amortization expense as of December 31, 2019 is as follows: $60 million in 2020 ; $52 million in 2021 ; $46 million in 2022 ; $37 million in 2023 ; and $32 million in 2024 . Marketable Securities Nuclear decommissioning trust Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust (NDT) includes amounts collected from customers, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein. Non-qualified benefit plan trust Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans (NQBP) and represents contributions made by the Company, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein. All of PGE’s investments in marketable securities included in NDT and NQBP trust on the consolidated balance sheets, are classified as equity or trading debt securities. These securities are classified as noncurrent because they are not available for use in operations. Such securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the NQBP trust assets are included in Other income, net. Realized and unrealized gains and losses on the NDT fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold is based on the average cost method. Regulatory Accounting Regulatory Assets and Liabilities As a rate-regulated enterprise, PGE applies regulatory accounting, which results in the creation of regulatory assets and regulatory liabilities. Regulatory assets represent: i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process; or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as: i) prices are established by, or subject to, approval by independent third-party regulators; ii) prices are designed to recover the specific enterprise’s cost of service; and iii) in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices. Circumstances that could result in the discontinuance of regulatory accounting include: i) increased competition that restricts PGE’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate. Based on a current evaluation of the various factors and conditions, management believes that recovery of PGE’s regulatory assets is probable. For additional information concerning the Company’s regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities. Power Cost Adjustment Mechanism PGE is subject to a power cost adjustment mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.5% for 2019 and 2018 , and 9.6% for 2017 . Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. A final determination of any customer refund or collection is made in the following year by the OPUC through a public filing and review. The PCAM has resulted in no collection from, or refund to, customers since 2011. Asset Retirement Obligations Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred. The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, with such depreciation included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is included in Depreciation and amortization expense in the Company’s consolidated statements of income. For additional information concerning the Company’s AROs, see Note 8, Asset Retirement Obligations. The difference between the timing of the recognition of ARO depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. As of December 31, 2019 , PGE had a net regulatory liability related to Utility plant AROs in the amount of $54 million and a net regulatory asset related to Trojan decommissioning ARO activities of $91 million . As of December 31, 2018 , PGE had a net regulatory liability related to Utility plant AROs in the amount of $53 million and a net regulatory asset related to Trojan decommissioning ARO activities of $25 million . For additional information concerning the Company’s regulatory assets and liabilities related to AROs, see Note 7, Regulatory Assets and Liabilities. Contingencies Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental 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 determined, 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 why the estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event. Gain contingencies are recognized when realized and are disclosed when material. For additional information concerning the Company’s contingencies, see Note 19, Contingencies. Accumulated Other Comprehensive Loss Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. Revenue Recognition Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided. The prices charged, and amount of consideration PGE receives in exchange for its services provided, are regulated by the OPUC or the FERC. PGE recognizes revenue through the following steps: i) identifying the contract with the customer; ii) identifying the performance obligations in the contract; iii) determining the transaction price; iv) allocating the transaction price to the performance obligations; and v) recognizing revenue when or as each performance obligation is satisfied. Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $45 million in 2019 and 2018 , and $43 million in 2017 . Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that remained unbilled to customers. The estimate, which is classified as Unbilled revenues in the Company’s consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices. As a rate-regulated utility, PGE, in certain situations, recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization. For additional information, see “ Regulatory Assets and Liabilities ” in this Note 2. Alternative Revenue Programs Revenues related to PGE’s decoupling mechanism is considered earned under alternative revenue programs, as this amount represent a contract with the regulator and not with customers. Such revenues are presented separately from revenues from contracts with customers and classified as Alternative revenue programs, net of amortization on the consolidated statements of income. The activity within this line item is comprised of current period deferral adjustments, which can either be a collection from or a refund to customers, and is net of any related amortization. When amounts related to alternative revenue programs are ultimately included in prices and customer bills, the amounts are included within Revenues, net, with an equal and offsetting amount of amortization recorded on the Alternative revenue programs, net of amortization line item. Stock-Based Compensation The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. For additional information concerning the Company’s Stock-Based Compensation, see Note 14, Stock-Based Compensation Expense. Income Taxes Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns. Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory liabilities of $260 million and $267 million as of December 31, 2019 and 2018 , respectively, and will primarily be amortized using the average rate assumption method to account for the refund to customers as the temporary differences reverse. Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheets. PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income. Recent Accounting Pronouncements In August 2018, the FASB issued ASU 2018-13 Fair Value Measurement (Topic 820): Disclosure Framework—Changes to the Disclosure Requirements for Fair Value Measurement . ASU 2018-13 amends Topic 820 to add, remove, and clarify disclosure requirements related to fair value measurement disclosures. For calendar year-end entities, the update will be effective for annual periods beginning January 1, 2020, and interim periods within those fiscal years. Early adoption of the amendments is permitted, including adoption in any interim period. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the consolidated financial statements and does not plan to early adopt. In August 2018, the FASB issued ASU 2018-15 Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Customer’s Accounting for Implementation Costs Incurred in a Cloud Computing Arrangement That Is a Service Contract , to provide guidance on implementation costs incurred in a cloud computing arrangement that is a service contract. ASU 2018-15 aligns the accounting for such costs with the guidance on capitalizing costs associated with developing or obtaining internal-use software. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2020. Early adoption is permitted, including adoption in an interim period. The amendments in this update may be applied either retrospectively or prospectively to all implementation costs incurred after the date of adoption. PGE does not expect the adoption to have a material impact on the consolidated financial statements and does not plan to early adopt. In August 2018, the FASB issued ASU 2018-14 Compensation—Retirement Benefits—Defined Benefit Plans—General (Subtopic 715-20): Disclosure Framework—Changes to the Disclosure Requirements for Defined Benefit Plans . ASU 2018-14 amends Topic 715 to add, remove, and clarify disclosure requirements related to defined benefit pension and other postretirement plans. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2021. Early adoption is permitted. As the standard relates only to disclosures, PGE does not expect the adoption to have a material impact on the consolidated financial statements and is still evaluating whether it will early adopt. Recently Adopted Accounting Pronouncements On January 1, 2019, PGE adopted ASU 2016-02, Leases (Topic 842), which supersedes the previous lease accounting requirements for lessees and lessors within Topic 840, Leases . The Company elected the practical expedient provided under ASU 2018-11, Leases (Topic 842) Targeted Improvements , which amended ASU 2016-02 to provide entities an optional transition practical expedient to adopt the new standard with a cumulative effect adjustment as of the beginning of the year of adoption with prior year comparative financial information and disclosures remaining as previously reported. As a result, no adjustments were made to the balance sheet prior to January 1, 2019 and amounts are reported in accordance with historical accounting under Topic 840, while the balance sheet as of December 31, 2019 is presented under Topic 842. The Company also elected the practical expedient provided under ASU 2018-01, Leases (Topic 842) Land Easement Practical Expedient for Transition to Topic 842 , which amended ASU 2016-02 to provide entities an optional transition practical expedient to not evaluate under Topic 842, existing or expired land easements that were not previously accounted for as leases under the previous leases guidance in Topic 840. Effective January 1, 2019, PGE evaluates new or modified land easements under Topic 842. PGE's transition to the new lease standard did not result in a material adjustment to beginning retained earnings and the Company expects the adoption of the new standard to have an immaterial impact to its results of operations on an ongoing basis. Upon transition, PGE elected to reassess all arrangements that may contain a lease and their resulting lease classification which resulted in the following balance sheet adjustments as of January 1, 2019: i) the recognition of right-of-use assets and liabilities from operating and finance leases of $44 million pursuant to the new standard; ii) the derecognition of existing build-to-suit assets and liabilities of $131 million that were no longer considered to meet build-to-suit criteria under Topic 842 and were not recognized on the Company’s balance sheet until commencement, which occurred in the second quarter of 2019; and iii) the derecognition of $49 million in lease assets and liabilities related to an existing gas pipeline lateral capital lease that no longer met the definition of a lease under the new standard. The following table illustrates the adjustments made upon adoption of Topic 842 and the corresponding line items affected on the Company’s consolidated balance sheets (in millions): January 1, 2019 Topic 842 Adoption Adjustments Increase due to existing operating and finance leases Decrease due to build-to-suit reassessment Decrease due to capital lease reassessment Total Increase/(Decrease) Assets Electric utility plant, net $ 2 $ (131 ) $ (49 ) $ (178 ) Other noncurrent assets 42 — — 42 Liabilities Accrued expenses and other current liabilities 5 — (2 ) 3 Other noncurrent liabilities 39 (131 ) (47 ) (139 ) For new required disclosures and further information see Note 17, Leases. The transition to the new standard did not have a material impact on the Company's financial position. On January 1, 2019 PGE adopted ASU 2018-02 Income Statement—Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income (ASU 2018-02). ASU 2018-02 allows for a reclassification from accumulated other comprehensive income to retained earnings for the stranded tax effects resulting from the United States Tax Cuts and Jobs Act of 2017 (TCJA). The amendments only relate to the reclassification of the income tax effects of the TCJA, and therefore the underlying guidance that requires that the effect of a change in tax laws or rates be included in income from continuing operations is not affected. As a result, PGE reclassified $2 million from Accumulated other compressive loss to Retained earnings during the period of adoption rather than applying the standard retrospectively. The implementation did not result in a material impact to the results of operation, financial position or statements of cash flows.

Revenue Recogniton Revenue Reco

Revenue Recogniton Revenue Recognition	12 Months Ended
	Dec. 31, 2019
Revenue Recognition [Abstract]
Revenue from Contract with Customer [Text Block]	REVENUE RECOGNITION Disaggregated Revenue The following table presents PGE’s revenue, disaggregated by customer type (in millions): Year Ended December 31, 2019 2018 Retail: Residential $ 981 $ 948 Commercial 636 647 Industrial 196 185 Direct access customers 44 43 Subtotal 1,857 1,823 Alternative revenue programs, net of amortization 2 3 Other accrued (deferred) revenues, net (1) 22 (45 ) Total retail revenues 1,881 1,781 Wholesale revenues (2) 170 159 Other operating revenues 72 51 Total revenues $ 2,123 $ 1,991 (1) Amounts for the year ended December 31, 2019 and 2018 is primarily comprised of $23 million of amortization and $45 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. For further information, see Note 12, Income Taxes. (2) Wholesale revenues include $50 million and $42 million related to electricity commodity contract derivative settlements for the year ended December 31, 2019 and 2018 , respectively. Price risk management derivative activities are included within Total revenues but do not represent revenues from contracts with customers as defined by GAAP, pursuant to Topic 606. For further information, see Note 6, Risk Management. Retail Revenues The Company’s primary revenue source is the sale of electricity to customers at regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers. Commercial customers include most businesses, small industrial companies, and public street and highway lighting accounts. Industrial customers consist of non-residential customers who accept delivery at higher voltages than commercial customers. Demand from industrial customers is primarily driven by economic conditions, with weather having little impact on energy use by this customer class. In accordance with state regulations, PGE’s retail customer prices are based on the Company’s cost of service and are determined through general rate case proceedings and various tariff filings with the OPUC. Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options. PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations. Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for the benefit of the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the consolidated statements of income. Wholesale Revenues PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro, solar, and wind conditions, and daily and seasonal retail demand. PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues. Other Operating Revenues

Balance Sheet Components

Balance Sheet Components	12 Months Ended
	Dec. 31, 2019
Balance Sheet Components [Abstract]
Balance Sheet Components	BALANCE SHEET COMPONENTS Accounts Receivable, Net Accounts receivable is net of an allowance for uncollectible accounts of $5 million as of December 31, 2019 and $15 million as of December 31, 2018 . The following is the activity in the allowance for uncollectible accounts (in millions): Years Ended December 31, 2019 2018 2017 Balance as of beginning of year $ 15 $ 6 $ 6 Increase in provision 2 14 6 Amounts written off, less recoveries (12 ) (5 ) (6 ) Balance as of end of year $ 5 $ 15 $ 6 Other Current Assets and Accrued Expenses and Other Current Liabilities Other current assets and Accrued expenses and other current liabilities consist of the following (in millions): As of December 31, 2019 2018 Other current assets: Prepaid expenses $ 63 $ 54 Margin deposits 16 16 Assets from price risk management activities 25 20 $ 104 $ 90 Accrued expenses and other current liabilities: Regulatory liabilities—current $ 44 $ 36 Accrued employee compensation and benefits 74 66 Accrued dividends payable 36 34 Accrued interest payable 25 27 Accrued taxes payable 33 34 Other 103 71 $ 315 $ 268 Electric Utility Plant, Net Electric utility plant, net consist of the following (in millions): As of December 31, 2019 2018 Electric utility plant: Generation $ 4,749 $ 4,600 Transmission 848 580 Distribution 3,917 3,838 General 656 611 Intangible 758 715 Total in service 10,928 10,344 Accumulated depreciation and amortization (4,095 ) (3,803 ) Total in service, net 6,833 6,541 Construction work-in-progress 328 346 Electric utility plant, net $ 7,161 $ 6,887

Fair Value of FInancial Instrum

Fair Value of FInancial Instruments	12 Months Ended
	Dec. 31, 2019
Fair Value of Financial Instruments Note [Abstract]
Fair Value of FInancial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2019 and 2018 . The Company 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 measurement date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement 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. 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. PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of 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 years ended December 31, 2019 and 2018 , except those 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 December 31, 2019 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 26 $ — $ — $ — $ 26 Nuclear decommissioning trust: (1) Debt securities: Domestic government 8 16 — — 24 Corporate credit — 9 — — 9 Money market funds measured at NAV (2) — — — 13 13 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 7 — 16 Natural gas — 21 1 — 22 $ 43 $ 55 $ 8 $ 13 $ 119 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 14 $ 105 $ — $ 119 Natural gas — 12 — — 12 $ — $ 26 $ 105 $ — $ 131 (1) Activities are subject to regulation, with 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 $29 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. As of December 31, 2018 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 112 $ — $ — $ — $ 112 Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 18 — — 25 Corporate credit — 10 — — 10 Money market funds measured at NAV (2) — — — 7 7 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities—domestic 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 3 — 12 Natural gas — 8 — — 8 $ 128 $ 45 $ 3 $ 7 $ 183 Liabilities: Interest rate swap derivatives $ — $ 4 $ — $ — 4 Price risk management activities: (1) (4) Electricity — 10 84 — 94 Natural gas — 51 7 — 58 $ — $ 65 $ 91 $ — $ 156 (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 $27 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted-average maturity of securities held by the funds do not exceed 90 days and investors have the ability to redeem shares daily at the net asset value of the respective fund. These cash equivalents 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 measurement date. Principal markets for money market fund prices include published exchanges such as National Association of Securities Dealers Automated Quotations (NASDAQ) and the New York Stock Exchange (NYSE). Assets held in the NDT and NQBP trusts are recorded at fair value in PGE’s 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 measurement date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are 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 measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE. 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. 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. The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Liabilities from interest rate swap derivatives are recorded at fair value in PGE’s consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk and to reduce volatility in NVPC. For additional information regarding these assets and liabilities, see Note 6, Risk Management. For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps. Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer-term commodity forwards, futures, and swaps. Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below: Significant Price per Unit Fair Value Valuation Unobservable Weighted Commodity Contracts Assets Liabilities Technique Input Low High Average (in millions) As of December 31, 2019: Electricity physical forward $ — $ 104 Discounted cash flow Electricity forward price (per MWh) $ 12.53 $ 59.00 $ 36.92 Natural gas financial swaps 1 — Discounted cash flow Natural gas forward price (per Dth) 1.39 3.73 1.90 Electricity financial futures 7 1 Discounted cash flow Electricity forward price (per MWh) 10.57 66.32 45.11 $ 8 $ 105 As of December 31, 2018: Electricity physical forward $ 3 $ 84 Discounted cash flow Electricity forward price (per MWh) $ 14.60 $ 69.00 $ 45.00 Natural gas financial swaps — 7 Discounted cash flow Natural gas forward price (per Dth) 0.95 4.64 1.82 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 20.75 35.46 28.63 $ 3 $ 91 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, PGE 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 quarterly 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: Significant Unobservable Input Position Change to Input Impact on Fair Value Measurement Market price Buy Increase (decrease) Gain (loss) Market price Sell Increase (decrease) Loss (gain) Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): Years Ended December 31, 2019 2018 Net liabilities from price risk management activities as of beginning of year $ 88 $ 139 Net realized and unrealized losses/(gains) * 10 (40 ) Net transfers out of Level 3 to Level 2 (1 ) (11 ) Net liabilities from price risk management activities as of end of year $ 97 $ 88 Level 3 net unrealized losses/(gains) that have been fully offset by the effect of regulatory accounting $ 16 $ (32 ) * Includes $6 million in net realized gains in 2019 and $8 million in 2018 . 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 years ended December 31, 2019 and 2018 , 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 consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCRBs) is classified as a Level 2 fair value measurement. As of December 31, 2019 , the carrying amount of PGE’s long-term debt was $2,597 million , net of $11 million of unamortized debt expense, and its estimated aggregate fair value was $3,039 million . As of December 31, 2018 , the carrying amount of PGE’s long-term debt was $2,478 million , net of $10 million of unamortized debt expense, with an estimated aggregate fair value of $2,760 million . For fair value information concerning the Company’s pension plan assets, see Note 11, Employee Benefits.

Price Risk Management (Notes)

Price Risk Management (Notes)	12 Months Ended
	Dec. 31, 2019
Price Risk Management [Abstract]
Price Risk Management	RISK MANAGEMENT Price Risk Management PGE participates in the wholesale marketplace to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer the Company’s long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions with respect to Company-owned generating resources. As a result of this ongoing business activity, 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 flow. PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to manage volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the consolidated balance sheets, may include forward, futures, swap, and option contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the consolidated statements of income. In accordance with ratemaking and cost recovery processes authorized by the OPUC, the Company recognizes a regulatory asset or liability to defer the gains and losses from derivative activity 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): As of December 31, 2019 2018 Current assets: Commodity contracts: Electricity $ 9 $ 11 Natural gas 16 7 Total current derivative assets (1) 25 18 Noncurrent assets: Commodity contracts: Electricity 7 1 Natural gas 6 1 Total noncurrent derivative assets (1) 13 2 Total derivative assets (2) $ 38 $ 20 Current liabilities: Commodity contracts: Electricity $ 14 $ 16 Natural gas 9 35 Total current derivative liabilities 23 51 Noncurrent liabilities: Commodity contracts: Electricity 105 78 Natural gas 3 23 Total noncurrent derivative liabilities 108 101 Total derivative liabilities (2) $ 131 $ 152 (1) Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the consolidated balance sheets. (2) As of December 31, 2019 and 2018 , no commodity derivative assets or liabilities were designated as hedging instruments. PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): As of December 31, 2019 2018 Commodity contracts: Electricity 6 MWh 5 MWh Natural gas 145 Dth 123 Dth Foreign currency exchange $ 23 Canadian $ 18 Canadian PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement at gross values on the consolidated balance sheet. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given 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 December 31, 2019 , PGE had no material gross master netting arrangements. As of December 31, 2018 , gross amounts included as Price risk management liabilities subject to master netting agreements were $88 million , for which PGE posted collateral of $11 million , which consisted entirely of letters of credit. Of the gross amounts recognized as of December 31, 2018 , $84 million was for electricity and $4 million was for natural gas. Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions): Years Ended December 31, 2019 2018 2017 Commodity contracts: Electricity $ 20 $ (34 ) $ 41 Natural Gas (32 ) 21 85 Foreign currency exchange (1 ) 1 (1 ) Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net amounts recognized in Net income, net gains of $2 million , net gains of $18 million , and net losses of $82 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively, have been offset. Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized (gains)/losses recorded as of December 31, 2019 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2020 2021 2022 2023 2024 Thereafter Total Commodity contracts: Electricity $ 5 $ 1 $ 7 $ 7 $ 7 $ 76 $ 103 Natural gas (7 ) (2 ) (1 ) — — — (10 ) Net unrealized (gain)/loss $ (2 ) $ (1 ) $ 6 $ 7 $ 7 $ 76 $ 93 PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. 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 December 31, 2019 was $122 million , for which the Company has posted $15 million in collateral, consisting entirely of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered as of December 31, 2019 , the cash requirement to either post as collateral or settle the instruments immediately would have been $114 million . As of December 31, 2019 , PGE had no posted 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 consolidated balance sheet. Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows: As of December 31, 2019 2018 Assets from price risk management activities: Counterparty A 35 % 42 % Counterparty B 1 15 Counterparty C 13 5 Counterparty D 11 6 Counterparty E 11 9 71 % 77 % Liabilities from price risk management activities: Counterparty F 79 % 56 % For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 5, Fair Value of Financial Instruments. Interest Rate Risk In 2018 PGE entered into two forward starting interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. These derivative instruments were designated as cash flow hedges, protecting against the risk of changes in future interest payments that could have resulted from changes in benchmark U.S. Treasury rates between the date of hedge inception and the date of the debt issuance. As of December 31, 2018, the fair value of the interest rate swaps was a $4 million liability, which was recorded in Liabilities from price risk management activities - current on the Company’s consolidated balance sheets. The swaps settled at a $5 million loss in January 2019, which was recorded in Regulatory assets - noncurrent on the consolidated balance sheets, and will be amortized as a component of interest expense over the life of the associated debt. Such amounts are also included as a component of cost of debt for ratemaking purposes. As of December 31, 2019, the Company had no outstanding interest rate swaps.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2019
Regulatory Assets and Liabilities Disclosure [Abstract]
Schedule of Regulatory Assets and Liabilities [Text Block]	REGULATORY ASSETS AND LIABILITIES The majority of PGE’s regulatory assets and liabilities are reflected in customer prices and are amortized over the period in which they are reflected in customer prices. Items not currently reflected in prices are pending before the regulatory body as discussed below. Regulatory assets and liabilities consist of the following (dollars in millions): Remaining Amortization Period As of December 31, 2019 2018 Earning a Return (1) Not Earning a Return Total Total Regulatory assets: Price risk management 2035 $ — $ 95 $ 95 $ 131 Pension and other postretirement plans (2) — 213 213 222 Debt issuance costs 2049 — 26 26 16 Trojan decommissioning activities 2059 — 94 94 26 Other Various 62 10 72 67 Total regulatory assets $ 62 $ 438 $ 500 $ 462 Regulatory liabilities: Asset retirement removal costs (3) $ 1,021 $ — $ 1,021 $ 979 Deferred income taxes (4) 260 — 260 267 Asset retirement obligations (3) 54 — 54 53 Tax reform deferral (5) 2020 23 — 23 45 Other Various 47 16 63 47 Total regulatory liabilities $ 1,405 $ 16 $ 1,421 $ 1,391 (1) Earning a return includes either interest on the regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return. (2) Recovery expected over the average service life of employees. (3) Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base. (4) Refund expected primarily through amortization using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base. (5) Refund related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest, over a two-year period that began in 2019. Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 6, Risk Management. Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic pension and postretirement benefit costs. For further information, see Note 11, Employee Benefits. Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date. Trojan decommissioning activities represents the deferral of ongoing costs associated with monitoring spent nuclear fuel at Trojan, net of amortization of customer collections. In addition, proceeds received from the United States Department of Energy (USDOE) for the reimbursement of costs to monitor the ISFSI is deferred and subsequently refunded to customers. Asset retirement removal costs represents the costs that do not qualify as AROs and are a component of depreciation expense allowed in customer prices. Such costs are recorded as a regulatory liability as they are collected in prices, and are reduced by actual removal costs incurred. Deferred income taxes represents income tax benefits primarily from property-related timing differences that will be refunded to customers when the temporary differences reverse. Substantially all of the amounts deferred are subject to tax normalization rules that require that the impact to the results of operations of amortizing the excess deferred income tax balance cannot occur more rapidly than over the book life of the related assets. The Company uses the average rate assumption method to account for the refund to customers. For further information, see Note 12, Income Taxes. Asset retirement obligations represents the difference in the timing of recognition of: i) the amounts recognized for depreciation expense of the asset retirement costs and accretion of the ARO; and ii) the amount recovered in customer prices.

Asset Retirement Obilgations

Asset Retirement Obilgations	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation [Abstract]
Asset Retirement Obligations	ASSET RETIREMENT OBLIGATIONS AROs consist of the following (in millions): As of December 31, 2019 2018 Trojan decommissioning activities $ 137 $ 68 Utility plant 126 112 Non-utility property 16 17 Total asset retirement obligations 279 197 Less: current portion * 16 — Noncurrent asset retirement obligations $ 263 $ 197 * Current portion of AROs are classified within Accrued expenses and other current liabilities in the consolidated balance sheets. Trojan decommissioning activities represents the present value of future decommissioning costs for PGE’s 67.5% ownership interest in Trojan, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the ISFSI, an interim dry storage facility that is licensed by the Nuclear Regulatory Commission (NRC). The ISFSI will store the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a USDOE facility is complete, which is not expected prior to 2059 . In the third quarter of 2019, the NRC issued PGE a renewed license to operate the ISFSI through the first quarter of 2059. PGE updated its ARO to reflect the estimated costs through this date which increased the Trojan ARO by $69 million as of December 31, 2019 . The Company also recorded accretion of $4 million and a reduction of $4 million due to settled liabilities. Under a settlement agreement reached with the USDOE, the Company receives annual reimbursement from the USDOE for certain costs related to monitoring the ISFSI. Pursuant to this process, the USDOE reimbursed the co-owners $4 million in 2019 for costs incurred in 2018 and $4 million in 2018 for costs incurred in 2017 resulting from USDOE delays in accepting spent nuclear fuel. Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, and distribution and transmission assets, the disposal of which is governed by environmental regulation. During 2019, the Company recorded an overall increase in utility AROs of $14 million , with the change comprised of revisions in estimated cash flows of $13 million , accretion of $4 million , and a reduction of $3 million due to settled liabilities. In 2019, the Company recorded an $11 million increase to its ARO related to Colstrip to revise the estimated cash flows associated with remediation of a number of settlement ponds that will require upgrading or closure to meet Montana Department of Environmental Quality regulatory requirements. Non-utility property primarily represents AROs that have been recognized for portions of unregulated properties leased to third parties. Revisions to estimates for non-utility AROs are not subject to regulatory deferral. As such, additions in non-utility AROs are charged directly to the consolidated statement of income in the period in which the revisions are probable and reasonably estimable. The following is a summary of the changes in the Company’s AROs (in millions): Years Ended December 31, 2019 2018 2017 Balance as of beginning of year $ 197 $ 167 $ 161 Liabilities incurred — — 2 Liabilities settled (9 ) (5 ) (3 ) Accretion expense 9 8 7 Revisions in estimated cash flows 82 27 — Balance as of end of year $ 279 $ 197 $ 167 Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability. Recovery of Trojan decommissioning costs is included in PGE’s retail prices with an equal amount recorded in Depreciation and amortization expense. PGE maintains a separate trust account, Nuclear decommissioning trust in the consolidated balance sheet, for funds collected from customers through prices to cover the cost of Trojan decommissioning activities. The Oak Grove hydro facility and transmission and distribution plant located on public right-of-ways and on certain easements meet the requirements of a legal obligation and will require removal when the plant is no longer in service. An ARO liability is not currently measurable as management believes that these assets will be used in utility operations for the foreseeable future. Removal costs are charged to accumulated asset retirement removal costs, which is included in Regulatory liabilities on PGE’s consolidated balance sheets.

Credit Facilities

Credit Facilities	12 Months Ended
	Dec. 31, 2019
Line of Credit Facility [Abstract]
Credit Facilities	CREDIT FACILITIES As of December 31, 2019 , PGE had a $500 million revolving credit facility scheduled to expire in November 2023 . The credit facility allows for unlimited extension requests, provided that lenders with a pro-rata share of more than 50% approve the extension request. 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 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 a provision that 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 65.0% of total capitalization. As of December 31, 2019 , PGE was in compliance with this covenant with a 51.9% 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 in the consolidated balance sheets. Under the revolving credit facility, as of December 31, 2019 , PGE had no borrowings outstanding and there were no commercial paper or letters of credit issued. As a result, 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 capacity of $220 million 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 facilities, a total of $55 million of letters of credit were outstanding as of December 31, 2019 . Outstanding letters of credit are not reflected on the Company’s consolidated balance sheets. Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount up to $900 million through February 7, 2022 . Short-term borrowings under these credit facilities, and related interest rates, are reflected in the following table (dollars in millions). Year Ended December 31, 2019 Average daily amount of short-term debt outstanding $ 7 Weighted daily average interest rate * 2.6 % Maximum amount outstanding during the year $ 46 * Excludes the effect of commitment fees, facility fees and other financing fees. The Company had no short-term borrowings during 2018 or 2017.

Long-term Debt

Long-term Debt	12 Months Ended
	Dec. 31, 2019
Long-term Debt Disclosure [Abstract]
Long-term Debt	LONG-TERM DEBT Long-term debt consists of the following (in millions): As of December 31, 2019 2018 First Mortgage Bonds , rates range from 2.51% to 9.31%, with a weighted average rate of 4.63% in 2019 and 5.01% in 2018, due at various dates through 2050 $ 2,510 $ 2,390 Pollution Control Revenue Bonds , rates at 5%, due 2033 119 119 Pollution Control Revenue Bonds held by PGE (21 ) (21 ) Total long-term debt 2,608 2,488 Less: Unamortized debt expense (11 ) (10 ) Less: Current portion of long-term debt — (300 ) Long-term debt, net of current portion $ 2,597 $ 2,178 First Mortgage Bonds —On April 12, 2019, PGE issued $200 million of 4.30% Series FMBs due in 2049. Proceeds from the transaction were used to repay the $300 million current portion of long-term debt on April 15, 2019. On October 25, 2019, PGE entered into an agreement to issue $270 million of privately placed FMBs in two tranches, both of which bear interest from their issue date at an annual rate of 3.34%. The first tranche, $110 million , with a maturity in 2049, was issued on October 25, 2019, a portion of which was used to redeem $50 million of 6.75% FMBs that had a maturity date in 2023. The second tranche, $160 million , with a maturity in 2050, was issued and funded November 15, 2019. The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs. Pollution Control Revenue Bonds —The Company has the option to remarket through 2033 the $21 million PCRBs held by PGE as of December 31, 2019 . At the time of any remarketing, the Company can choose a new interest rate period that could be daily, weekly, or a fixed term. The new interest rate would be based on market conditions at the time of remarketing. The PCRBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on the PCRBs. As of December 31, 2019 , the future minimum principal payments on long-term debt are as follows (in millions): Years ending December 31: 2020 $ — 2021 160 2022 — 2023 — 2024 80 Thereafter 2,368 $ 2,608

Employee Benefits

Employee Benefits	12 Months Ended
	Dec. 31, 2019
Employee Benefits [Abstract]
Employee Benefits	EMPLOYEE BENEFITS Pension and Other Postretirement Plans Defined Benefit Pension Plan— PGE sponsors a non-contributory defined benefit pension plan, which has been closed to new employees since January 1, 2012. No changes were made to the benefits provided to existing participants when the plan was closed to new employees. The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate. PGE contributed $62 million to the pension plan in 2019 and $9 million in 2018 . PGE does not expect to contribute to the pension plan in 2020 . Other Postretirement Benefits— PGE offers non-contributory postretirement health and life insurance plans, and provides health reimbursement arrangements (HRAs) to its employees (collectively, “Other Postretirement Benefits” in the following tables). PGE’s obligation pursuant to the postretirement health plan is limited by establishing a maximum benefit per employee with any additional cost the responsibility of the employee. In the third quarter of 2019, PGE announced an amendment to its HRAs and defined dollar medical benefit for non- represented employees, resulting in a $2 million curtailment gain, which has been recorded in Miscellaneous income (expense), net on the consolidated statement of income. The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, equity securities, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions that are reviewed annually by PGE and updated as appropriate, with measurement dates of December 31. Non-Qualified Benefit Plan —The NQBP in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also includes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. The assets of such trust are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bonds, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the NQBP is December 31. For further information regarding these trust investments, see Note 5, Fair Value of Financial Instruments. Other NQBP —In addition to the NQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. PGE holds investments in a NQBP trust that are intended to be a funding source for these plans. Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions): 2019 2018 NQBP Other NQBP Total NQBP Other NQBP Total Non-qualified benefit plan trust $ 17 $ 21 $ 38 $ 16 $ 20 $ 36 Non-qualified benefit plan liabilities * 24 79 103 22 81 103 * For the NQBP, excludes the current portion of $2 million in 2019 and 2018 , which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets. Investment Policy and Asset Allocation —The Board of Directors of PGE appoints an Investment Committee, which is comprised of certain members of management from the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for the implementation of the asset allocation and oversight of the benefit plan investments. The Company’s investment strategy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities, and other alternative investments. Asset classes are regularly rebalanced to ensure asset allocations remain within prescribed parameters. The asset allocations for the plans, and the target allocation, are as follows: As of December 31, 2019 2018 Actual Target * Actual Target * Defined Benefit Pension Plan: Equity securities 64 % 65 % 65 % 67 % Debt securities 36 35 35 33 Total 100 % 100 % 100 % 100 % Other Postretirement Benefit Plans: Equity securities 61 % 59 % 58 % 59 % Debt securities 39 41 42 41 Total 100 % 100 % 100 % 100 % Non-Qualified Benefits Plans: Equity securities 17 % 12 % 16 % 13 % Debt securities 7 12 10 13 Insurance contracts 76 76 74 74 Total 100 % 100 % 100 % 100 % * The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools. The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers. The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): Level 1 Level 2 Level 3 Other * Total As of December 31, 2019: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 49 $ — $ — $ — $ 49 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 632 632 Private equity funds — — — 9 9 $ 49 $ — $ — $ 646 $ 695 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 9 — — — 9 Debt securities—Domestic — 5 — — 5 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 13 $ 34 As of December 31, 2018: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 67 $ — $ — $ — $ 67 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 463 463 Private equity funds — — — 11 11 $ 67 $ — $ — $ 479 $ 546 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 7 7 $ 11 $ 8 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 5, Fair Value of Financial Instruments. The following discussion provides information regarding the methods used in valuation of the various asset class investments held in the pension and other postretirement benefit plan trusts. Money market funds— PGE invests in money market funds that seek to maintain a stable NAV. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Equity securities— Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace. Debt Securities— Debt security investment funds are classified as Level 2 securities as pricing for underlying securities are determined by evaluating pricing data, such as broker quotes for similar securities, adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, if applicable. Collective trust funds— Domestic and international mutual fund assets and debt security assets, including municipal debt and corporate credit securities, mortgage-backed securities, and asset back securities assets, are included in commingled trusts or separately managed accounts. The Company believes the redemption value of the collective trust funds are likely to be the fair value, which is represent by the net asset value as a practical expedient. The funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Private equity funds— PGE invests in a combination of primary and secondary fund-of-funds, which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and NQBP as of and for the years ended December 31, 2019 and 2018 . Information related to the Other NQBP is not included in the following tables (dollars in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2019 2018 2019 2018 2019 2018 Benefit obligation: As of January 1 $ 811 $ 869 $ 72 $ 78 $ 24 $ 27 Service cost 16 19 2 2 — — Interest cost 34 32 3 3 1 1 Participants’ contributions — — 2 2 — — Actuarial loss (gain) 88 (67 ) 8 (7 ) 3 (1 ) Benefit payments (42 ) (39 ) (6 ) (6 ) (2 ) (3 ) Administrative expenses (2 ) (3 ) — — — — Plan amendment — — (9 ) — — — Curtailment gain — — (1 ) — — — As of December 31 $ 905 $ 811 $ 71 $ 72 $ 26 $ 24 Fair value of plan assets: As of January 1 $ 546 $ 629 $ 30 $ 33 $ 16 $ 17 Actual return on plan assets 131 (50 ) 5 (2 ) 1 (1 ) Company contributions 62 9 3 3 2 3 Participants’ contributions — — 2 2 — — Benefit payments (42 ) (39 ) (6 ) (6 ) (2 ) (3 ) Administrative expenses (2 ) (3 ) — — — — As of December 31 $ 695 $ 546 $ 34 $ 30 $ 17 $ 16 Unfunded position as of December 31 $ (210 ) $ (265 ) $ (37 ) $ (42 ) $ (9 ) $ (8 ) Accumulated benefit plan obligation as of December 31 $ 813 $ 734 N/A N/A $ 26 $ 24 Classification in consolidated balance sheet: Noncurrent asset $ — $ — $ — $ — $ 17 $ 16 Current liability — — — — (2 ) (2 ) Noncurrent liability (210 ) (265 ) (37 ) (42 ) (24 ) (22 ) Net liability $ (210 ) $ (265 ) $ (37 ) $ (42 ) $ (9 ) $ (8 ) Amounts included in comprehensive income: Net actuarial loss (gain) $ (3 ) $ 25 $ 5 $ (4 ) $ 3 $ (1 ) Net prior service credit — — (9 ) — — — Amortization of net actuarial loss (10 ) (17 ) — — (1 ) (1 ) $ (13 ) $ 8 $ (4 ) $ (4 ) $ 2 $ (2 ) Amounts included in AOCL:* Net actuarial loss (gain) $ 213 $ 226 $ 1 $ (4 ) $ 13 $ 11 Prior service cost — — (9 ) — — — $ 213 $ 226 $ (8 ) $ (4 ) $ 13 $ 11 * Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets. Net periodic benefit cost consists of the following for the years ended December 31 (in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service cost $ 16 $ 19 $ 17 $ 2 $ 2 $ 2 $ — $ — $ — Interest cost on benefit obligation 34 32 33 3 3 3 1 1 1 Expected return on plan assets (40 ) (42 ) (42 ) (2 ) (1 ) (2 ) — — — Amortization of net actuarial loss 10 17 13 — — — 1 1 1 Curtailment gain — — — (2 ) — — — — — Net periodic benefit cost $ 20 $ 26 $ 21 $ 1 $ 4 $ 3 $ 2 $ 2 $ 2 The portion of non-service costs attributable to expense related to the pension and other postretirement benefit plans, is classified as Miscellaneous income (expense), net within Other income on the Company’s consolidated statements of income. PGE estimates that $17 million will be amortized from AOCL into net periodic benefit cost in 2020 , consisting of a net actuarial loss of $17 million for pension benefits, a net actuarial gain and prior service credit of $1 million for other postretirement benefits and a net actuarial loss of $1 million for non-qualified benefits. Amounts related to the pension and other postretirement benefits are offset with the amortization of the corresponding regulatory asset. The following assumptions were used in determining benefit obligations and net period benefit costs: Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2019 2018 2019 2018 2019 2018 Assumptions used to determine benefit obligations: Discount rate 3.43 % 4.25 % 3.19 % - 4.10 % - 3.43 % 4.25 % 3.47 % 4.26 % Weighted average rate of compensation increase 3.65 % 3.65 % 4.58 % 4.58 % N/A N/A Assumptions used to determine net periodic benefit cost: Discount rate 4.25 % 3.65 % 3.11 % - 3.42 % - 3.43 % 3.65 % 4.26 % 3.70 % Weighted average rate of compensation increase 3.65 % 3.65 % 4.58 % 4.58 % N/A N/A Long-term rate of return on plan assets 7.00 % 7.00 % 5.88 % 6.20 % N/A N/A As of December 31, 2019 , there are no liabilities with sensitivity to health care cost trend rates. Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.25% reduction in the expected long-term rate of return on plan assets, or reduction in the discount rate, would have the effect of increasing the 2019 net periodic pension expense by approximately $2 million . The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions): Payments Due 2020 2021 2022 2023 2024 2025 - 2029 Defined benefit pension plan $ 44 $ 44 $ 45 $ 46 $ 46 $ 239 Other postretirement benefits 5 5 5 5 6 20 Non-qualified benefit plans 2 2 2 2 2 11 Total $ 51 $ 51 $ 52 $ 53 $ 54 $ 270 All of the plans develop expected long-term rates of return for the major asset classes using long-term historical returns, with adjustments based on current levels and forecasts of inflation, interest rates, and economic growth. Also included are incremental rates of return provided by investment managers whose returns are expected to be greater than the markets in which they invest. 401(k) Retirement Savings Plan PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions to the 401(k) Plan up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes 5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay. For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan. All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $25 million in 2019 , $23 million in 2018 , and $21 million in 2017 .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2019
Income Taxes Note [Abstract]
Income Taxes	INCOME TAXES On December 22, 2017, the TCJA was enacted and signed into law with substantially all of the provisions having an effective date of January 1, 2018. The most significant change to PGE’s financial condition was the federal corporate tax rate decrease from 35% to 21% . Income tax expense/(benefit) consists of the following (in millions): Years Ended December 31, 2019 2018 2017 Current: Federal $ 9 $ 12 $ 4 State and local 12 22 12 21 34 16 Deferred: Federal (2 ) (15 ) 61 State and local 8 (2 ) 9 6 (17 ) 70 Income tax expense $ 27 $ 17 $ 86 The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows: Years Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % Federal tax credits (1) (13.4 ) (16.7 ) (14.0 ) Change in federal tax law (2) — — 6.1 State and local taxes, net of federal tax benefit 6.5 6.5 5.0 Flow through depreciation and cost basis differences 1.5 1.5 1.5 Excess deferred tax amortization (3) (3.7 ) (4.1 ) — Other (0.7 ) (0.8 ) (2.1 ) Effective tax rate 11.2 % 7.4 % 31.5 % (1) Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation ended or will end at various dates between 2017 and 2024. (2) For the year ended December 31, 2017, includes a $17 million increase to Income tax expense related to the remeasurement of deferred income taxes as a result of the enacted tax rate change under the TCJA. (3) The majority of excess deferred income taxes related to remeasurement under the TCJA is subject to IRS normalization rules and will be amortized over the remaining regulatory life of the assets using the average rate assumption method. Deferred income tax assets and liabilities consist of the following (in millions): As of December 31, 2019 2018 Deferred income tax assets: Employee benefits $ 119 $ 134 Price risk management 26 36 Regulatory liabilities 22 26 Tax credits 64 52 Other — 9 Total deferred income tax assets 231 257 Deferred income tax liabilities: Depreciation and amortization 496 511 Regulatory assets 103 115 Other 10 — Total deferred income tax liabilities 609 626 Deferred income tax liability, net $ 378 $ 369 As of December 31, 2019 , PGE has federal credit carryforwards of $64 million , consisting of PTCs, which will expire at various dates through 2039 . PGE believes that it is more likely than not that its deferred income tax assets as of December 31, 2019 and 2018 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2019 , and 2018 , PGE had no material unrecognized tax benefits. PGE and its subsidiaries file a consolidated federal income tax return. The Company also files income tax returns in the states of Oregon, California, and Montana, and in certain local jurisdictions. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2010 and all issues were resolved related to those years. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

Equity-Based Plans

Equity-Based Plans	12 Months Ended
	Dec. 31, 2019
Equity Based Plans [Abstract]
Stock Purchase Plan [Text Block]	EQUITY-BASED PLANS Employee Stock Purchase Plan PGE has an employee stock purchase plan (ESPP) under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock or 1,500 shares (based on fair value on the purchase date), whichever is less. Two six-month offering periods occur annually, January 1 through June 30 and July 1 through December 31, during which eligible employees may contribute toward the purchase of shares of PGE common stock. Purchases occur the last day of the offering period, at a price equal to 95% of the fair value of the stock on the purchase date. As of December 31, 2019 , there were 278,098 shares available for future issuance pursuant to the ESPP. Dividend Reinvestment and Direct Stock Purchase Plan PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2019 , there were 2,466,470 shares available for future issuance pursuant to the DRIP.

Stock-based Compensation Expens

Stock-based Compensation Expense	12 Months Ended
	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement [Text Block]	STOCK-BASED COMPENSATION EXPENSE Pursuant to the Portland General Electric Company Stock Incentive Plan as amended and restated effective February 13, 2018 (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs), to non-employee directors, officers, or certain key employees. RSU activity is summarized in the following table: Units Weighted Average Grant Date Fair Value Nonvested units as of December 31, 2016 458,792 $ 34.68 Granted 202,145 41.96 Forfeited (64,840 ) 39.57 Vested (196,721 ) 31.78 Nonvested units as of December 31, 2017 399,376 37.98 Granted 198,864 37.99 Forfeited (8,556 ) 39.73 Vested (160,771 ) 36.77 Nonvested units of December 31, 2018 428,913 38.43 Granted 210,555 49.06 Forfeited (9,041 ) 41.68 Vested (167,037 ) 37.52 Nonvested units as of December 31, 2019 463,390 43.52 A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 2,902,576 shares remain available for future issuance as of December 31, 2019 . Outstanding RSUs provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. Each DER represents an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vests on the same schedule as the related RSU. The DERs are settled in shares of PGE common stock valued either at the closing stock price on the vesting date (for performance-based RSUs) or dividend payment date (for all other grants). Time-based RSUs generally vest over a period of up to three years from the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was $1 million for the years ended December 31, 2019 , 2018 , and 2017 . Performance-based RSUs vest based on the extent to which performance goals are met at the end of a three-year performance period, subject to adjustment by the Compensation and Human Resources Committee of PGE’s Board of Directors. The number of RSUs that may vest under grants awarded in 2018 and 2017 is based on two equally-weighted metrics: i) actual return on equity relative to allowed return on equity; and ii) a relative total shareholder return (TSR) of PGE’s common stock as compared to an index of peer companies during the performance period. Based on the attainment of the goals, the number of RSUs that vest can range from zero to 175% of the RSUs granted. The number of RSUs that may vest under grants awarded in 2019 is based on three equally-weighted metrics: i) actual return on equity relative to allowed return on equity; ii) average EPS growth; and iii) power supply portfolio decarbonization—and relative TSR as a modifier to the total of the three equally-weighted metrics. Based on the attainment of the goals, the number of RSUs that vest can range from zero to 200% of the RSUs granted. For return on equity, average EPS growth and power supply portfolio decarbonization metrics of the performance-based RSUs, fair value is measured based on the NYSE closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation with the following weighted average assumptions: 2019 2018 2017 Risk-free interest rate 2.5 % 2.4 % 1.5 % Expected term (in years) 3.0 3.0 3.0 Volatility 14.8 % - 74.5 % 14.7 % - 21.8 % 15.6 % - 22.9 % There is no expected dividend yield used in the valuation, as it is assumed that all dividends distributed during the performance period are reinvested in the Company’s underlying stock. The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 123.0% , 86.6% , and 89.1% of awarded performance-based RSUs for the respective 2019 , 2018 , and 2017 grants, with an estimated 5% forfeiture rate. The total value of performance-based RSUs vested was $7 million for the year ended December 31, 2019 , $4 million for 2018 , and $6 million for 2017 . Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $9 million for the year ended December 31, 2019 , $5 million for 2018 , and $7 million in 2017 . Such amounts differ from those reported in the consolidated statements of shareholders’ equity for stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. Not included in Administrative and other expenses in the consolidated statements of income, is the net impact from these income tax payments, partially offset by the issuance of DERs, resulting in a charge to shareholders’ equity of $2 million in 2019 , and $2 million in 2018 and $3 million in 2017 . As of December 31, 2019 , unrecognized stock-based compensation expense was $10 million , which is expected to be recognized over a weighted average period of one to three years. No stock-based compensation costs have been capitalized.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2019
Earnings Per Share [Abstract]
Earnings Per Share	EARNINGS PER SHARE Basic earnings per share are computed based on the weighted average number of common shares outstanding during the year. 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 year using the treasury stock method. Potential common shares consist of employee stock purchase plan shares and contingently issuable time-based and performance-based RSUs, along with associated DERs. Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands): Years Ended December 31, 2019 2018 2017 Weighted average common shares outstanding—basic 89,353 89,215 89,056 Dilutive effect of potential common shares 206 132 120 Weighted average common shares outstanding—diluted 89,559 89,347 89,176

Commitments and Guarantees

Commitments and Guarantees	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Commitments and Guarantees [Text Block]	COMMITMENTS AND GUARANTEES Purchase Commitments As of December 31, 2019 , PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): Payments Due 2020 2021 2022 2023 2024 Thereafter Total Capital and other purchase commitments $ 393 $ 130 $ 14 $ 4 $ 1 $ 56 $ 598 Purchased power and fuel: Electricity purchases 193 189 220 219 215 2,327 3,363 Capacity contracts — 9 9 9 9 9 45 Public utility districts 16 15 13 13 12 50 119 Natural gas 59 45 40 38 42 603 827 Coal and transportation 27 27 27 27 27 27 162 Total $ 688 $ 415 $ 323 $ 310 $ 306 $ 3,072 $ 5,114 Capital and other purchase commitments— Certain commitments have been made for 2020 and beyond that include those related to hydro licenses, upgrades to generation, distribution, and transmission facilities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges. Electricity purchases and Capacity contracts— PGE has power purchase agreements with counterparties, which expire at varying dates through 2051, and power capacity contracts through 2025. Public utility districts —PGE has long-term power purchase agreements with certain public utility districts (PUDs) in the state of Washington: • Grant County PUD for the Priest Rapids and Wanapum projects, and • Douglas County PUD for the Wells project. Under the Grant County agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether they are operable or not. Under the Douglas County agreement, the Company is required to make monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas County’s loads, and included the estimated amounts in the table above. The future minimum payments for the PUDs in the preceding table reflect the principal and capacity payments only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions): Capacity Charges and Revenue Bonds as of December 31, 2019 PGE’s Average Share as of December 31, 2019 Contract Expiration Total PGE Contract Costs Output Capacity 2019 2018 2017 (in MW) Priest Rapids and Wanapum $ 1,302 8.6 % 163 2052 $ 21 $ 17 $ 16 Wells 651 13.6 98 2028 16 11 11 The agreements for Priest Rapids, Wanapum, and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro-rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be responsible for a pro-rata portion of the defaulting purchaser’s share with no limitation, regardless of the reason for any default. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax-exempt status of any of the public utility district’s outstanding debt for the portion of the project that benefits tax-exempt purchasers. Natural gas— PGE has contracts for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities. Coal and transportation —PGE has coal and related rail transportation agreements with take-or-pay provisions related to Boardman that expire in December 2020. The Company also has a coal agreement with take-or-pay provisions related to Colstrip that expires in December 2025. 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 December 31, 2019 , management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the consolidated balance sheets with respect to these indemnities.

Leases (Notes)

Leases (Notes)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Finance Leases [Text Block]	LEASES PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability. Operating leases reflect lease expense on a straight-line basis, while finance leases result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes. PGE does not record leases with a term of 12-months or less in the consolidated balance sheets. Total short-term lease costs as of December 31, 2019 are immaterial. PGE has lease agreements with lease and non-lease components, which are accounted for separately. The Company’s leases relate primarily to the use of land, support facilities, gas storage, and power purchase agreements that rely on identified plant. Variable payments are generally related to gas storage and power purchase agreements for components dependent upon variable factors, such as energy production and property taxes, and are not included in the determination of the present value of lease payments. The components of lease cost were as follows (in millions): 2019 Operating lease cost $ 7 Finance lease cost: Amortization of right-of-use assets $ 3 Interest on lease liabilities 6 Total finance lease cost $ 9 Variable lease cost $ 19 Supplemental information related to amounts and presentation of leases in the consolidated balance sheets is presented below (in millions): Balance Sheet Classification December 31, 2019 Operating Leases: Operating lease right-of-use assets Other noncurrent assets $ 51 Current liabilities Accrued expenses and other current liabilities $ 8 Noncurrent liabilities Other noncurrent liabilities 43 Total operating lease liabilities $ 51 Finance Leases: Finance lease right-of-use assets Electric utility plant, net $ 150 Current liabilities Current portion of finance lease obligations $ 16 Noncurrent liabilities Finance lease obligations, net of current portion 135 Total finance lease liabilities $ 151 Lease term and discount rates were as follows: December 31, 2019 Weighted Average Remaining Lease Term Operating leases 24 years Finance leases 29 years Weighted Average Discount Rate Operating leases 3.5 % Finance leases 7.3 % PGE’s gas storage finance lease contains five 10-year renewal periods which have not been included in the finance lease obligation. As of December 31, 2019 , maturities of lease liabilities were as follows (in millions): Operating Leases Finance Leases 2020 $ 8 $ 16 2021 8 16 2022 8 16 2023 8 14 2024 7 14 Thereafter 46 235 Total lease payments 85 311 Less imputed interest (34) (160) Total $ 51 $ 151 Supplemental cash flow information related to leases was as follows (in millions): December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 7 Operating cash flows from finance leases 5 Financing cash flows from finance leases 4 Right-of-use assets obtained in leasing arrangements: Operating leases $ 56 Finance leases 154 2018 Lease Obligations As of December 31, 2018 , PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2019 $ 6 $ 11 $ 4 2020 6 14 5 2021 6 13 5 2022 6 13 6 2023 5 13 7 Thereafter 67 225 97 Total minimum lease payments 96 $ 289 $ 124 Less imputed interest (47 ) Present value of net minimum lease payments 49 Less current portion (2 ) Non-current portion $ 47 Capital Leases —PGE entered into agreements to purchase natural gas transportation capacity via a 24-mile natural gas pipeline, Carty Lateral, that was constructed to serve the Carty natural gas-fired generating plant. The Company has entered into a 30-year agreement to purchase the entire capacity of Carty Lateral, which is approximately 175 thousand 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 As of December 31, 2018 , a capital lease asset of $57 million was reflected within Electric utility plant and accumulated amortization of such assets of $8 million was reflected within Accumulated depreciation and amortization in the consolidated balance sheets. The present value of the future minimum lease payments due under the agreement included $2 million within Accrued expenses and other current liabilities and $47 million in Other noncurrent liabilities on the consolidated balance sheets. 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. Amortization of the leased asset of $3 million and interest expense of $4 million was recorded to Purchased power and fuel expense in the consolidated statements of income through December 31, 2018. Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the capital lease obligation and related capital lease asset as it no longer met the definition of a lease. Build-to-suit —PGE entered into a 30-year lease agreement with a local natural gas company, NW Natural, to expand their natural gas storage facilities, including the development of an underground storage reservoir and construction of a new compressor station and 13-miles of pipeline, which are collectively designed to provide no-notice storage and transportation services to PW1, PW2, and Beaver. Construction of the expansion project was completed in the second quarter of 2019 at a cost of $149 million . Due to the level of PGE’s involvement during the construction period, the Company was deemed to be the owner of the assets for accounting purposes during the construction period. As a result, PGE recorded $131 million to Construction work-in-progress within Electric utility plant, net and a corresponding liability for the same amount to Other noncurrent liabilities in the consolidated balance sheets as of December 31, 2018 . Pursuant to the adoption of the new lease accounting standard, Topic 842, PGE derecognized the build-to-suit assets and liabilities as they are no longer considered to meet the build-to-suit criteria under the new standard. For additional information regarding the new lease accounting standard, see Note 2, Summary of Significant Accounting Policies. The table above reflects PGE’s estimated future minimum lease payments pursuant to the agreement based on estimated costs. Operating leases —PGE has various operating leases associated with leases of land, support facilities, and power purchase agreements that rely on identified plant that expire in various years, extending through 2096. Rent expense was $7 million in 2018 . Contingent rents related to power purchase agreements was $14 million in 2018. Sublease income was $4 million in 2018.

Jointly-owned Plant

Jointly-owned Plant	12 Months Ended
	Dec. 31, 2019
Jointly-owned Plant [Abstract]
Jointly-owned Plant [Text Block]	JOINTLY-OWNED PLANT As of December 31, 2019 , PGE had the following investments in jointly-owned plant (dollars in millions): PGE Share In-service Date Plant In-service Accumulated Depreciation* Construction Work In Progress Boardman 90.00 % 1980 $ 517 $ 478 $ — Colstrip 20.00 1986 550 375 14 Pelton/Round Butte 66.67 1958 / 1964 265 78 6 Total $ 1,332 $ 931 $ 20 * Excludes AROs and accumulated asset retirement removal costs. Under the respective joint operating agreements for the generating facilities, each participating owner is responsible for financing its share of capital and operating expenses. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.

Contingencies

Contingencies	12 Months Ended
	Dec. 31, 2019
Contingencies [Abstract]
Contingencies [Text Block]	CONTINGENCIES PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. 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. PGE 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. EPA Investigation of Portland Harbor An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 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. PGE was included among the Potentially Responsible Parties (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 had been completed pursuant to an agreement between the EPA and several PRPs known as the Lower Willamette Group (LWG), which did not include PGE. The LWG funded the remedial investigation and feasibility study and stated that it had incurred $115 million in investigation-related costs. The Company anticipates that such costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy. The EPA finalized the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of the Portland Harbor site, which has an undiscounted estimated total cost of $1.7 billion , comprised of $1.2 billion related to remediation construction costs and $0.5 billion related to long-term operation and maintenance costs. Remediation construction costs were estimated to be incurred over a 13-year period, with long-term operation and maintenance costs estimated to be incurred over a 30-year period from the start of construction. The EPA acknowledged the estimated costs are based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost. A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of the Portland Harbor Superfund site have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. EPA is currently seeking parties to sign up to perform remedial design. PGE continues to participate in a voluntary process to determine an appropriate allocation of costs amongst the PRPs. Significant uncertainties remain surrounding facts and circumstances that are integral to the determination of such an allocation percentage, remedial design, a final allocation methodology, and data with regard to property specific activities and history of ownership of sites within Portland Harbor that will inform the precise boundaries for clean-up. It is probable that PGE will share in a portion of the costs related to Portland Harbor. However, based on the above facts and remaining uncertainties, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that represents PGE’s portion of the liability to clean-up Portland Harbor, although such costs could be material to PGE’s financial position. In cases in which 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 are referred to as Natural Resource Damages (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the state of Oregon, the Confederated Tribes of the Grand Ronde Community of Oregon, the Confederated Tribes of Siletz Indians, the Confederated Tribes of the Umatilla Indian Reservation, the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS), and the Nez Perce Tribe. 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. The Company believes that PGE’s portion of NRD liabilities related to Portland Harbor will not have a material impact on its results of operations, financial position, or cash flows. The impact of such costs to the Company’s results of operations is mitigated by the Portland Harbor Environmental Remediation Account (PHERA) mechanism. As approved by the OPUC in 2017, the PHERA allows the Company to defer and recover incurred environmental expenditures related to the Portland Harbor Superfund Site through a combination of third-party proceeds, such as insurance recoveries, and if necessary, through customer prices. The mechanism established annual prudency reviews of environmental expenditures and third-party proceeds. Annual expenditures in excess of $6 million , excluding expenses related to contingent liabilities, are subject to an annual earnings test and would be ineligible for recovery to the extent PGE’s actual regulated return on equity exceeds its return on equity as authorized by the OPUC in PGE’s most recent general rate case. PGE’s results of operations may be impacted to the extent such expenditures are deemed imprudent by the OPUC or ineligible per the prescribed earnings test. The Company plans to seek recovery of any costs resulting from EPA’s determination of liability for Portland Harbor through application of the PHERA. At this time, PGE is not recovering any Portland Harbor cost from the PHERA through customer prices. 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 2003, in two separate proceedings, lawsuits were filed against PGE on behalf of two classes of electric service customers: i) Dreyer, Gearhart and Kafoury Bros., LLC v. Portland General Electric Company, Marion County Circuit Court (Circuit Court); and ii) Morgan v. Portland General Electric Company, Marion County Circuit Court. The class action lawsuits seek damages totaling $260 million , plus interest, as a result of the Company’s inclusion, in prices charged to customers, of a return on its investment in Trojan. In 2006, the Oregon Supreme Court (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. In 2008, the OPUC issued an order (2008 Order) that required PGE to provide refunds, including interest, which were completed in 2010. Following appeals, the 2008 Order was upheld by the Oregon Court of Appeals in 2013 and by the OSC in 2014. In 2015, based on a motion filed by PGE, the Marion County Circuit Court lifted the abatement on the class action proceedings and heard oral argument on the Company’s motion for Summary Judgment. In 2016, the Circuit Court entered a general judgment that granted the Company’s motion for Summary Judgment and dismissed all claims by the plaintiffs. The plaintiffs subsequently appealed the Circuit Court dismissal to the Court of Appeals for the state of Oregon. In November 2019, the Court of Appeals issued an opinion that affirmed the Circuit Court dismissal. On December 30, 2019, the plaintiffs filed a motion for reconsideration, which the Court of Appeals denied on February 4, 2020. PGE believes that the 2014 OSC decision, the decisions of the Circuit Court and the Court of Appeals that followed have reduced the risk of any loss to the Company beyond the amounts previously recorded and refunds discussed above. However, because the class actions remain subject to a potential petition for review to the OSC, 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. Deschutes River Alliance Clean Water Act Claims In August 2016, the Deschutes River Alliance (DRA) filed a lawsuit against the Company (Deschutes River Alliance v. Portland General Electric Company, U.S. District Court of the District of Oregon) that sought injunctive and declaratory relief against PGE under the Clean Water Act (CWA) related to alleged past and continuing violations of the CWA. Specifically, DRA claimed PGE had violated certain conditions contained in PGE’s Water Quality Certification for the Pelton/Round Butte Hydroelectric Project (Project) related to dissolved oxygen, temperature, and measures of acidity or alkalinity of the water. DRA alleged the violations are related to PGE’s operation of the Selective Water Withdrawal (SWW) facility at the Project. The SWW, located above Round Butte Dam on the Deschutes River in central Oregon, is, among other things, designed to blend water from the surface of the reservoir with water near the bottom of the reservoir and was constructed and placed into service in 2010, as part of the FERC license requirements for the purpose of restoration and enhancement of native salmon and steelhead fisheries above the Project. DRA has alleged that PGE’s operation of the SWW has caused the above-referenced violations of the CWA, which in turn have degraded the fish and wildlife habitat of the Deschutes River below the Project and harmed the economic and personal interests of DRA’s members and supporters. In March and April 2018, DRA and PGE filed cross-motions for summary judgment and PGE and CTWS, which co-own the Project, filed separate motions to dismiss. CTWS initially appeared as a friend of the court, but subsequently was found to be a necessary party to the lawsuit and joined as a defendant. In August 2018, the U.S. District Court of the District of Oregon (District Court) denied DRA’s motions for partial summary judgment and granted PGE’s and CTWS’s cross-motions for summary judgment, ruling in favor of PGE and CTWS. The District Court found that DRA had not shown a genuine dispute of material fact sufficient to support its contention that PGE and CTWS were operating the Project in violation of the CWA, and accordingly dismissed the case. In October 2018, DRA filed an appeal, and PGE and CTWS filed cross-appeals, to the Ninth Circuit Court of Appeals. In December 2019, the Court of Appeals closed the case and vacated the briefing schedule, pending ongoing discussions among the parties. The Company cannot predict the outcome of this matter or determine the likelihood of whether the outcome of this matter will result in a material 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, which may result in judgments against the Company. Although management currently believes that resolution of such matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

Basis of Presentation Basis of

Basis of Presentation Basis of Presentation (Policies)	12 Months Ended
	Dec. 31, 2019
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 18, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies [Abstract]
Cash and Cash Equivalents, Policy [Policy Text Block]	Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents,
Accounts Receivable [Policy Text Block]	Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and state (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning eight business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. Provisions for uncollectible accounts receivable related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates are based on management’s assessment of the probability of collection, aging of accounts receivable, bad debt write-offs, actual customer billings, and other factors.
Derivatives, Policy [Policy Text Block]	PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statements of income, offset by the effects of regulatory accounting. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net variable power costs (NVPC). In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, the Company recognizes a realized gain or loss on the derivative instrument. Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement .
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets
Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block]	Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheets
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, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value.
Property, Plant and Equipment, Policy [Policy Text Block]	Electric utility plant is capitalized at original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at PGE’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining FERC licenses for the Company’s hydroelectric projects are capitalized and amortized over the related license period.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	PGE records AFDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. AFDC is capitalized as part of the cost of plant and credited to the consolidated statements of income.
Regulatory Depreciation and Amortization, Policy [Policy Text Block]	Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage.
Depreciation Lives [Policy Text Block]	Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2020 to 2059
Plant Retirement and Abandonment, Policy [Policy Text Block]	When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities.
Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block]	Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50
Marketable Securities, Policy [Policy Text Block]	All of PGE’s investments in marketable securities included in NDT and NQBP trust on the consolidated balance sheets, are classified as equity or trading debt securities. These securities are classified as noncurrent because they are not available for use in operations. Such securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the NQBP trust assets are included in Other income, net. Realized and unrealized gains and losses on the NDT fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold is based on the average cost method.
Public Utilities, Policy [Policy Text Block]	PGE applies regulatory accounting, which results in the creation of regulatory assets and regulatory liabilities. Regulatory assets represent: i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process; or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as: i) prices are established by, or subject to, approval by independent third-party regulators; ii) prices are designed to recover the specific enterprise’s cost of service; and iii) in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices.
Power Cost [Policy Text Block]	PGE is subject to a power cost adjustment mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1%
Asset Retirement Obligation [Policy Text Block]	Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred.
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental 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 determined, 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 why the estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event. Gain contingencies are recognized when realized and are disclosed when material. For additional information concerning the Company’s contingencies, see Note 19, Contingencies. 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. PGE 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate.
Revenue [Policy Text Block]	Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided.
Franchise Tax [Policy Text Block]	Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that remained unbilled to customers. The estimate, which is classified as Unbilled revenues in the Company’s consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.
Share-based Payment Arrangement [Policy Text Block]	The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.
Income Tax, Policy [Policy Text Block]	Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.
Income Tax Uncertainties, Policy [Policy Text Block]	Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheets.
Interest and Penalties Related to Income Taxes [Policy Text Block]	PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Revenue Recogniton Revenue Re_2

Revenue Recogniton Revenue Recognition (Policies)	12 Months Ended
	Dec. 31, 2019
Revenue Recognition [Abstract]
Revenue [Policy Text Block]	Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided.
Revenue from Contract with Customer [Policy Text Block]	PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Revenue, Transaction Price Measurement, Tax Exclusion [Policy Text Block]	Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers associated with activities for the benefit of the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the consolidated statements of income.
Utility, Revenue and Expense Recognition, Policy [Policy Text Block]	PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Policies)	12 Months Ended
	Dec. 31, 2019
Fair Value of Financial Instruments [Abstract]
Fair Value of Financial Instruments, Policy [Policy Text Block]	PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value as of December 31, 2019 and 2018 . The Company 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 measurement date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement 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. 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.
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]	Assets held in the NDT and NQBP trusts are recorded at fair value in PGE’s 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 measurement date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are 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 measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE. 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. 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. The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Liabilities from interest rate swap derivatives are recorded at fair value in PGE’s consolidated balance sheets and consist of forward starting interest rate swap lock agreements to hedge a portion of its interest rate risk associated with anticipated issuances of fixed-rate, long-term debt securities. To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness. Future cash flows of the interest rate swap derivatives are equal to the fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period. Assets and liabilities from price risk management activities are recorded at fair value in PGE’s consolidated balance sheets and consist of derivative instruments entered into by the Company to manage its exposure to commodity price risk and foreign currency exchange rate risk and to reduce volatility in NVPC. For additional information regarding these assets and liabilities, see Note 6, Risk Management. For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps. Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer-term commodity forwards, futures, and swaps.
Transfers in and out of Level 3 [Policy Text Block]	Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2019 and 2018 , 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.
Debt, Policy [Policy Text Block]	Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCRBs) is classified as a Level 2 fair value measurement.

Price Risk Management (Policies

Price Risk Management (Policies)	12 Months Ended
	Dec. 31, 2019
Price Risk Management [Abstract]
Gross Reporting of Positive and Negative Exposures Related to Derivative Instruments [Policy Text Block]	PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement at gross values on the consolidated balance sheet. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given 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.

Asset Retirement Obligations (P

Asset Retirement Obligations (Policies)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation [Policy Text Block]	Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques because quoted market prices and market-risk premiums are not available. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred.

Employee Benefits (Policies)

Employee Benefits (Policies)	12 Months Ended
	Dec. 31, 2019
Employee Benefits [Abstract]
pension and other postretirement benefits valuation methodology [Policy Text Block]	The following discussion provides information regarding the methods used in valuation of the various asset class investments held in the pension and other postretirement benefit plan trusts. Money market funds— PGE invests in money market funds that seek to maintain a stable NAV. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Equity securities— Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace. Debt Securities— Debt security investment funds are classified as Level 2 securities as pricing for underlying securities are determined by evaluating pricing data, such as broker quotes for similar securities, adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, if applicable. Collective trust funds— Domestic and international mutual fund assets and debt security assets, including municipal debt and corporate credit securities, mortgage-backed securities, and asset back securities assets, are included in commingled trusts or separately managed accounts. The Company believes the redemption value of the collective trust funds are likely to be the fair value, which is represent by the net asset value as a practical expedient. The funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Private equity funds— PGE invests in a combination of primary and secondary fund-of-funds, which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the non-qualified benefit plans’ obligations recognized in net income and the unfunded position. The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate.
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]	The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, equity securities, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions that are reviewed annually by PGE and updated as appropriate, with measurement dates of December 31.
Non-qualified benefit [Policy Text Block]	Non-Qualified Benefit Plan —The NQBP in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also includes pension make-up benefits for employees that participate in the unfunded Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide funding for the future requirements of these plans. The assets of such trust are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bonds, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the NQBP is December 31. For further information regarding these trust investments, see Note 5, Fair Value of Financial Instruments. Other NQBP —In addition to the NQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. PGE holds investments in a NQBP trust that are intended to be a funding source for these plans.

Commitments and Guarantees (Pol

Commitments and Guarantees (Policies)	12 Months Ended
	Dec. 31, 2019
Commitments and Contingencies Disclosure [Abstract]
Minimum Guarantees, Policy [Policy Text Block]	PGE enters into financial agreements and power and natural gas purchase and sale agreements that include indemnification provisions relating to certain claims or liabilities that may arise relating to the transactions contemplated by these agreements. Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities.

Leases Leases (Policies)

Leases Leases (Policies)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lessee, Leases [Policy Text Block]	PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability. Operating leases reflect lease expense on a straight-line basis, while finance leases result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

Contingencies (Policies)

Contingencies (Policies)	12 Months Ended
	Dec. 31, 2019
Contingencies [Abstract]
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental 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 determined, 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 why the estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event. Gain contingencies are recognized when realized and are disclosed when material. For additional information concerning the Company’s contingencies, see Note 19, Contingencies. 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. PGE 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) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2019
Summary of Significant Accounting Policies [Abstract]
Estimated average service lives [Table Text Block]	Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years): Generation, excluding thermal: Hydro 98 Wind 30 Transmission 59 Distribution 46 General 12
Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]	The following table illustrates the adjustments made upon adoption of Topic 842 and the corresponding line items affected on the Company’s consolidated balance sheets (in millions): January 1, 2019 Topic 842 Adoption Adjustments Increase due to existing operating and finance leases Decrease due to build-to-suit reassessment Decrease due to capital lease reassessment Total Increase/(Decrease) Assets Electric utility plant, net $ 2 $ (131 ) $ (49 ) $ (178 ) Other noncurrent assets 42 — — 42 Liabilities Accrued expenses and other current liabilities 5 — (2 ) 3 Other noncurrent liabilities 39 (131 ) (47 ) (139 )

Revenue Recogniton Revenue Re_3

Revenue Recogniton Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2019
Revenue Recognition [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents PGE’s revenue, disaggregated by customer type (in millions): Year Ended December 31, 2019 2018 Retail: Residential $ 981 $ 948 Commercial 636 647 Industrial 196 185 Direct access customers 44 43 Subtotal 1,857 1,823 Alternative revenue programs, net of amortization 2 3 Other accrued (deferred) revenues, net (1) 22 (45 ) Total retail revenues 1,881 1,781 Wholesale revenues (2) 170 159 Other operating revenues 72 51 Total revenues $ 2,123 $ 1,991 (1) Amounts for the year ended December 31, 2019 and 2018 is primarily comprised of $23 million of amortization and $45 million of deferral, respectively, related to the 2018 net tax benefits due to the change in corporate tax rate under the TCJA. For further information, see Note 12, Income Taxes. (2) Wholesale revenues include $50 million and $42 million related to electricity commodity contract derivative settlements for the year ended December 31, 2019 and 2018 , respectively. Price risk management derivative activities are included within Total revenues but do not represent revenues from contracts with customers as defined by GAAP, pursuant to Topic 606. For further information, see Note 6, Risk Management.

Balance Sheet Components (Table

Balance Sheet Components (Tables)	12 Months Ended
	Dec. 31, 2019
Balance Sheet Components [Abstract]
SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]	The following is the activity in the allowance for uncollectible accounts (in millions): Years Ended December 31, 2019 2018 2017 Balance as of beginning of year $ 15 $ 6 $ 6 Increase in provision 2 14 6 Amounts written off, less recoveries (12 ) (5 ) (6 ) Balance as of end of year $ 5 $ 15 $ 6
Schedule of Other Assets and Other Liabilities [Table Text Block]	Other current assets and Accrued expenses and other current liabilities consist of the following (in millions): As of December 31, 2019 2018 Other current assets: Prepaid expenses $ 63 $ 54 Margin deposits 16 16 Assets from price risk management activities 25 20 $ 104 $ 90 Accrued expenses and other current liabilities: Regulatory liabilities—current $ 44 $ 36 Accrued employee compensation and benefits 74 66 Accrued dividends payable 36 34 Accrued interest payable 25 27 Accrued taxes payable 33 34 Other 103 71 $ 315 $ 268
Public Utility Property, Plant, and Equipment [Table Text Block]	Electric utility plant, net consist of the following (in millions): As of December 31, 2019 2018 Electric utility plant: Generation $ 4,749 $ 4,600 Transmission 848 580 Distribution 3,917 3,838 General 656 611 Intangible 758 715 Total in service 10,928 10,344 Accumulated depreciation and amortization (4,095 ) (3,803 ) Total in service, net 6,833 6,541 Construction work-in-progress 328 346 Electric utility plant, net $ 7,161 $ 6,887

Fair Value of Financial Instr_3

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2019
Fair Value of Financial Instruments [Abstract]
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): As of December 31, 2019 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 26 $ — $ — $ — $ 26 Nuclear decommissioning trust: (1) Debt securities: Domestic government 8 16 — — 24 Corporate credit — 9 — — 9 Money market funds measured at NAV (2) — — — 13 13 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 7 — 16 Natural gas — 21 1 — 22 $ 43 $ 55 $ 8 $ 13 $ 119 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 14 $ 105 $ — $ 119 Natural gas — 12 — — 12 $ — $ 26 $ 105 $ — $ 131 (1) Activities are subject to regulation, with 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 $29 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. As of December 31, 2018 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 112 $ — $ — $ — $ 112 Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 18 — — 25 Corporate credit — 10 — — 10 Money market funds measured at NAV (2) — — — 7 7 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities—domestic 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 3 — 12 Natural gas — 8 — — 8 $ 128 $ 45 $ 3 $ 7 $ 183 Liabilities: Interest rate swap derivatives $ — $ 4 $ — $ — 4 Price risk management activities: (1) (4) Electricity — 10 84 — 94 Natural gas — 51 7 — 58 $ — $ 65 $ 91 $ — $ 156 (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 $27 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): Level 1 Level 2 Level 3 Other * Total As of December 31, 2019: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 49 $ — $ — $ — $ 49 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 632 632 Private equity funds — — — 9 9 $ 49 $ — $ — $ 646 $ 695 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 9 — — — 9 Debt securities—Domestic — 5 — — 5 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 13 $ 34 As of December 31, 2018: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 67 $ — $ — $ — $ 67 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 463 463 Private equity funds — — — 11 11 $ 67 $ — $ — $ 479 $ 546 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 7 7 $ 11 $ 8 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.
Fair Value Option, 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: Significant Price per Unit Fair Value Valuation Unobservable Weighted Commodity Contracts Assets Liabilities Technique Input Low High Average (in millions) As of December 31, 2019: Electricity physical forward $ — $ 104 Discounted cash flow Electricity forward price (per MWh) $ 12.53 $ 59.00 $ 36.92 Natural gas financial swaps 1 — Discounted cash flow Natural gas forward price (per Dth) 1.39 3.73 1.90 Electricity financial futures 7 1 Discounted cash flow Electricity forward price (per MWh) 10.57 66.32 45.11 $ 8 $ 105 As of December 31, 2018: Electricity physical forward $ 3 $ 84 Discounted cash flow Electricity forward price (per MWh) $ 14.60 $ 69.00 $ 45.00 Natural gas financial swaps — 7 Discounted cash flow Natural gas forward price (per Dth) 0.95 4.64 1.82 Electricity financial futures — — Discounted cash flow Electricity forward price (per MWh) 20.75 35.46 28.63 $ 3 $ 91
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Table Text Block]	Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): Years Ended December 31, 2019 2018 Net liabilities from price risk management activities as of beginning of year $ 88 $ 139 Net realized and unrealized losses/(gains) * 10 (40 ) Net transfers out of Level 3 to Level 2 (1 ) (11 ) Net liabilities from price risk management activities as of end of year $ 97 $ 88 Level 3 net unrealized losses/(gains) that have been fully offset by the effect of regulatory accounting $ 16 $ (32 ) * Includes $6 million in net realized gains in 2019 and $8 million in 2018 .

Price Risk Management (Tables)

Price Risk Management (Tables)	12 Months Ended
	Dec. 31, 2019
Price Risk Management [Abstract]
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): As of December 31, 2019 2018 Current assets: Commodity contracts: Electricity $ 9 $ 11 Natural gas 16 7 Total current derivative assets (1) 25 18 Noncurrent assets: Commodity contracts: Electricity 7 1 Natural gas 6 1 Total noncurrent derivative assets (1) 13 2 Total derivative assets (2) $ 38 $ 20 Current liabilities: Commodity contracts: Electricity $ 14 $ 16 Natural gas 9 35 Total current derivative liabilities 23 51 Noncurrent liabilities: Commodity contracts: Electricity 105 78 Natural gas 3 23 Total noncurrent derivative liabilities 108 101 Total derivative liabilities (2) $ 131 $ 152 (1) Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the consolidated balance sheets. (2) As of December 31, 2019 and 2018 , no commodity derivative assets or liabilities were designated as hedging instruments.
Schedule of Derivative Instruments [Table Text Block]	PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions): As of December 31, 2019 2018 Commodity contracts: Electricity 6 MWh 5 MWh Natural gas 145 Dth 123 Dth Foreign currency exchange $ 23 Canadian $ 18 Canadian
Derivatives Not Designated as Hedging Instruments [Table Text Block]	Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Purchased power and fuel in the consolidated statements of income and were as follows (in millions): Years Ended December 31, 2019 2018 2017 Commodity contracts: Electricity $ 20 $ (34 ) $ 41 Natural Gas (32 ) 21 85 Foreign currency exchange (1 ) 1 (1 ) Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net amounts recognized in Net income, net gains of $2 million , net gains of $18 million , and net losses of $82 million for the years ended December 31, 2019 , 2018 , and 2017 , respectively, have been offset.
Schedule of Price Risk Derivatives [Table Text Block]	Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized (gains)/losses recorded as of December 31, 2019 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2020 2021 2022 2023 2024 Thereafter Total Commodity contracts: Electricity $ 5 $ 1 $ 7 $ 7 $ 7 $ 76 $ 103 Natural gas (7 ) (2 ) (1 ) — — — (10 ) Net unrealized (gain)/loss $ (2 ) $ (1 ) $ 6 $ 7 $ 7 $ 76 $ 93
Schedule of Concentration of Risk, by Counterparty [Table Text Block]	Counterparties representing 10% or more of Assets and Liabilities from price risk management activities were as follows: As of December 31, 2019 2018 Assets from price risk management activities: Counterparty A 35 % 42 % Counterparty B 1 15 Counterparty C 13 5 Counterparty D 11 6 Counterparty E 11 9 71 % 77 % Liabilities from price risk management activities: Counterparty F 79 % 56 %

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2019
Regulatory Assets [Line Items]
Schedule of Regulatory Liabilities [Table Text Block]	Regulatory assets and liabilities consist of the following (dollars in millions): Remaining Amortization Period As of December 31, 2019 2018 Earning a Return (1) Not Earning a Return Total Total Regulatory assets: Price risk management 2035 $ — $ 95 $ 95 $ 131 Pension and other postretirement plans (2) — 213 213 222 Debt issuance costs 2049 — 26 26 16 Trojan decommissioning activities 2059 — 94 94 26 Other Various 62 10 72 67 Total regulatory assets $ 62 $ 438 $ 500 $ 462 Regulatory liabilities: Asset retirement removal costs (3) $ 1,021 $ — $ 1,021 $ 979 Deferred income taxes (4) 260 — 260 267 Asset retirement obligations (3) 54 — 54 53 Tax reform deferral (5) 2020 23 — 23 45 Other Various 47 16 63 47 Total regulatory liabilities $ 1,405 $ 16 $ 1,421 $ 1,391 (1) Earning a return includes either interest on the regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return. (2) Recovery expected over the average service life of employees. (3) Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base. (4) Refund expected primarily through amortization using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base. (5) Refund related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest, over a two-year period that began in 2019.
Schedule of Regulatory Assets [Table Text Block]	Regulatory assets and liabilities consist of the following (dollars in millions): Remaining Amortization Period As of December 31, 2019 2018 Earning a Return (1) Not Earning a Return Total Total Regulatory assets: Price risk management 2035 $ — $ 95 $ 95 $ 131 Pension and other postretirement plans (2) — 213 213 222 Debt issuance costs 2049 — 26 26 16 Trojan decommissioning activities 2059 — 94 94 26 Other Various 62 10 72 67 Total regulatory assets $ 62 $ 438 $ 500 $ 462 Regulatory liabilities: Asset retirement removal costs (3) $ 1,021 $ — $ 1,021 $ 979 Deferred income taxes (4) 260 — 260 267 Asset retirement obligations (3) 54 — 54 53 Tax reform deferral (5) 2020 23 — 23 45 Other Various 47 16 63 47 Total regulatory liabilities $ 1,405 $ 16 $ 1,421 $ 1,391 (1) Earning a return includes either interest on the regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return. (2) Recovery expected over the average service life of employees. (3) Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base. (4) Refund expected primarily through amortization using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base. (5) Refund related to the deferral of the 2018 net tax benefits due to the change in corporate tax rate under TCJA, including interest, over a two-year period that began in 2019.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations [Table Text Block]	AROs consist of the following (in millions): As of December 31, 2019 2018 Trojan decommissioning activities $ 137 $ 68 Utility plant 126 112 Non-utility property 16 17 Total asset retirement obligations 279 197 Less: current portion * 16 — Noncurrent asset retirement obligations $ 263 $ 197 * Current portion of AROs are classified within Accrued expenses and other current liabilities in the consolidated balance sheets.
Schedule of Change in Asset Retirement Obligation [Table Text Block]	The following is a summary of the changes in the Company’s AROs (in millions): Years Ended December 31, 2019 2018 2017 Balance as of beginning of year $ 197 $ 167 $ 161 Liabilities incurred — — 2 Liabilities settled (9 ) (5 ) (3 ) Accretion expense 9 8 7 Revisions in estimated cash flows 82 27 — Balance as of end of year $ 279 $ 197 $ 167

Credit Facilities (Tables)

Credit Facilities (Tables)	12 Months Ended
	Dec. 31, 2019
Line of Credit Facility [Abstract]
Schedule of Short-term Debt [Table Text Block]	Short-term borrowings under these credit facilities, and related interest rates, are reflected in the following table (dollars in millions). Year Ended December 31, 2019 Average daily amount of short-term debt outstanding $ 7 Weighted daily average interest rate * 2.6 % Maximum amount outstanding during the year $ 46 * Excludes the effect of commitment fees, facility fees and other financing fees.

Long term debt (Tables)

Long term debt (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Debt, Unclassified [Abstract]
Schedule of Long-term Debt Instruments [Table Text Block]	Long-term debt consists of the following (in millions): As of December 31, 2019 2018 First Mortgage Bonds , rates range from 2.51% to 9.31%, with a weighted average rate of 4.63% in 2019 and 5.01% in 2018, due at various dates through 2050 $ 2,510 $ 2,390 Pollution Control Revenue Bonds , rates at 5%, due 2033 119 119 Pollution Control Revenue Bonds held by PGE (21 ) (21 ) Total long-term debt 2,608 2,488 Less: Unamortized debt expense (11 ) (10 ) Less: Current portion of long-term debt — (300 ) Long-term debt, net of current portion $ 2,597 $ 2,178
Schedule of Maturities of Long-term Debt [Table Text Block]	As of December 31, 2019 , the future minimum principal payments on long-term debt are as follows (in millions): Years ending December 31: 2020 $ — 2021 160 2022 — 2023 — 2024 80 Thereafter 2,368 $ 2,608

Employee Benefits (Tables)

Employee Benefits (Tables)	12 Months Ended
	Dec. 31, 2019
Employee Benefits [Abstract]
Assets and Liabilities associated with Non Qualified Benefit Plans [Table Text Block]	Trust assets and plan liabilities related to the NQBP included in PGE’s consolidated balance sheets are as follows as of December 31 (in millions): 2019 2018 NQBP Other NQBP Total NQBP Other NQBP Total Non-qualified benefit plan trust $ 17 $ 21 $ 38 $ 16 $ 20 $ 36 Non-qualified benefit plan liabilities * 24 79 103 22 81 103 * For the NQBP, excludes the current portion of $2 million in 2019 and 2018 , which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets.
Schedule of Allocation of Plan Assets [Table Text Block]	The asset allocations for the plans, and the target allocation, are as follows: As of December 31, 2019 2018 Actual Target * Actual Target * Defined Benefit Pension Plan: Equity securities 64 % 65 % 65 % 67 % Debt securities 36 35 35 33 Total 100 % 100 % 100 % 100 % Other Postretirement Benefit Plans: Equity securities 61 % 59 % 58 % 59 % Debt securities 39 41 42 41 Total 100 % 100 % 100 % 100 % Non-Qualified Benefits Plans: Equity securities 17 % 12 % 16 % 13 % Debt securities 7 12 10 13 Insurance contracts 76 76 74 74 Total 100 % 100 % 100 % 100 % * The target for the Defined Benefit Pension Plan represents the mid-point of the investment target range. Due to the nature of the investment vehicles in both the Other Postretirement Benefit Plans and the NQBP, these targets are the weighted average of the mid-point of the respective investment target ranges approved by the Investment Committee. Due to the method used to calculate the weighted average targets for the Other Postretirement Benefit Plans and NQBP, reported percentages are affected by the fair market values of the investments within the pools.
Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis [Table Text Block]	The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions): As of December 31, 2019 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 26 $ — $ — $ — $ 26 Nuclear decommissioning trust: (1) Debt securities: Domestic government 8 16 — — 24 Corporate credit — 9 — — 9 Money market funds measured at NAV (2) — — — 13 13 Non-qualified benefit plan trust: (3) Money market funds 1 — — — 1 Equity securities—domestic 7 — — — 7 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 7 — 16 Natural gas — 21 1 — 22 $ 43 $ 55 $ 8 $ 13 $ 119 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 14 $ 105 $ — $ 119 Natural gas — 12 — — 12 $ — $ 26 $ 105 $ — $ 131 (1) Activities are subject to regulation, with 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 $29 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. As of December 31, 2018 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 112 $ — $ — $ — $ 112 Nuclear decommissioning trust: (1) Debt securities: Domestic government 7 18 — — 25 Corporate credit — 10 — — 10 Money market funds measured at NAV (2) — — — 7 7 Non-qualified benefit plan trust: (3) Money market funds 2 — — — 2 Equity securities—domestic 6 — — — 6 Debt securities—domestic government 1 — — — 1 Price risk management activities: (1) (4) Electricity — 9 3 — 12 Natural gas — 8 — — 8 $ 128 $ 45 $ 3 $ 7 $ 183 Liabilities: Interest rate swap derivatives $ — $ 4 $ — $ — 4 Price risk management activities: (1) (4) Electricity — 10 84 — 94 Natural gas — 51 7 — 58 $ — $ 65 $ 91 $ — $ 156 (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 $27 million , which are recorded at cash surrender value. (4) For further information regarding price risk management derivatives, see Note 6, Risk Management. The fair values of the Company’s pension plan assets and other postretirement benefit plan assets by asset category are as follows (in millions): Level 1 Level 2 Level 3 Other * Total As of December 31, 2019: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 49 $ — $ — $ — $ 49 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 632 632 Private equity funds — — — 9 9 $ 49 $ — $ — $ 646 $ 695 Other Postretirement Benefit Plans assets: Money market funds $ 4 $ — $ — $ — $ 4 Equity securities: Domestic — 3 — — 3 International 9 — — — 9 Debt securities—Domestic — 5 — — 5 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 8 8 $ 13 $ 8 $ — $ 13 $ 34 As of December 31, 2018: Defined Benefit Pension Plan assets: Equity securities—Domestic $ 67 $ — $ — $ — $ 67 Investments measured at NAV: Money market funds — — — 5 5 Collective trust funds — — — 463 463 Private equity funds — — — 11 11 $ 67 $ — $ — $ 479 $ 546 Other Postretirement Benefit Plans assets: Money market funds $ 3 $ — $ — $ — $ 3 Equity securities: Domestic — 3 — — 3 International 8 — — — 8 Debt securities—Domestic government — 5 — — 5 Investments measured at NAV: Money market funds — — — 4 4 Collective trust funds — — — 7 7 $ 11 $ 8 $ — $ 11 $ 30 * Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.
Schedule of Defined Benefit Plans Disclosures [Table Text Block]	The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and NQBP as of and for the years ended December 31, 2019 and 2018 . Information related to the Other NQBP is not included in the following tables (dollars in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2019 2018 2019 2018 2019 2018 Benefit obligation: As of January 1 $ 811 $ 869 $ 72 $ 78 $ 24 $ 27 Service cost 16 19 2 2 — — Interest cost 34 32 3 3 1 1 Participants’ contributions — — 2 2 — — Actuarial loss (gain) 88 (67 ) 8 (7 ) 3 (1 ) Benefit payments (42 ) (39 ) (6 ) (6 ) (2 ) (3 ) Administrative expenses (2 ) (3 ) — — — — Plan amendment — — (9 ) — — — Curtailment gain — — (1 ) — — — As of December 31 $ 905 $ 811 $ 71 $ 72 $ 26 $ 24 Fair value of plan assets: As of January 1 $ 546 $ 629 $ 30 $ 33 $ 16 $ 17 Actual return on plan assets 131 (50 ) 5 (2 ) 1 (1 ) Company contributions 62 9 3 3 2 3 Participants’ contributions — — 2 2 — — Benefit payments (42 ) (39 ) (6 ) (6 ) (2 ) (3 ) Administrative expenses (2 ) (3 ) — — — — As of December 31 $ 695 $ 546 $ 34 $ 30 $ 17 $ 16 Unfunded position as of December 31 $ (210 ) $ (265 ) $ (37 ) $ (42 ) $ (9 ) $ (8 ) Accumulated benefit plan obligation as of December 31 $ 813 $ 734 N/A N/A $ 26 $ 24 Classification in consolidated balance sheet: Noncurrent asset $ — $ — $ — $ — $ 17 $ 16 Current liability — — — — (2 ) (2 ) Noncurrent liability (210 ) (265 ) (37 ) (42 ) (24 ) (22 ) Net liability $ (210 ) $ (265 ) $ (37 ) $ (42 ) $ (9 ) $ (8 ) Amounts included in comprehensive income: Net actuarial loss (gain) $ (3 ) $ 25 $ 5 $ (4 ) $ 3 $ (1 ) Net prior service credit — — (9 ) — — — Amortization of net actuarial loss (10 ) (17 ) — — (1 ) (1 ) $ (13 ) $ 8 $ (4 ) $ (4 ) $ 2 $ (2 ) Amounts included in AOCL:* Net actuarial loss (gain) $ 213 $ 226 $ 1 $ (4 ) $ 13 $ 11 Prior service cost — — (9 ) — — — $ 213 $ 226 $ (8 ) $ (4 ) $ 13 $ 11 * Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are transferred to Regulatory assets due to the future recoverability from retail customers. Accordingly, as of the balance sheet date, such amounts are included in Regulatory assets.
Schedule of Net Benefit Costs [Table Text Block]	Net periodic benefit cost consists of the following for the years ended December 31 (in millions): Defined Benefit Pension Plan Other Postretirement Benefits Non-Qualified Benefit Plans 2019 2018 2017 2019 2018 2017 2019 2018 2017 Service cost $ 16 $ 19 $ 17 $ 2 $ 2 $ 2 $ — $ — $ — Interest cost on benefit obligation 34 32 33 3 3 3 1 1 1 Expected return on plan assets (40 ) (42 ) (42 ) (2 ) (1 ) (2 ) — — — Amortization of net actuarial loss 10 17 13 — — — 1 1 1 Curtailment gain — — — (2 ) — — — — — Net periodic benefit cost $ 20 $ 26 $ 21 $ 1 $ 4 $ 3 $ 2 $ 2 $ 2
Schedule of Expected Benefit Payments [Table Text Block]	The following table summarizes the benefits expected to be paid to participants in each of the next five years and in the aggregate for the five years thereafter (in millions): Payments Due 2020 2021 2022 2023 2024 2025 - 2029 Defined benefit pension plan $ 44 $ 44 $ 45 $ 46 $ 46 $ 239 Other postretirement benefits 5 5 5 5 6 20 Non-qualified benefit plans 2 2 2 2 2 11 Total $ 51 $ 51 $ 52 $ 53 $ 54 $ 270

Income Taxes Income Taxes (Tabl

Income Taxes Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2019
Income Taxes [Abstract]
Schedule of Components of Income Tax Expense (Benefit) [Table Text Block]	Income tax expense/(benefit) consists of the following (in millions): Years Ended December 31, 2019 2018 2017 Current: Federal $ 9 $ 12 $ 4 State and local 12 22 12 21 34 16 Deferred: Federal (2 ) (15 ) 61 State and local 8 (2 ) 9 6 (17 ) 70 Income tax expense $ 27 $ 17 $ 86
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The significant differences between the U.S. federal statutory rate and PGE’s effective tax rate for financial reporting purposes are as follows: Years Ended December 31, 2019 2018 2017 Federal statutory tax rate 21.0 % 21.0 % 35.0 % Federal tax credits (1) (13.4 ) (16.7 ) (14.0 ) Change in federal tax law (2) — — 6.1 State and local taxes, net of federal tax benefit 6.5 6.5 5.0 Flow through depreciation and cost basis differences 1.5 1.5 1.5 Excess deferred tax amortization (3) (3.7 ) (4.1 ) — Other (0.7 ) (0.8 ) (2.1 ) Effective tax rate 11.2 % 7.4 % 31.5 % (1) Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation ended or will end at various dates between 2017 and 2024. (2) For the year ended December 31, 2017, includes a $17 million increase to Income tax expense related to the remeasurement of deferred income taxes as a result of the enacted tax rate change under the TCJA. (3) The majority of excess deferred income taxes related to remeasurement under the TCJA is subject to IRS normalization rules and will be amortized over the remaining regulatory life of the assets using the average rate assumption method.
Schedule of Deferred Tax Assets and Liabilities [Table Text Block]	Deferred income tax assets and liabilities consist of the following (in millions): As of December 31, 2019 2018 Deferred income tax assets: Employee benefits $ 119 $ 134 Price risk management 26 36 Regulatory liabilities 22 26 Tax credits 64 52 Other — 9 Total deferred income tax assets 231 257 Deferred income tax liabilities: Depreciation and amortization 496 511 Regulatory assets 103 115 Other 10 — Total deferred income tax liabilities 609 626 Deferred income tax liability, net $ 378 $ 369

Stock-based Compensation Expe_2

Stock-based Compensation Expense Restricted and Performance Stock Unit activity (Tables)	12 Months Ended
	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Share-based Payment Arrangement, Restricted Stock Unit, Activity [Table Text Block]	Pursuant to the Portland General Electric Company Stock Incentive Plan as amended and restated effective February 13, 2018 (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs), to non-employee directors, officers, or certain key employees. RSU activity is summarized in the following table: Units Weighted Average Grant Date Fair Value Nonvested units as of December 31, 2016 458,792 $ 34.68 Granted 202,145 41.96 Forfeited (64,840 ) 39.57 Vested (196,721 ) 31.78 Nonvested units as of December 31, 2017 399,376 37.98 Granted 198,864 37.99 Forfeited (8,556 ) 39.73 Vested (160,771 ) 36.77 Nonvested units of December 31, 2018 428,913 38.43 Granted 210,555 49.06 Forfeited (9,041 ) 41.68 Vested (167,037 ) 37.52 Nonvested units as of December 31, 2019 463,390 43.52
Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]	with the following weighted average assumptions: 2019 2018 2017 Risk-free interest rate 2.5 % 2.4 % 1.5 % Expected term (in years) 3.0 3.0 3.0 Volatility 14.8 % - 74.5 % 14.7 % - 21.8 % 15.6 % - 22.9 %

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2019
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): Years Ended December 31, 2019 2018 2017 Weighted average common shares outstanding—basic 89,353 89,215 89,056 Dilutive effect of potential common shares 206 132 120 Weighted average common shares outstanding—diluted 89,559 89,347 89,176

Commitments and Guarantees (Tab

Commitments and Guarantees (Tables)	12 Months Ended
	Dec. 31, 2019
Long-term Purchase Commitment [Line Items]
Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]	As of December 31, 2019 , PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions): Payments Due 2020 2021 2022 2023 2024 Thereafter Total Capital and other purchase commitments $ 393 $ 130 $ 14 $ 4 $ 1 $ 56 $ 598 Purchased power and fuel: Electricity purchases 193 189 220 219 215 2,327 3,363 Capacity contracts — 9 9 9 9 9 45 Public utility districts 16 15 13 13 12 50 119 Natural gas 59 45 40 38 42 603 827 Coal and transportation 27 27 27 27 27 27 162 Total $ 688 $ 415 $ 323 $ 310 $ 306 $ 3,072 $ 5,114
Schedule of Long-term Contracts for Purchase of Electric Power [Table Text Block]	PGE has long-term power purchase agreements with certain public utility districts (PUDs) in the state of Washington: • Grant County PUD for the Priest Rapids and Wanapum projects, and • Douglas County PUD for the Wells project. Under the Grant County agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether they are operable or not. Under the Douglas County agreement, the Company is required to make monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas County’s loads, and included the estimated amounts in the table above. The future minimum payments for the PUDs in the preceding table reflect the principal and capacity payments only and do not include interest, operation, or maintenance expenses. Selected information regarding these projects is summarized as follows (dollars in millions): Capacity Charges and Revenue Bonds as of December 31, 2019 PGE’s Average Share as of December 31, 2019 Contract Expiration Total PGE Contract Costs Output Capacity 2019 2018 2017 (in MW) Priest Rapids and Wanapum $ 1,302 8.6 % 163 2052 $ 21 $ 17 $ 16 Wells 651 13.6 98 2028 16 11 11

Leases Lease Obligations (Table

Leases Lease Obligations (Tables)	12 Months Ended
	Dec. 31, 2019
Leases [Abstract]
Lease, Cost [Table Text Block]	The components of lease cost were as follows (in millions): 2019 Operating lease cost $ 7 Finance lease cost: Amortization of right-of-use assets $ 3 Interest on lease liabilities 6 Total finance lease cost $ 9 Variable lease cost $ 19 Lease term and discount rates were as follows: December 31, 2019 Weighted Average Remaining Lease Term Operating leases 24 years Finance leases 29 years Weighted Average Discount Rate Operating leases 3.5 % Finance leases 7.3 %
Leases of Lessee Disclosure [Text Block]	Supplemental information related to amounts and presentation of leases in the consolidated balance sheets is presented below (in millions): Balance Sheet Classification December 31, 2019 Operating Leases: Operating lease right-of-use assets Other noncurrent assets $ 51 Current liabilities Accrued expenses and other current liabilities $ 8 Noncurrent liabilities Other noncurrent liabilities 43 Total operating lease liabilities $ 51 Finance Leases: Finance lease right-of-use assets Electric utility plant, net $ 150 Current liabilities Current portion of finance lease obligations $ 16 Noncurrent liabilities Finance lease obligations, net of current portion 135 Total finance lease liabilities $ 151
Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]	As of December 31, 2019 , maturities of lease liabilities were as follows (in millions): Operating Leases Finance Leases 2020 $ 8 $ 16 2021 8 16 2022 8 16 2023 8 14 2024 7 14 Thereafter 46 235 Total lease payments 85 311 Less imputed interest (34) (160) Total $ 51 $ 151
Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]	Supplemental cash flow information related to leases was as follows (in millions): December 31, 2019 Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 7 Operating cash flows from finance leases 5 Financing cash flows from finance leases 4 Right-of-use assets obtained in leasing arrangements: Operating leases $ 56 Finance leases 154
Contractual Obligation, Fiscal Year Maturity [Table Text Block]	As of December 31, 2018 , PGE’s estimated future minimum lease payments pursuant to capital, build-to-suit, and operating leases for the following five years and thereafter are as follows (in millions): Future Minimum Lease Payments Capital Leases Build-to-Suit Operating Leases 2019 $ 6 $ 11 $ 4 2020 6 14 5 2021 6 13 5 2022 6 13 6 2023 5 13 7 Thereafter 67 225 97 Total minimum lease payments 96 $ 289 $ 124 Less imputed interest (47 ) Present value of net minimum lease payments 49 Less current portion (2 ) Non-current portion $ 47

Jointly-owned Plant (Tables)

Jointly-owned Plant (Tables)	12 Months Ended
	Dec. 31, 2019
Jointly-owned Plant [Abstract]
Schedule of Jointly Owned Utility Plants [Table Text Block]	As of December 31, 2019 , PGE had the following investments in jointly-owned plant (dollars in millions): PGE Share In-service Date Plant In-service Accumulated Depreciation* Construction Work In Progress Boardman 90.00 % 1980 $ 517 $ 478 $ — Colstrip 20.00 1986 550 375 14 Pelton/Round Butte 66.67 1958 / 1964 265 78 6 Total $ 1,332 $ 931 $ 20 * Excludes AROs and accumulated asset retirement removal costs.

Basis of Presentation (Details)

Basis of Presentation (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)mi²sharesretail_customers	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4,000
Incorporated Cities	51
Number of Retail Customers | retail_customers	895,000
Service area population	1,900,000
Entity Number of Employees	2,949
Number of Union Employees	775
Number of Union Employees Subject to Agreement A	719
Number of Union Employees Subject to Agreement B	56
Share-based Payment Arrangement, Noncash Expense | $	$ 9	$ 5	$ 7

Summary of Significant Accoun_4

Summary of Significant Accounting Policies Estimated average service lives (Details)	12 Months Ended
	Dec. 31, 2019
Generation, excluding thermal:
Hydro	98 years
Wind	30 years
Transmission	59 years
Distribution	46 years
General	12 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies Schedule of Changes for Adoption of New Accounting Pronouncements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 178
Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(42)
Other Current Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(3)
Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	139
Accounting Standards Update 2016-02 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(44)
Accounting Standards Update 2016-02 [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(2)
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(42)
Accounting Standards Update 2016-02 [Member] | Other Current Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(5)
Accounting Standards Update 2016-02 [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(39)
Building [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(131)
Building [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Building [Member] | Other Current Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Building [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	131
Assets Held under Capital Leases [Member] | Property, Plant and Equipment [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(49)
Assets Held under Capital Leases [Member] | Other Noncurrent Assets [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	0
Assets Held under Capital Leases [Member] | Other Current Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	2
Assets Held under Capital Leases [Member] | Other Noncurrent Liabilities [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 47

Summary of Significant Accoun_6

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Excise Taxes Collected	$ 45	$ 45	$ 43
Regulatory Liabilities	1,421	1,391
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	438
Other Investments	$ 26	112
Document Period End Date	Dec. 31, 2019
Days after the due date	45 days
Wholesale accounts receivable written off	$ 0	0	$ 0
Margin deposit	16	16
Letters of Credit Outstanding, Amount	$ 15	48
Public Utilities, Allowance for Funds Used During Construction, Rate	7.10%		7.30%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 5	6	$ 6
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	$ 10	$ 11	$ 12
Depreciation expense rate	3.60%	3.60%	3.60%
Finite-Lived Intangible Assets, Accumulated Amortization	$ 366	$ 302
Amortization of Intangible Assets	64	$ 59	$ 46
Future Amortization Expense, Year One	60
Future Amortization Expense, Year Two	52
Future Amortization Expense, Year Three	46
Future Amortization Expense, Year Four	37
Future Amortization Expense, Year Five	32
Power Cost Deadband - Lower Threshold	15
Power Cost Deadband - Upper Threshold	$ 30
Public Utilities, Approved Return on Equity, Percentage	9.50%	9.50%	9.60%
Quantifying Misstatement in Current Year Financial Statements, Amount	$ 3,917	$ 3,838
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	4,095	3,803
Trojan decommissioning [Member]
Property, Plant and Equipment [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	91	25
Asset Retirement Obligation Costs [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	54	53
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Deferred Income Tax Charge [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	260	$ 267
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Previously Reported [Member]
Property, Plant and Equipment [Line Items]
Quantifying Misstatement in Current Year Financial Statements, Amount	223
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	113
Accounting Standards Update 2016-02 [Member]
Property, Plant and Equipment [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	44
Property, Plant and Equipment [Member]
Property, Plant and Equipment [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	(178)
Property, Plant and Equipment [Member] | Building [Member]
Property, Plant and Equipment [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	131
Property, Plant and Equipment [Member] | Assets Held under Capital Leases [Member]
Property, Plant and Equipment [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	49
Property, Plant and Equipment [Member] | Accounting Standards Update 2016-02 [Member]
Property, Plant and Equipment [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	2
AOCI Attributable to Parent [Member]
Property, Plant and Equipment [Line Items]
Reclassification of stranded tax effects due to Tax Reform	$ 2

Revenue Recogniton Revenue Re_4

Revenue Recogniton Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Document Period End Date	Dec. 31, 2019
Regulated Operating Revenue, Electric, Non-Nuclear	$ 1,857	$ 1,823
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price	2	3	$ 0
Deferred Revenue, Revenue Recognized	(22)	(45)
Regulated Operating Revenue	1,881	1,781
Unregulated Operating Revenue	170	159
Regulated and Unregulated Operating Revenue	72	51
Total Revenues	2,123	1,991	$ 2,009
Gain on Derivative Instruments, Pretax	50	42
Residential [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	981	948
Commercial [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	636	647
Industrial [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	196	185
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	44	43
Revenue Subject to Refund [Member]
Disaggregation of Revenue [Line Items]
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount	$ 23	$ 45

Balance Sheet Components Allowa

Balance Sheet Components Allowance for Uncollectible accounts activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance as of beginning of year	$ 15	$ 6	$ 6
Increase in provision	2	14	6
Amounts written off, less recoveries	(12)	(5)	(6)
Balance as of end of year	$ 5	$ 15	$ 6

Balance Sheet Components Schedu

Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Other current assets:
Prepaid Expense, Current	$ 63	$ 54
Margin Deposit Assets	16	16
Assets from price risk management activities	25	20
Other Assets, Current	104	90
Accrued expenses and other current liabilities:
Regulatory Liability, Current	44	36
Accrued employee compensation and benefits	74	66
Accrued interest payable	25	27
Dividends payable	36	34
Taxes Payable, Current	33	34
Other	103	71
Other Liabilities, Current	$ 315	$ 268

Balance Sheet Components Balanc

Balance Sheet Components Balance Sheet Components Public Utility Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation or Processing	$ 4,749	$ 4,600
Public Utilities, Property, Plant and Equipment, Transmission	848	580
Public Utilities, Property, Plant and Equipment, Distribution	3,917	3,838
Public Utilities, Property, Plant and Equipment, General	656	611
Public Utilities, Property, Plant and Equipment, Intangible	758	715
Public Utilities, Property, Plant and Equipment, Plant in Service	10,928	10,344
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	4,095	3,803
Construction work-in-progress	328	346
Public Utilities, Property, Plant and Equipment, Net	6,833	6,541
Property, Plant and Equipment, Net	$ 7,161	$ 6,887

Balance Sheet Components (Detai

Balance Sheet Components (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Accounts Receivable, Allowance for Credit Loss, Current	$ 5	$ 15	$ 6	$ 6

Fair Value of FInancial Instr_4

Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2019	Jan. 31, 2019	Dec. 31, 2018
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	$ 26		$ 112
Domestic government, Debt securities	24		25
Corporate debt securities held in decommissioning trust assets	9		10
Money market funds	13		7
Fair Value - Money market funds	1		2
Domestic Equity Securities	7		6
Debt securities - domestic government	1		1
Electricity	16		12
Natural gas	22		8
Financial Instruments, Owned, at Fair Value	13		7
Assets, Fair Value Disclosure	119		183
Derivative Liability	0	$ 5	4
Liabilities from price risk management activities: [Abstract]
Electricity	119		94
Natural gas	12		58
Liabilities, Fair Value Disclosure	131		156
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	26		112
Domestic government, Debt securities	8		7
Corporate debt securities held in decommissioning trust assets	0		0
Fair Value - Money market funds	1		2
Domestic Equity Securities	7		6
Debt securities - domestic government	1		1
Electricity	0		0
Natural gas	0		0
Financial Instruments, Owned, at Fair Value	43		128
Liabilities from price risk management activities: [Abstract]
Electricity	0		0
Natural gas	0		0
Liabilities, Fair Value Disclosure	0		0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0		0
Domestic government, Debt securities	16		18
Corporate debt securities held in decommissioning trust assets	9		10
Fair Value - Money market funds	0		0
Domestic Equity Securities	0		0
Debt securities - domestic government	0		0
Electricity	9		9
Natural gas	21		8
Financial Instruments, Owned, at Fair Value	55		45
Derivative Liability			4
Liabilities from price risk management activities: [Abstract]
Electricity	14		10
Natural gas	12		51
Liabilities, Fair Value Disclosure	26		65
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0		0
Domestic government, Debt securities	0		0
Corporate debt securities held in decommissioning trust assets	0		0
Money market funds	0
Fair Value - Money market funds			0
Domestic Equity Securities	0		0
Debt securities - domestic government	0		0
Electricity	7		3
Natural gas	1		0
Financial Instruments, Owned, at Fair Value	8		3
Liabilities from price risk management activities: [Abstract]
Electricity	105		84
Natural gas	0		7
Liabilities, Fair Value Disclosure	105		91
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 29		$ 27

Fair Value of FInancial Instr_5

Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	$ 12.53	$ 14.60
Natural gas financial swaps	1.39	0.95
Fnancial swaps - electricity	10.57	20.75
Maximum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	59	69
Natural gas financial swaps	3.73	4.64
Fnancial swaps - electricity	66.32	35.46
Weighted Average [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	36.92	45
Natural gas financial swaps	1.90	1.82
Fnancial swaps - electricity	45.11	28.63
Assets [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	0	3,000,000
Natural gas financial swaps	1,000,000	0
Fnancial swaps - electricity	7,000,000	0
Total commodity contracts	8,000,000	3,000,000
Liabilities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	104,000,000	84,000,000
Natural gas financial swaps	0	7,000,000
Fnancial swaps - electricity	1,000,000	0
Total commodity contracts	$ 105,000,000	$ 91,000,000

Fair Value of FInancial Instr_6

Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net realized and unrealized losses	$ 10	$ (40)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Net transfers out of Level 3 to Level 2	(1)	(11)
Net liabilities from price risk management activities as of end of year	97	88	$ 139
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	16	(32)
Net realized losses	$ (6)	$ (8)

Fair Value of Financial Instr_7

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Net realized losses	$ (6)	$ (8)
Long-term Debt, Fair Value	3,039	2,760
Long-term Debt	2,608	2,488
Unamortized Debt Issuance Expense	11	10
Defined Benefit Plan, Transfers Between Measurement Levels	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Notes Payable to Banks [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 2,597	$ 2,478

Fair values of price risk manag

Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current Assets, Commodity Contracts:
Electricity	$ 9	$ 11
Natural Gas	16	7
Total current derivative assets	25	18
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	7	1
Commodity Contract Asset, Noncurrent, Natural Gas	6	1
Derivative Asset, Noncurrent	13	2
Total derivative assets	38	20
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	14	16
Natural Gas	9	35
Total current derivative liabilities	23	51
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	105	78
Natural Gas	3	23
Total noncurrent derivative liabilities	108	101
Total derivative liabilities	$ 131	$ 152

Net volumes related to price ri

Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2019CAD ($)MMBTUMWh	Dec. 31, 2018CAD ($)MMBTUMWh
Commodity contracts: [Abstract]
Electricity | MWh	6	5
Natural gas | MMBTU	145	123
Foreign currency exchange | $	$ 23	$ 18

Net realized and unrealized gai

Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Commodity contracts: [Abstract]
Electricity	$ 20	$ (34)	$ 41
Natural Gas	(32)	21	85
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency	$ (1)	$ 1	$ (1)

Future year net unrealized gain

Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) $ in Millions	Dec. 31, 2019USD ($)
Electricity [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	$ (5)
Other Commitment, Due in Second Year	(1)
Other Commitment, Due in Third Year	(7)
Other Commitment, Due in Fourth Year	7
Other Commitment, Due in Fifth Year	7
Other Commitment, Due after Fifth Year	76
Total	(103)
Natural Gas [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	(7)
Other Commitment, Due in Second Year	(2)
Other Commitment, Due in Third Year	(1)
Other Commitment, Due in Fourth Year	0
Other Commitment, Due in Fifth Year	0
Other Commitment, Due after Fifth Year	0
Total	(10)
Unrealized Gain Loss On Derivatives [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	(2)
Other Commitment, Due in Second Year	(1)
Other Commitment, Due in Third Year	(6)
Other Commitment, Due in Fourth Year	7
Other Commitment, Due in Fifth Year	7
Other Commitment, Due after Fifth Year	76
Total	$ (93)

Counterparties representing 10%

Counterparties representing 10% or more (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Liabilities from price risk management activities: [Abstract]
Concentration of Risk, Derivative Instruments, Assets	71.00%	77.00%
Counterparty A [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	35.00%	42.00%
Counterparty B [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	1.00%	15.00%
Counterparty C [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	13.00%	5.00%
Counterparty D [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	11.00%	6.00%
Counterparty E [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	11.00%	9.00%
Counterparty F [Member]
Liabilities from price risk management activities: [Abstract]
Concentration Risk, Percentage	79.00%	56.00%

Price Risk Management (Details)

Price Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 31, 2019
Derivative [Line Items]
Derivative Liability	$ 0	$ (4)		$ (5)
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		88
Derivative, Collateral, Right to Reclaim Cash		11
Net gain or loss recognized in the statement of income offset by regulatory accounting	2	18	$ 82
Derivative, Net Liability Position, Aggregate Fair Value	122
Collateral Already Posted, Aggregate Fair Value	15
Collateral Aggregate Fair Value	114
Margin Deposit Assets	$ 0
Electricity [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		84
Natural Gas [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ 4

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Regulatory Assets [Line Items]
Regulatory Assets	$ 500	$ 462
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	438
Regulatory Liabilities	1,421	1,391
Regulatory Assets Earning a Rate of Return at the Approved Rate	1,405
Removal Costs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	1,021	979
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	260	267
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	$ 54	53
Revenue Subject to Refund [Member]
Regulatory Assets [Line Items]
Regulatory Current Asset, End Date for Recovery	2020
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 0
Regulatory Liabilities	23	45
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	16
Regulatory Liabilities	63	47
Regulatory Assets Earning a Rate of Return at the Approved Rate	47
Other Regulatory Assets Earning a Return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	62
Earning a return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	$ 62
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets [Line Items]
Regulatory Current Asset, End Date for Recovery	2035
Regulatory Assets	$ 0	131
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	95
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	222
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 213
Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Current Asset, End Date for Recovery	2049
Regulatory Assets	$ 0	16
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 26
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Current Asset, End Date for Recovery	2059
Regulatory Assets	$ 0
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	94	26
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets	72	$ 67
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 10

Schedule of Asset Retirement Ob

Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 137	$ 68
Utility plant	126	112
Non-utility property	16	17
Asset Retirement Obligation	279	197	$ 167	$ 161
Asset Retirement Obligation, Current	16	0
Asset Retirement Obligations, Noncurrent	$ 263	$ 197

Schedule of Change in Asset Ret

Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation		$ 197	$ 167	$ 161
Asset Retirement Obligation, Liabilities Incurred		0	0	2
Asset Retirement Obligation, Liabilities Settled		(9)	(5)	(3)
Asset Retirement Obligation, Accretion Expense		9	8	7
Asset Retirement Obligation, Revision of Estimate	$ 69	82	27	0
Asset Retirement Obligation		$ 279	$ 197	$ 167

Asset Retirement Obligations (D

Asset Retirement Obligations (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Asset Retirement Obligation, Revision of Estimate	$ 69	$ 82	$ 27	$ 0
Asset Retirement Obligation, Accretion Expense		9	8	7
Asset Retirement Obligation, Liabilities Incurred		0	0	$ 2
Asset Retirement Obligation, Period Increase (Decrease)		$ 14
Document Period End Date		Dec. 31, 2019
Decommissioning Liability, Noncurrent		$ 4
Asset Retirement Obligation, Cash Paid to Settle		4
Recorded Third-Party Environmental Recoveries, Amount		4	$ 4
Non Utility [Member] [Member]
Asset Retirement Obligation, Revision of Estimate	$ 13
Utility Plant [Domain]
Asset Retirement Obligation, Accretion Expense		4
Asset Retirement Obligation, Liabilities Incurred		3
Colstrip [Member]
Asset Retirement Obligation, Period Increase (Decrease)		$ 11

Credit Facilities Schedule of S

Credit Facilities Schedule of Short term debt (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Short-term Debt [Line Items]
Average daily amount of short-term debt outstanding	$ 7
Weighted daily average interest rate	2.60%
Maximum amount outstanding during the year	$ 46

Credit Facilities (Details)

Credit Facilities (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Line of Credit Facility [Abstract]
Line of Credit Facility, Maximum Borrowing Capacity	$ 500
Line of Credit Facitlity, Covenant Terms, One Month Term	1 year
Line of Credit Facitlity, Covenant Terms, Two Month Term	2 years
Line of Credit Facitlity, Covenant Terms, Three Month Term	3 years
Line of Credit Facitlity, Covenant Terms, Six Month Term	6 months
Debt Instrument, Covenant Description	65.00%
Ratio of Indebtedness to Net Capital	0.519
Commercial Paper, Maximum Term	270 days
Commercial Paper	$ 0
FERC Authorized Short-term Debt, effective through February 6, 2014	900
Line of Credit Facility, Amount Outstanding	0
Line of Credit Facility, Remaining Borrowing Capacity	500
letter of credit facility	220
Letters of Credit Outstanding, Amount	$ 55

Long-term Debt Schedule of Long

Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Sep. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
First mortgage Bonds - minimum rate	2.51%
First Mortgage Bonds, rates range from 2.51% to 9.31%, with a weighted average rate of 4.63% in 2019 and 5.01% in 2018, due at various dates through 2050	$ 2,510		$ 2,390
Pollution Control Revenue Bonds, 5% rate, due 2033	119		119
Pollution Control Revenue Bonds owned by PGE	(21)		(21)
Total long-term debt	2,608		2,488
Debt Instrument, Unamortized Discount	(11)		(10)
Less: current portion of long-term debt	0	$ (50)	(300)
Long-term debt, net of current portion	$ 2,597		$ 2,178
First Mortgage Bonds - maximum rate	9.31%
Debt, Weighted Average Interest Rate	4.63%

Long-term Debt Schedule of Matu

Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Long-term Debt, Unclassified [Abstract]
2020	$ 0
2021	160
2022	0
2023	0
2024	80
Thereafter	2,368
Total long-term debt	$ 2,608	$ 2,488

Long term debt (Details)

Long term debt (Details) - USD ($) $ in Millions	Nov. 15, 2019	Oct. 25, 2019	Apr. 12, 2019	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Sep. 30, 2019
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt	$ 160	$ 110	$ 200	$ 470	$ 75	$ 225
Long-term Pollution Control Bond				21
Line of Credit Facility, Interest Rate During Period					1.37%
Pollution Control Revenue Bonds owned by PGE				21	$ 21
Long-term Debt, Current Maturities				$ 0	$ 300		$ 50
Proceeds from Issuance of Debt		$ 270

Employee Benefits Assets and Li

Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Document Period End Date	Dec. 31, 2019
Non-qualified benefit plan trust	$ 38	$ 36
Non-qualified benefit plan liabilities	103	103
Other Postretirement Benefit Plans [Domain]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	0	0
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	21	20
Non-qualified benefit plan liabilities	79	81
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	17	16
Non-qualified benefit plan liabilities	$ 24	$ 22

Employee Benefits Schedule of A

Employee Benefits Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Dec. 31, 2019
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Defined Benefit Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	65.00%	67.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	64.00%	65.00%
Defined Benefit Pension Plan [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	35.00%	33.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	36.00%	35.00%
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Other Postretirement Benefit Plans [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	59.00%	59.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	61.00%	58.00%
Other Postretirement Benefit Plans [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	41.00%	41.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	39.00%	42.00%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Non Qualified Benefit Plans [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	12.00%	13.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	17.00%	16.00%
Non Qualified Benefit Plans [Member] | Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	12.00%	13.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	7.00%	10.00%
Non Qualified Benefit Plans [Member] | Other Contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	76.00%	74.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	76.00%	74.00%

Employee Benefits Schedule of F

Employee Benefits Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	$ 13	$ 7
Equity securities:
Domestic	49	67
Defined Benefit Plan, Plan Assets, Amount		546
Financial Instruments, Owned, at Fair Value	13	7
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds		3
Domestic equity securities - Other postretirement benefit plan assets at fair value		3
International equity securities - other post retirement assets at fair value		8
Private Equity Funds, US [Member]
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	5	5
Investments, Fair Value Disclosure	9	11
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure	632	463
Fair Value, Inputs, Level 1 [Member]
Equity securities:
Domestic	49	67
Private equity funds	0	0
Defined Benefit Plan, Plan Assets, Amount	49	67
Financial Instruments, Owned, at Fair Value	43	128
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	4	3
Domestic equity securities - Other postretirement benefit plan assets at fair value	0	0
International equity securities - other post retirement assets at fair value	9	8
Other post retirement benefit plan assets total	13	11
Fair Value, Inputs, Level 2 [Member]
Equity securities:
Domestic	0	0
Private equity funds	0	0
Defined Benefit Plan, Plan Assets, Amount	0	0
Financial Instruments, Owned, at Fair Value	55	45
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	0	0
Domestic equity securities - Other postretirement benefit plan assets at fair value	3	3
International equity securities - other post retirement assets at fair value	0	0
Other post retirement benefit plan assets total	8	8
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	0
Equity securities:
Domestic	0	0
Private equity funds	0	0
Defined Benefit Plan, Plan Assets, Amount	0	0
Financial Instruments, Owned, at Fair Value	8	3
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	0	0
Domestic equity securities - Other postretirement benefit plan assets at fair value	0	0
International equity securities - other post retirement assets at fair value	0	0
Other post retirement benefit plan assets total	0	0
Pension Plan [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	695	546	$ 629
Financial Instruments, Owned, at Fair Value	646	479
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Money Market Funds, at Carrying Value	5	4
Investments, Fair Value Disclosure	8	7
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	34	30	$ 33
Financial Instruments, Owned, at Fair Value	13	$ 11
Other Postretirement Benefit Plans assets: [Abstract]
Money market funds	4
Domestic equity securities - Other postretirement benefit plan assets at fair value	3
International equity securities - other post retirement assets at fair value	$ 9

Employee Benefits Schedule of C

Employee Benefits Schedule of Changes in Fair Value of Plan Assets (Details) $ in Millions	Dec. 31, 2018USD ($)
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Defined Benefit Plan, Plan Assets, Amount	$ 546

Employee Benefits Schedule of D

Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets	$ 5	$ 5
Fair value of plan assets:
As of January 1		546
Classification in consolidated balance sheet:
Noncurrent asset	(38)	(36)
Noncurrent liability	(247)	(307)
Fair Value, Inputs, Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets	0	0
Fair value of plan assets:
As of January 1	0	0
Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets	0	0
Fair value of plan assets:
As of January 1	49	67
Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Debt Securities— Domestic Government Other Postretirement Benefit Plan Assets	5	5
Fair value of plan assets:
As of January 1	0	0
Pension Plans, Defined Benefit [Member]
Benefit obligation:
As of January 1	905	811	$ 869
Fair value of plan assets:
Service cost	16	19	17
Interest cost on benefit obligation	34	32	33
Participants’ contributions	0	0
Actuarial loss (gain)	88	(67)
Benefit payments	(42)	(39)
Defined Benefit Plan, Plan Assets, Administration Expense	(2)	(3)
As of January 1	695	546	629
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(210)	(265)
Net actuarial loss (gain) included in comprehensive income	(3)	25
Defined Benefit Plan, Amortization of Gain (Loss)	(10)	(17)	(13)
Total Amounts included in comprehensive income	(13)	8
Defined Benefit Plan, Accumulated Benefit Obligation	813	734
Actual return on plan assets	131	(50)
Company contributions	62	9
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(210)	(265)
Amounts included in AOCL:
Net actuarial loss	213	226
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 213	$ 226
Assumptions used:
Discount rate used to calculate benefit obligation	4.25%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.65%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	7.00%	7.00%
Other Postretirement Benefit Plans [Member]
Benefit obligation:
As of January 1	$ 71	$ 72	78
Fair value of plan assets:
Service cost	2	2	2
Interest cost on benefit obligation	3	3	3
Participants’ contributions	2	2
Actuarial loss (gain)	8	(7)
Benefit payments	(6)	(6)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	9
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment	1
As of January 1	34	30	33
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(37)	(42)
Net actuarial loss (gain) included in comprehensive income	5	(4)
Other Postretirement Benefits Cost (Reversal of Cost)	9
Defined Benefit Plan, Amortization of Gain (Loss)	0	0	0
Total Amounts included in comprehensive income	(4)	(4)
Actual return on plan assets	5	(2)
Company contributions	3	3
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(37)	(42)
Amounts included in AOCL:
Net actuarial loss	1	(4)
Prior service cost	(9)	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ (8)	$ (4)
Assumptions used:
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.58%	4.58%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	5.88%	6.20%
Non Qualified Benefit Plans [Member]
Benefit obligation:
As of January 1	$ 26	$ 24	27
Fair value of plan assets:
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Participants’ contributions	0	0
Actuarial loss (gain)	3	(1)
Benefit payments	(2)	(3)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
As of January 1	17	16	17
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(9)	(8)
Net actuarial loss (gain) included in comprehensive income	3	(1)
Defined Benefit Plan, Amortization of Gain (Loss)	(1)	(1)	$ (1)
Total Amounts included in comprehensive income	2	(2)
Defined Benefit Plan, Accumulated Benefit Obligation	26	24
Actual return on plan assets	1	(1)
Company contributions	2	3
Classification in consolidated balance sheet:
Noncurrent asset	(17)	(16)
Current liability	(2)	(2)
Noncurrent liability	(24)	(22)
Amounts included in AOCL:
Net actuarial loss	13	11
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 13	$ 11
Assumptions used:
Discount rate used to calculate benefit obligation	3.43%	3.65%

Employee Benefits Schedule of N

Employee Benefits Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 2	$ 2
Interest cost on benefit obligation	3	3	3
Expected return on plan assets	(2)	(1)	(2)
Amortization of net actuarial loss	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(2)	0
Net periodic benefit cost	1	4	3
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	16	19	17
Interest cost on benefit obligation	34	32	33
Expected return on plan assets	(40)	(42)	(42)
Amortization of net actuarial loss	10	17	13
Net periodic benefit cost	20	26	21
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Expected return on plan assets	0	0	0
Amortization of net actuarial loss	1	1	1
Net periodic benefit cost	$ 2	$ 2	$ 2

Employee Benefits Assumptions (

Employee Benefits Assumptions (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.58%	4.58%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	5.88%	6.20%
Pension Plan [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.43%	4.25%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.65%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.25%	3.65%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	7.00%	7.00%
Other Pension, Postretirement and Supplemental Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.43%	4.25%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.43%	3.65%
Maximum [Member] | Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.47%	4.26%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.26%	3.70%
Minimum [Member] | Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	3.19%	4.10%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.11%	3.42%

Employee Benefits Schedule of E

Employee Benefits Schedule of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2019USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 51
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	51
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	52
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	53
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	54
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	270
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	45
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	46
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	46
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	239
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	6
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	20
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	2
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 11

Employee Benefits (Details)

Employee Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Dec. 31, 2019
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 21	$ 30	$ 24
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	17
Payment for Pension Benefits	62	9
OtherPostretirementDefinedBenefitPlanLiabilityCurrent	2	2
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	17
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 2
Company match pre 2009 hire	6.00%
Company match post 2008 hire	5.00%
Company contribution percentage to 401k for post 2008 hires	5.00%
Company contribution percent to 401k for bargaining employees	1.00%
401k Plan Company contributions	$ 25	23	$ 21
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	2	0
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(1)
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	6	6
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	(1)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	17
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	42	39
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	17
Other Pension, Postretirement and Supplemental Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	1
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	2	$ 3
Pension and Other Postretirement Benefit Plans, Amounts that Will be Amortized from Accumulated Other Comprehensive Income (Loss) in Next Fiscal Year	$ 1

Income Taxes Schedule of Compon

Income Taxes Schedule of Components of Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current:
Federal	$ 9	$ 12	$ 4
State and local	12	22	12
Current Income Tax Expense (Benefit)	21	34	16
Deferred:
Federal	(2)	(15)	61
State and local	8	(2)	9
deferred income tax expense	6	(17)	70
Income tax expense	$ 27	$ 17	$ 86

Income Taxes Schedule of Effect

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Federal statutory tax rate	21.00%	21.00%	35.00%
Federal tax credits	(13.40%)	(16.70%)	(14.00%)
Effective Income Tax Rate Reconciliation, Change in Deferred Tax Assets Valuation Allowance, Percent	0.00%	0.00%	6.10%
State and local taxes, net of federal tax benefit	6.50%	6.50%	5.00%
Flow through depreciation and cost basis differences	1.50%	1.50%	1.50%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Amortization, Percent	(3.70%)	(4.10%)	0.00%
Other	(0.70%)	(0.80%)	(2.10%)
Effective tax rate	11.20%	7.40%	31.50%

Income Taxes Schedule of Deferr

Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Deferred income tax assets:
Employee benefits	$ 119	$ 134
Price risk management	26	36
Deferred income taxes	22	26
Deferred Tax Assets, tax credits, net of valuation allowance	64	52
Deferred Tax Assets, Tax Deferred Expense, Other	0	9
Total deferred income tax assets	231	257
Deferred income tax liabilities:
Depreciation and amortization	496	511
Regulatory assets	103	115
Deferred Tax Liabilities, Other	10	0
Deferred Tax Liabilities, Gross, Noncurrent	609	626
Total deferred income tax liabilities	$ 378	$ 369

Income Taxes Income taxes (Deta

Income Taxes Income taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Taxes [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	35.00%
Income Tax Expense (Benefit), Continuing Operations, Adjustment of Deferred Tax (Asset) Liability			$ 17
Tax Credit Carryforward, Federal	$ 64
Deferred Tax Assets, Valuation Allowance	0	$ 0
Unrecognized Tax Benefits	$ 0	$ 0

Equity-Based Plans (Details)

Equity-Based Plans (Details)	12 Months Ended
	Dec. 31, 2019USD ($)shares
employee stock purchase plan shares authorized	625,000
Employee Stock Purchase Plan, Base Pay Threshold	10.00%
Employee Stock Purchase Plan, Purchased Stock Value Limitation | $	$ 25,000
Employee Stock Purchase Plan, Share Purchase Limitation	1,500
Employee Stock Purchase Plan, Purchase Price	95.00%
Employee Stock Purchase Plan, Number of Available Shares	278,098
Dividend Reinvestment and Direct Stock Purchase Plan Shares	2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares	2,466,470

Stock-based Compensation Expe_3

Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Outstanding, Units	428,913	399,376	458,792
Outstanding, Weighted Average Grant Date Fair Value	$ 38.43	$ 37.98	$ 34.68
Granted, Units	210,555	198,864	202,145
Granted, Weighted Average Grant Date Fair Value	$ 49.06	$ 37.99	$ 41.96
Forfeited, Units	(9,041)	(8,556)	(64,840)
Forfeited, Weighted Average Grant Date Fair Value	$ 41.68	$ 39.73	$ 39.57
Vested, Units	(167,037)	(160,771)	(196,721)
Vested, Weighted Average Grant Date Fair Value	$ 37.52	$ 36.77	$ 31.78
Outstanding, Units	463,390	428,913	399,376
Outstanding, Weighted Average Grant Date Fair Value	$ 43.52	$ 38.43	$ 37.98

Stock-based Compensation Expe_4

Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	2.50%	2.40%	1.50%
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized, Period for Recognition	3 years	3 years	3 years
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	14.80%	14.70%	15.60%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	74.50%	21.80%	22.90%

Stock-based Compensation Expe_5

Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Noncash Expense	$ 9	$ 5	$ 7
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	4,687,500
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,902,576
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 1	0	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	7	4	6
Share-based Payment Arrangement, Decrease for Tax Withholding Obligation	2	$ 2	$ 3
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 10
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting	123.00%	86.60%	89.10%
Stock-based Compensation, Forfeiture Rate	5.00%
Share-based Payment Arrangement, Amount Capitalized	$ 0	$ 0	$ 0
Performance based stock award percentage - minimum	0.00%
Performance based stock award percentage - maximum	200.00%

Earnings Per Share Schedule of

Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Shares Outstanding, Basic	89,353	89,215	89,056
Weighted Average Number Diluted Shares Outstanding Adjustment	206	132	120
Weighted Average Number of Shares Outstanding, Diluted	89,559	89,347	89,176

Commitments and Guarantees Unre

Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2019USD ($)
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 598
Unrecorded Unconditional Purchase Obligation, Due within One Year	393
Unrecorded Unconditional Purchase Obligation, Due within Two Years	130
Unrecorded Unconditional Purchase Obligation, Due within Three Years	14
Unrecorded Unconditional Purchase Obligation, Due within Four Years	4
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	56
Long-term Contract for Purchase of Electric Power [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	3,363
Unrecorded Unconditional Purchase Obligation, Due within One Year	193
Unrecorded Unconditional Purchase Obligation, Due within Two Years	189
Unrecorded Unconditional Purchase Obligation, Due within Three Years	220
Unrecorded Unconditional Purchase Obligation, Due within Four Years	219
Unrecorded Unconditional Purchase Obligation, Due within Five Years	215
Unrecorded Unconditional Purchase Obligation, Due after Five Years	2,327
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	45
Unrecorded Unconditional Purchase Obligation, Due within One Year	0
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	9
Unrecorded Unconditional Purchase Obligation, Due within Four Years	9
Unrecorded Unconditional Purchase Obligation, Due within Five Years	9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	9
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	119
Unrecorded Unconditional Purchase Obligation, Due within One Year	16
Unrecorded Unconditional Purchase Obligation, Due within Two Years	15
Unrecorded Unconditional Purchase Obligation, Due within Three Years	13
Unrecorded Unconditional Purchase Obligation, Due within Four Years	13
Unrecorded Unconditional Purchase Obligation, Due within Five Years	12
Unrecorded Unconditional Purchase Obligation, Due after Five Years	50
Natural gas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	827
Unrecorded Unconditional Purchase Obligation, Due within One Year	59
Unrecorded Unconditional Purchase Obligation, Due within Two Years	45
Unrecorded Unconditional Purchase Obligation, Due within Three Years	40
Unrecorded Unconditional Purchase Obligation, Due within Four Years	38
Unrecorded Unconditional Purchase Obligation, Due within Five Years	42
Unrecorded Unconditional Purchase Obligation, Due after Five Years	603
Coal and transportationSupply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	162
Unrecorded Unconditional Purchase Obligation, Due within One Year	27
Unrecorded Unconditional Purchase Obligation, Due within Two Years	27
Unrecorded Unconditional Purchase Obligation, Due within Three Years	27
Unrecorded Unconditional Purchase Obligation, Due within Four Years	27
Unrecorded Unconditional Purchase Obligation, Due within Five Years	27
Unrecorded Unconditional Purchase Obligation, Due after Five Years	27
Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	5,114
Unrecorded Unconditional Purchase Obligation, Due within One Year	688
Unrecorded Unconditional Purchase Obligation, Due within Two Years	415
Unrecorded Unconditional Purchase Obligation, Due within Three Years	323
Unrecorded Unconditional Purchase Obligation, Due within Four Years	310
Unrecorded Unconditional Purchase Obligation, Due within Five Years	306
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 3,072

Commitments and Guarantees Schd

Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)MW	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 1,302
PGE Share of Output	8.60%
PGE Share of Capacity | MW	163
commitment costs	$ 21	$ 17	$ 16
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 651
PGE Share of Output	13.60%
PGE Share of Capacity | MW	98
commitment costs	$ 16	$ 11	$ 11

Commitments and Guarantees (Det

Commitments and Guarantees (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Unrecorded Unconditional Purchase Obligation [Line Items]
Capital Leased Assets, Gross	$ 57
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	8
Capital Lease Obligations, Current	2	$ 2
Purchase Commitment, Remaining Minimum Amount Committed	47	47
Deferred Costs, Leasing, Accumulated Amortization		3
Interest Expense, Lessee, Assets under Capital Lease		4
Long-term Purchase Commitment, Amount	149
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	20
Operating Leases, Rent Expense		7
Operating Leases, Rent Expense, Contingent Rentals		14
Contractual Obligation		289
Operating Leases, Rent Expense, Sublease Rentals		$ 4
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 131

Leases Lease Cost (Details)

Leases Lease Cost (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Lease, Cost	$ 7
Finance Lease, Right-of-Use Asset, Amortization	3
Finance Lease, Interest Expense	6
FinanceLeaseCost	9
Variable Lease, Cost	$ 19

Leases Supplemental Information

Leases Supplemental Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Document Period End Date	Dec. 31, 2019
Operating Lease, Right-of-Use Asset	$ 51
Operating Lease, Liability, Current	8
Operating Lease, Liability, Noncurrent	43
Operating Lease, Liability	51
Finance Lease, Right-of-Use Asset	150
Finance Lease, Liability, Current	16	$ 0
Finance Lease, Liability, Noncurrent	135	$ 0
Finance Lease, Liability	$ 151

Leases Lease Term and Discount

Leases Lease Term and Discount Rate (Details)	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	24 years
Finance Lease, Weighted Average Remaining Lease Term	29 years
Operating Lease, Weighted Average Discount Rate, Percent	3.50%
Finance Lease, Weighted Average Discount Rate, Percent	7.30%

Leases Maturities of Lease Liab

Leases Maturities of Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 8	$ 4
Lessee, Operating Lease, Liability, Payments, Due Year Two	8
Finance Lease, Liability, Payments, Due Year Two	16
Finance Lease, Liability, Payments, Due Year Two	16
Lessee, Operating Lease, Liability, Payments, Due Year Three	8
Finance Lease, Liability, Payments, Due Year Three	16
Lessee, Operating Lease, Liability, Payments, Due Year Four	8
Finance Lease, Liability, Payments, Due Year Four	14
Lessee, Operating Lease, Liability, Payments, Due Year Five	7
Finance Lease, Liability, Payments, Due Year Five	14
Lessee, Operating Lease, Liability, Payments, Due after Year Five	46
Finance Lease, Liability, Payments, Due after Year Five	235
Lessee, Operating Lease, Liability, Payments, Due	85
Finance Lease, Liability, Payment, Due	311
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(34)
Finance Lease, Liability, Undiscounted Excess Amount	(160)
Operating Lease, Liability	51
Finance Lease, Liability	$ 151

Leases Supplemental Cash Flow I

Leases Supplemental Cash Flow Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Leases [Abstract]
Operating Lease, Payments	$ 7
Finance Lease, Interest Payment on Liability	5
Finance Lease, Principal Payments	4
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	56
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 154

Leases Future Minimum Lease Pay

Leases Future Minimum Lease Payments (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Capital Leases, Future Minimum Payments Due, Next Twelve Months		$ 6
Contractual Obligation, Due in Next Fiscal Year		11
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 8	4
Capital Leases, Future Minimum Payments Due in Two Years		6
Contractual Obligation, Due in Second Year		14
Operating Leases, Future Minimum Payments, Due in Two Years		5
Capital Leases, Future Minimum Payments Due in Three Years		6
Contractual Obligation, Due in Third Year		13
Operating Leases, Future Minimum Payments, Due in Three Years		5
Capital Leases, Future Minimum Payments Due in Four Years		6
Contractual Obligation, Due in Fourth Year		13
Operating Leases, Future Minimum Payments, Due in Four Years		6
Capital Leases, Future Minimum Payments Due in Five Years		5
Contractual Obligation, Due in Fifth Year		13
Operating Leases, Future Minimum Payments, Due in Five Years		7
Capital Leases, Future Minimum Payments Due Thereafter		67
Contractual Obligation, Due after Fifth Year		225
Operating Leases, Future Minimum Payments, Due Thereafter		97
Capital Leases, Future Minimum Payments Due		96
Contractual Obligation		289
Operating Leases, Future Minimum Payments Due		124
Capital Leases, Future Minimum Payments, Interest Included in Payments		(47)
Capital Leases, Future Minimum Payments, Present Value of Net Minimum Payments		49
Capital Lease Obligations, Current	(2)	(2)
Purchase Commitment, Remaining Minimum Amount Committed	$ 47	$ 47

Leases Leases (Details)

Leases Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment [Line Items]
Capital Leased Assets, Gross	$ 57
Capital Leases, Lessee Balance Sheet, Assets by Major Class, Accumulated Depreciation	8
Capital Lease Obligations, Current	2	$ 2
Purchase Commitment, Remaining Minimum Amount Committed	47	47
Deferred Costs, Leasing, Accumulated Amortization		3
Interest Expense, Lessee, Assets under Capital Lease		4
Long-term Purchase Commitment, Amount	149
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	20
Operating Leases, Rent Expense		7
Operating Leases, Rent Expense, Contingent Rentals		14
Operating Leases, Rent Expense, Sublease Rentals		$ 4
Capital Addition Purchase Commitments [Member]
Property, Plant and Equipment [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 131

Jointly-owned Plant Schedule of

Jointly-owned Plant Schedule of Jointly-owned plant (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Proportionate Ownership Share of Boardman	90.00%
Jointly Owned Plant, Boardman Plant In Service Year	1980
Jointly Owned Utility Plant, Gross Ownership Amount of Boardman Plant In Service	$ 517
Jointly Owned Utility Plant, Ownership Amount of Boardman Plant Accumulated Depreciation	478
Jointly Owned Utility Plant Ownership Amount of Construction Work In Progress Boardman	$ 0
Jointly Owned Utility Plant, Proportionate Ownership Share of Colstrip	20.00%
Jointly Owned Plant, Colstrip Plant In Service Year	1986
Jointly Owned Utility Plant, Gross Ownership Amount of Colstrip Plant In Service	$ 550
Jointly Owned Utility Plant, Ownership Amount of Colstrip Plant Accumulated Depreciation	375
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Colstrip	$ 14
Jointly Owned Utility Plant, Proportionate Ownership Share of Pelton/Round Butte	66.67%
Jointly Owned Plant, Pelton Plant in Service Year	1958
Jointly Owned Plant, Round Butte in Service Year	1964
Jointly Owned Utility Plant, Gross Ownership Amount of Pelton/Round Butte Plant In Service	$ 265
Jointly Owned Utility Plant, Ownership Amount of Pelton/Round Butte Plant Accumulated Depreciation	78
Jointly Owned Utility Plant Ownership Amount Of Construction Work In Progress Pelton/Round Butte	6
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	1,332
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	931
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 20

Contingencies (Details)

Contingencies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019USD ($)name	Dec. 31, 2018USD ($)	Dec. 31, 2017USD ($)	Dec. 31, 1993
Loss Contingencies [Line Items]
Proceeds from Insurance Settlement, Investing Activities	$ 0	$ 120	$ 0
Loss Contingency, Damages Sought, Value	$ 1,200
Site Contingency, Names of Other Potentially Responsible Parties | name	100
Litigation Settlement, Expense	$ 115
Loss Contingency, Range of Possible Loss, Maximum	1,700
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
Payments for Environmental Liabilities	6
investment in Trojan				87.00%
Class action damages sought	$ 260