Portland General Electric (POR) 10-Q 27 Jul 22 2022 Q2 Quarterly report Financial data

Cover Page

Cover Page - shares	6 Months Ended
	Jun. 30, 2022	Jul. 21, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2022
Document Transition Report	false
Entity File Number	001-5532-99
Entity Registrant Name	PORTLAND GENERAL ELECTRIC COMPANY
Entity Incorporation, State or Country Code	OR
Entity Tax Identification Number	93-0256820
Entity Address, Address Line One	121 SW 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
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		89,242,847
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q2
Current Fiscal Year End Date	--12-31

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income and Comprehensive Income (Unaudited) - USD ($) shares in Thousands, $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Revenue, net	$ 588	$ 545	$ 1,213	$ 1,157
Alternative revenue programs, net of amortization	3	(8)	4	(11)
Total revenues	591	537	1,217	1,146
Operating expenses:
Purchased power and fuel	168	185	370	354
Generation, transmission and distribution	85	76	175	156
Administrative and other	84	79	173	165
Depreciation and amortization	103	101	202	204
Taxes other than income taxes	39	35	79	73
Total operating expenses	479	476	999	952
Income from operations	112	61	218	194
Interest expense, net	38	33	76	67
Other income:
Allowance for equity funds used during construction	3	5	6	9
Miscellaneous income (loss), net	0	3	0	5
Other income, net	3	8	6	14
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	77	36	148	141
Income tax expense	13	4	24	13
Net income	64	32	124	128
Other comprehensive Income	1	0	1	0
Comprehensive Income	$ 65	$ 32	$ 125	$ 128
Weighted-average common shares outstanding (in thousands):
Basic	89,225	89,554	89,310	89,555
Diluted	89,371	89,672	89,449	89,687
Earnings Per Share, Basic and Diluted	$ 0.72	$ 0.36	$ 1.39	$ 1.43

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current assets:
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 91	$ 52
Accounts receivable, net	289	329
Inventories	96	78
Regulatory assets - current	16	24
Other current assets	310	205
Total current assets	802	688
Electric utility plant, net	8,164	8,005
Regulatory assets - noncurrent	498	533
Nuclear decommissioning trust	43	47
Non-qualified benefit plan trust	38	45
Other noncurrent assets	238	176
Total assets	9,783	9,494
Current liabilities
Accounts payable	191	244
Liabilities from price risk mangement activities - current	55	47
Current portion of finance lease obligation	21	20
Accrued expenses and other current liabilities	653	457
Total current liabilities	920	768
Long-term debt, net of current portion	3,286	3,285
Regulatory liabilities-noncurrent	1,418	1,360
Deferred income taxes	432	413
Unfunded status of pension and psotretirement plans	205	206
Liabilities from price risk management activities-noncurrent	67	90
Asset retirement obligations	244	238
Non-qualified benefit plan liabilities	92	95
Finance lease obligations, net of current portion	297	273
Other noncurrent liabilities	84	59
Total liabilities	7,045	6,787
Commitments and contingencies (see notes)
Shareholders' Equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding as of June 30, 2022 and December 31, 2021	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,242,672 and 89,410,612 shares issued and outstanding as of June 30, 2022 and December 31, 2021, respectively	1,241	1,241
Accumulated other comprehensive loss	(9)	(10)
Retained earnings	1,506	1,476
Total shareholders' equity	2,738	2,707
Total liabilities and shareholders' equity	$ 9,783	$ 9,494

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2022	Dec. 31, 2021
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, issued	0	0
Preferred stock, outstanding	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares issued	89,242,672	89,410,612
Common stock, shares outstanding	89,242,672	89,410,612

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021
Cash flows from operating activities:
Net income	$ 124	$ 128
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	202	204
Deferred income taxes	9	6
Pension and other postretirement benefits	7	12
Allowance for equity funds used during construction	(6)	(9)
Decoupling mechanism deferrals, net of amortization	(4)	11
Deferral of incremental storm costs	(3)	(52)
2020 Labor Day wildfire earnings test reserve	15	0
Other non-cash income and expenses, net	38	19
Changes in working capital:
Decrease in accounts receivable, net	37	(9)
(Increase) in inventories	(19)	(3)
(Increase)/decrease in margin deposits	3	(35)
(Decrease) in accounts payable and accrued liabilities	(55)	13
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities	149	17
Other working capital items, net	6	15
Other, net	(52)	(41)
Net cash provided by operating activities	451	276
Cash flows from investing activities:
Capital expenditures	(345)	(326)
Sales of Nuclear decommissioning trust securities	3	7
Purchases of Nuclear decommissioning trust securities	(3)	(5)
Proceeds from Sale of Property, Plant, and Equipment	12	0
Other, net	(1)	(13)
Net cash used in investing activities	(334)	(337)
Cash flows from financing activities:
Payments on long-term debt	0	(140)
Borrowings on short-term debt	0	200
Repayments of Short-term Debt	0	(150)
Proceeds from failed sale-leaseback transactions	25	0
Dividends paid	(77)	(73)
Repurchase of common stock	(18)	(12)
Other	(8)	(4)
Net cash provided by (used in) financing activities	(78)	(179)
Increase (Decrease) in cash and cash equivalents	39	(240)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	91	17
Supplemental cash flow information is as follows:
Cash paid for interest, net of amounts capitalized	63	61
Cash paid for income taxes, net	16	11
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	$ 29	$ 0

Basis of Presentation (Notes)

Basis of Presentation (Notes)	6 Months Ended
	Jun. 30, 2022
Basis of Presentation [Abstract]
BASIS OF PRESENTATION	BASIS OF PRESENTATION Nature of Business Portland General Electric Company (PGE or the Company) is a vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the State of Oregon. The Company participates in the wholesale market by purchasing and selling electricity and natural gas, as well as buying and selling transmission products and services, in an effort to provide reasonably-priced power for its retail customers. In addition, PGE offers wholesale electricity transmission service pursuant to its Open Access Transmission Tariff (OATT), which contains rates, terms, and conditions of service, as filed with, and approved by, the Federal Energy Regulatory Commission (FERC). PGE operates as a single segment, with revenues and costs related to its business activities recorded and analyzed on a total electric operations basis. The Company’s corporate headquarters is located in Portland, Oregon and its 4,000 square mile, state-approved service area, entirely within the State of Oregon, encompasses 51 incorporated cities. As of June 30, 2022, PGE served 922,000 retail customers within a service area of 1.9 million residents. Condensed Consolidated Financial Statements These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations, although PGE believes that the disclosures provided are adequate to make the interim information presented not misleading. The financial information included herein as of and for the three and six months ended June 30, 2022 and 2021 is unaudited; however, in the opinion of management, such information reflects all adjustments necessary to fairly present the condensed consolidated financial position, condensed consolidated income and comprehensive income, and condensed consolidated cash flows of the Company for these interim periods. All such adjustments are of a normal recurring nature, unless otherwise noted. The financial information as of December 31, 2021 is derived from the Company’s audited consolidated financial statements and notes thereto for the year ended December 31, 2021, included in Item 8 of PGE’s Annual Report on Form 10-K, filed with the SEC on February 17, 2022, which should be read in conjunction with the interim unaudited Financial Statements. Comprehensive Income No material change occurred in Other comprehensive income in the three and six months ended June 30, 2022 and 2021. Use of Estimates The preparation of condensed consolidated financial statements in accordance with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results experienced by the Company could differ materially from those estimates. Certain costs are estimated for the full year and allocated to interim periods based on estimates of operating time expired, benefit received, or activity associated with the interim period; accordingly, such costs may not be reflective of amounts to be recognized for a full year. Due to seasonal fluctuations in electricity sales, as well as the price of wholesale electricity and natural gas, interim financial results do not necessarily represent those to be expected for the year. Reclassifications

Revenue Recognition (Notes)

Revenue Recognition (Notes)	6 Months Ended
	Jun. 30, 2022
Revenue Recognition and Deferred Revenue [Abstract]
Revenue Recognition, Multiple-deliverable Arrangements [Table Text Block]	REVENUE RECOGNITION Disaggregated Revenue The following table presents PGE’s revenue, disaggregated by customer type (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Retail: Residential $ 250 $ 249 $ 558 $ 559 Commercial 168 170 346 332 Industrial 73 62 142 122 Direct access customers 9 13 17 24 Subtotal 500 494 1,063 1,037 Alternative revenue programs, net of amortization 3 (8) 4 (11) Other accrued revenues, net — (2) — 11 Total retail revenues 503 484 1,067 1,037 Wholesale revenues * 65 41 121 74 Other operating revenues 23 12 29 35 Total revenues $ 591 $ 537 $ 1,217 $ 1,146 * Wholesale revenues include $14 million and $4 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2022 and 2021, respectively, and $33 million and $9 million for the six months ended June 30, 2022 and 2021, respectively. Price risk management derivative activities are included within total revenues but do not represent revenues from contracts with customers as defined by GAAP. For further information, see Note 5, 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 accept energy deliveries at voltages equivalent to those delivered to residential customers and are also sensitive to the effects of weather, although to a lesser extent than 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 determined through general rate case (GRC) proceedings and various tariff filings with the Public Utility Commission of Oregon (OPUC). Additionally, the Company offers pricing options that include a daily market price option, various time-of-use options, and several renewable energy options. 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 have not yet been billed to customers. This amount, classified as unbilled revenues, which is included in Accounts receivable, net in the Company’s condensed 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. 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. The Company 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 for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, the Company 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 the Company’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 within the condensed consolidated statements of income and comprehensive income and are not reflected in the line item Revenues, net. 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 Other operating revenues consist primarily of gains and losses on the sale of natural gas volumes purchased that exceeded what was needed to fuel the Company’s generating facilities, as well as revenues from transmission services, excess transmission capacity resales, utility pole attachment revenues, and other services provided to customers and other energy providers. Arrangements with Multiple Performance Obligations Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. The Company generally determines standalone selling prices based on the prices charged to customers.

Balance Sheet Components (Notes

Balance Sheet Components (Notes)	6 Months Ended
	Jun. 30, 2022
Balance Sheet Components [Abstract]
BALANCE SHEET COMPONENTS	BALANCE SHEET COMPONENTS Inventories PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil, for use in the Company’s generating plants. Periodically, PGE assesses whether inventories are recorded at the lower of average cost or net realizable value. Accounts Receivable, Net Accounts receivable, net includes $94 million and $117 million of unbilled revenues as of June 30, 2022 and December 31, 2021, respectively. Accounts receivable, net is net of an allowance for credit losses of $23 million and $26 million as of June 30, 2022 and December 31, 2021, respectively. The following summarizes activity in the allowance for credit losses (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2022 Balance as of beginning of period $ 28 $ 26 (Decrease)/increase in provision (2) 4 Amounts written off (4) (10) Recoveries 1 3 Balance as of end of period $ 23 $ 23 Other Current Assets Other current assets consist of the following (in millions): June 30, 2022 December 31, 2021 Prepaid expenses $ 55 $ 66 Assets from price risk management activities 221 102 Margin deposits 34 37 Other current assets $ 310 $ 205 Assets from price risk management activities and related unrealized gains increased during the six months ended June 30, 2022 due to increases in wholesale natural gas and electricity prices. For further information, see Note 5, Risk Management. Electric Utility Plant, Net Electric utility plant, net consists of the following (in millions): June 30, 2022 December 31, 2021 Electric utility plant $ 12,062 $ 11,838 Construction work-in-progress 383 313 Total cost 12,445 12,151 Less: accumulated depreciation and amortization (4,281) (4,146) Electric utility plant, net $ 8,164 $ 8,005 Accumulated depreciation and amortization in the table above includes accumulated amortization related to intangible assets of $470 million and $446 million as of June 30, 2022 and December 31, 2021, respectively. Amortization expense related to intangible assets was $14 million and $15 million for the three months ended June 30, 2022 and 2021, respectively and $29 million and $30 million for the six months ended June 30, 2022 and 2021, respectively. The Company’s intangible assets primarily consist of computer software development and hydro licensing costs. Pelton/Round Butte —Under terms of an agreement (the “Agreement”) approved by the OPUC in 2000, PGE had a 66.67% ownership interest in the 455 Megawatts (MW) Pelton/Round Butte hydroelectric project on the Deschutes River (Pelton/Round Butte), with the remaining interest held by the Confederated Tribes of the Warm Springs Reservation of Oregon (CTWS). In the Agreement, the CTWS had an option to purchase an additional undivided 16.66% ownership interest in Pelton/Round Butte in 2021. On June 30, 2021, the CTWS notified PGE of their intent to exercise this purchase option. Under the terms of the purchase option, on January 1, 2022, PGE completed the sale of the additional undivided interest in the project at a net book value of $37 million, with no gain or loss recognized on the sale. Under terms of the Agreement, the CTWS has a second option in 2036 to purchase an undivided 0.02% interest in Pelton/Round Butte. If the second option is exercised, the CTWS’ ownership percentage would exceed 50%. PGE remains the operator of the project. PGE has agreed to purchase 100% of the CTWS’ share of the project’s output under a Power Purchase Agreement (PPA) through 2040. The exercise of the purchase option on January 1, 2022 was evaluated as a sale-leaseback arrangement, and PGE determined that the transaction did not qualify for sale-leaseback accounting. As a result, the transaction is accounted for as a financing arrangement. PGE will continue to record the tangible utility asset within Electric utility plant, net on the condensed consolidated balance sheets as if it were the legal owner and will continue to recognize depreciation expense over the estimated useful life. A financing obligation of $25 million was recorded in Other noncurrent liabilities in the first quarter of 2022. Proceeds related to the financing obligation of $25 million were recorded as a financing activity while proceeds from the sale of intangible property of $11 million and from the sale of construction work-in-progress of $1 million were recorded as an investing activity on the condensed consolidated statements of cash flow. The monthly PPA payments are split between interest expense and a reduction of the principal portion of the financing obligation. 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. Battery storage agreement —In the first quarter of 2022, PGE commenced a finance lease for an energy storage agreement with a 20-year term, related to the Wheatridge Renewable Energy Facility. The Company recorded a lease liability and a corresponding right-of-use asset of $29 million in PGE’s condensed consolidated balance sheets. Regulatory Assets and Liabilities Regulatory assets and liabilities consist of the following (in millions): June 30, 2022 December 31, 2021 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ — $ — $ — $ 55 Pension and other postretirement plans — 125 — 131 Debt issuance costs — 22 — 23 Trojan decommissioning activities — 99 — 90 February 2021 ice storm and damage — 72 — 67 Power cost adjustment mechanism — 30 — 29 2020 Labor Day wildfire — 30 — 45 COVID-19 — 34 — 36 Wildfire mitigation — 20 — — Other 16 66 24 57 Total regulatory assets $ 16 $ 498 $ 24 $ 533 Regulatory liabilities: Asset retirement removal costs $ — $ 1,121 $ — $ 1,047 Deferred income taxes — 201 — 208 Asset retirement obligations — 4 — 43 Price risk management 165 23 55 — Other 38 69 51 62 Total regulatory liabilities $ 203 * $ 1,418 $ 106 * $ 1,360 * Included in Accrued expenses and other current liabilities in the condensed consolidated balance sheets. On April 25, 2022, the OPUC issued Order 22-129, which adopted all stipulations agreed to by the parties to the proceeding in PGE’s 2022 GRC, including the annual revenue requirement, cost of capital, capitalization ratio, and the elimination of the decoupling mechanism, although deferral related to the decoupling mechanism will continue on a prorated basis through the end of 2022. In 2023 and forward, deferral related to the decoupling mechanism will cease. Key elements of the OPUC’s Order also included: • establishment of a balancing account for the Company’s major storm damage recovery mechanism; • denial of PGE’s proposal for a secondary phase of the 2022 GRC regarding the Faraday capital improvement project under construction. PGE can pursue recovery in the Company’s next GRC; • approval of an intervenor request that would require PGE to defer and refund, subject to an earnings test, the revenue requirement associated with the Company’s Boardman coal-fired generating plant included in customer prices following plant closure in 2020; and • creation of an earnings test for the deferrals for the 2020 Labor Day wildfire and the February 2021 ice storm and damage that is to be applied on a year-by-year basis. As a result of the earnings tests outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax, non-cash charge to earnings for the three months ended March 31, 2022 in the amount of $17 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. PGE does not expect to exceed its regulated return on equity under the earnings test methodology approved by the OPUC and as a result, no release of deferrals or earnings test reserve is expected for 2021 and 2022. The OPUC has significant discretion in making the final determination of the application of the earnings test for 2020, 2021, and 2022 and could result in additional disallowances compared to the amount reserved by the Company as of June 30, 2022, which could be material. Wildfire Mitigation represents incremental costs and investments made by PGE under Oregon Senate Bill 762 (SB 762), which was passed in the 2021 legislative session with an effective date of July 19, 2021. SB 762 instructs public utilities to develop, implement, and operate a wildfire protection plan, in which reasonable costs can be recovered through the rates of all customers. The outcome of PGE’s 2022 GRC provided an annual amount of $24 million to be collected in base rates in regards to wildfire mitigation efforts. On July 1, 2022, PGE filed an application for reauthorization of OPUC Docket UM 2019 to defer incremental wildfire mitigation costs which exceed the amount granted in base rates. As of June 30, 2022, PGE’s deferred balance related to wildfire mitigation was $20 million. While the Company believes the full amount of the deferral is probable of recovery, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. February 2021 ice storm and damage represents the costs incurred to repair damage to PGE’s transmission and distribution systems and restore power to customers as a result of the historic storms that ultimately led Oregon’s Governor to declare a state of emergency in February 2021. The Company filed an application for authorization to defer emergency restoration costs for the February storms (OPUC Docket UM 2156). PGE received OPUC Order No. 22-020 approving the February storms deferral in the first quarter of 2022. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect the deferred costs in customer prices over a seven year amortization period beginning November 1, 2022. While the Company believes the full amount of the deferral is probable of recovery as PGE’s prudently incurred costs were in response to the unique and unprecedented nature of the storms, the OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusions of overall prudence, including application of the earnings test, could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. 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) net variable power costs (NVPC) forecast each year and included in customer prices via the Company’s Annual Power Cost Update Tariff (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 condensed consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the condensed 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. Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s condensed consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense . For the year ended December 31, 2021, actual NVPC was $62 million above baseline NVPC, and therefore PGE deferred $30 million which represents 90% of the excess variance expected to be collected from customers for the year ended December 31. 2021. 2020 Labor Day Wildfire —In 2020, the state of Oregon experienced the most destructive wildfire seasons on record, with over one million acres of land burned that ultimately led Oregon’s Governor to declare a state of emergency. PGE has incurred costs to replace and rebuild PGE facilities damaged by the fires, as well as address fire-damaged vegetation and other resulting debris and hazards both in and outside of PGE’s property and right-of-way. On October 20, 2020, the OPUC formally approved PGE’s request for deferral of such costs (Docket UM 2115). As of June 30, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the wildfire response was $30 million and $45 million, respectively. Among the provisions of Order 22-129, the OPUC established an earnings test for the 2020 Labor Day wildfire deferral. Pursuant to the earnings test outlined in the OPUC’s Order, the Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $15 million. The amount recorded represents the Company’s estimate based on its interpretation of the OPUC’s earnings test. The charge was recorded to Generation, transmission and distribution expenses in the condensed consolidated statements of income. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow the company to collect in customer prices over a seven year amortization period beginning November 1, 2022. PGE believes amounts deferred as of June 30, 2022 are probable of recovery as the Company’s prudently incurred costs were in response to the unique and unprecedented nature of the wildfire events leading to the deferral. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence, including application of the earnings test, could result in a portion, or all, of PGE’s deferral being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. COVID-19— The COVID-19 pandemic led Oregon’s Governor to declare a state of emergency on March 8, 2020. Due to the adverse impacts of COVID-19 on economic activity, PGE has experienced an increase in bad debt expense, lost revenue, and other incremental costs. On March 20, 2020, PGE filed an application with the OPUC for deferral of lost revenue and certain incremental costs, such as bad debt expense, related to COVID-19. PGE, other utilities under the OPUC’s jurisdiction, intervenors, and OPUC staff held discussions regarding the scope of costs incurred by utilities that may qualify for deferral under Docket UM 2114, Investigation into the Effects of the COVID-19 Pandemic on Utility Customers . The result of such discussions was an Energy Term Sheet (Term Sheet), which dictates costs in scope for deferral but is silent on the timing of recovery of such costs. On September 24, 2020, the Commission adopted a proposed OPUC Staff motion for Staff to execute stipulations incorporating the terms of the Term Sheet. PGE’s deferral application was approved by the Commission on October 20, 2020 with final stipulations for the Term Sheet approved on November 3, 2020. As of June 30, 2022 and December 31, 2021, PGE’s deferred balance was $34 million and $36 million, respectively, comprised primarily of bad debt expense in excess of what is currently considered and collected in customer prices. The Company has released deferrals associated with the year ended 2020, resulting in a pre-tax charge to earnings for the three months ended March 31, 2022 in the amount of $2 million. The amount recorded represents the Company’s estimate based on its understanding of the OPUC’s intent to apply an earnings test to certain elements of utility COVID deferrals. Amortization of any deferred costs will remain subject to OPUC review prior to amortization in customer prices and would be subject to an earnings test. PGE believes amounts deferred are probable of recovery as the Company’s prudently incurred costs were in response to the unique nature of the COVID-19 pandemic health emergency. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence, including application of earnings review, could result in a portion, or all, of PGE’s deferrals being disallowed for recovery. Such disallowance would be recognized as a charge to earnings. Accrued Expenses and Other Current Liabilities Accrued expenses and other current liabilities consist of the following (in millions): June 30, 2022 December 31, 2021 Accrued employee compensation and benefits $ 51 $ 67 Accrued taxes payable 30 46 Accrued interest payable 30 29 Accrued dividends payable 42 40 Regulatory liabilities—current 203 106 Margin deposits from wholesale counterparties 208 58 Other 89 111 Total accrued expenses and other current liabilities $ 653 $ 457 Credit Facilities As of June 30, 2022, PGE had a $650 million revolving credit facility scheduled to expire in September 2026. The Company has the ability to expand the revolving credit facility to $750 million, if needed, subject to the requirements of the agreement. Pursuant to the terms of the agreement, the revolving credit facility may be used for general corporate purposes, including as backup for commercial paper borrowings and to permit the issuance of standby letters of credit. PGE may borrow for one, three, or six months at a fixed interest rate established at the time of the borrowing, or at a variable interest rate for any period up to the then remaining term of the applicable credit facility. The revolving credit facility contains a provision that requires annual fees based on the Company ’ s unsecured credit ratings, and contains customary covenants and default provisions, including a requirement that limits consolidated indebtedness, as defined in the agreement, to 65% of total capitalization. As of June 30, 2022, PGE was in compliance with this covenant with a 55.6% debt-to-total capital ratio and the aggregate unused available credit capacity under the revolving credit facility was $650 million. In addition, the credit facility offers the potential for adjustments to interest rate margins and fees based on PGE’s achievement of certain annual sustainability-linked metrics related to its non-emitting generation capacity and the percentage of management comprised of women and employees who identify as black, indigenous, and people of color. The Company believes these potential adjustments will have an immaterial impact on PGE’s results of operations. The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. The Company has elected to limit its borrowings under the revolving credit facility in order to allow for coverage of any potential need to repay any commercial paper that may be outstanding at the time. As of June 30, 2022, PGE had no commercial paper outstanding. PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. In addition, PGE has three 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, letters of credit for a total of $91 million were outstanding as of June 30, 2022. Letters of credit issued are not reflected on the Company’s condensed consolidated balance sheets. Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount of up to $900 million through February 6, 2024. Defined Benefit Retirement Plan Costs Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Service cost $ 4 $ 5 $ 8 $ 10 Interest cost* 7 7 14 14 Expected return on plan assets* (12) (11) (24) (22) Amortization of net actuarial loss* 4 5 8 10 Net periodic benefit cost $ 3 $ 6 $ 6 $ 12 * The net expense portion of non-service cost components are included in Miscellaneous income (expense), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

Fair Value of Financial Instrum

Fair Value of Financial Instruments (Notes)	6 Months Ended
	Jun. 30, 2022
Fair Value of Financial Instruments [Abstract]
FAIR VALUE OF FINANCIAL INSTRUMENTS	FAIR VALUE OF FINANCIAL INSTRUMENTS PGE estimated the fair value of financial asset and liability instruments as of June 30, 2022 and December 31, 2021, and classified these financial instruments 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: 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; and 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 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. 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. The Company’s financial assets and liabilities whose values were recognized at fair value in the Company’s condensed consolidated balance sheets are as follows by level within the fair value hierarchy (in millions): As of June 30, 2022 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 63 $ — $ — $ — $ 63 Nuclear decommissioning trust: (1) Debt securities: Domestic government 9 8 — — 17 Corporate credit — 12 — — 12 Money market funds — — — 14 14 Non-qualified benefit plan trust: (3) Debt securities—domestic government 3 — — — 3 Money market funds 1 — — — 1 Equity securities 3 — — — 3 Price risk management activities: (1) (4) Electricity — 39 11 — 50 Natural gas — 235 26 — 261 $ 79 $ 294 $ 37 $ 14 $ 424 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 43 $ 71 $ — $ 114 Natural gas — 7 1 — 8 $ — $ 50 $ 72 $ — $ 122 (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 $31 million, which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. As of December 31, 2021 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 44 $ — $ — $ — $ 44 Nuclear decommissioning trust: (1) Debt securities: Domestic government 9 10 — — 19 Corporate credit — 14 — — 14 Money market funds — — — 14 14 Non-qualified benefit plan trust: (3) Debt securities—domestic government 4 — — — 4 Money market funds 1 — — — 1 Equity securities 4 — — — 4 Price risk management activities: (1) (4) Electricity — 16 1 — 17 Natural gas — 115 5 — 120 $ 62 $ 155 $ 6 $ 14 $ 237 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 33 $ 90 $ — $ 123 Natural gas — 13 1 — 14 $ — $ 46 $ 91 $ — $ 137 (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 $36 million, which are recorded at cash surrender value. (4) For further information, see Note 5, 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 holdings of such funds not exceed 90 days and provide investors with the ability to redeem shares of the funds daily at their respective net asset value. 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 the National Association of Securities Dealers Automated Quotations (Nasdaq) and the New York Stock Exchange (NYSE). Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors: Debt securities —PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the 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 yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are 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. Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates and reduce volatility in NVPC for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, 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 longer-term commodity forwards, futures, swaps, and options for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below: Fair Value Valuation Technique Significant Unobservable Input Price per Unit Commodity Contracts Assets Liabilities Low High Weighted Average (in millions) As of June 30, 2022 Electricity physical forwards $ 5 $ 68 Discounted cash flow Electricity forward price (per MWh) $ 24.00 $ 161.94 $ 67.03 Natural gas financial swaps 26 1 Discounted cash flow Natural gas forward price (per Decatherm) 2.98 6.34 3.45 Electricity financial futures 6 3 Discounted cash flow Electricity forward price (per MWh) 31.42 161.94 80.47 $ 37 $ 72 As of December 31, 2021 Electricity physical forwards $ — $ 90 Discounted cash flow Electricity forward price (per MWh) $ 16.66 $ 129.75 $ 43.73 Natural gas financial swaps 5 1 Discounted cash flow Natural gas forward price (per Decatherm) 2.02 8.02 2.81 Electricity financial futures 1 — Discounted cash flow Electricity forward price (per MWh) 26.76 68.43 52.46 $ 6 $ 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 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 long-term price curves that utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. 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 PGE’s position as either the buyer or seller under 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 Market price Buy Increase (decrease) Gain (loss) Market price Sell Increase (decrease) Loss (gain) Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Balance as of the beginning of the period $ 52 $ 117 $ 85 $ 137 Net realized and unrealized gains * (19) (62) (56) (83) Transfers from Level 3 to Level 2 2 3 6 4 Balance as of the end of the period $ 35 $ 58 $ 35 $ 58 * Both realized and unrealized losses/(gains), of which the unrealized portions are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income. Includes $2 million in net realized gains and $1 million in net realized losses for the three-month periods ended June 30, 2022 and June 30, 2021. respectively. For the six-month periods ended June 30, 2022 and June 30, 2021, includes $3 million in net realized gains and $2 million in net realized losses, respectively. 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. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement. As of June 30, 2022, the carrying amount of PGE’s long-term debt was $3,286 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $3,092 million. As of December 31, 2021, the carrying amount of PGE’s long-term debt was $3,285 million, net of $14 million of unamortized debt expense, and its estimated aggregate fair value was $3,831 million.

Risk Management (Notes)

Risk Management (Notes)	6 Months Ended
	Jun. 30, 2022
Price Risk Management [Abstract]
RISK MANAGEMENT	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 generation resources. The Company also performs portfolio management and wholesale market sales services for third parties in the region. 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 flows. PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forwards, future, swap, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. PGE also enters into non-exchange-traded weather contract options, which are accounted for using the intrinsic value method. 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 ins truments as economic hedges. The Company does not intend to engage in trading activities for non-retail purposes. PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): June 30, 2022 December 31, 2021 Current assets: Commodity contracts: Electricity $ 40 $ 16 Natural gas 181 86 Total current derivative assets (1) 221 102 Noncurrent assets: Commodity contracts: Electricity 10 1 Natural gas 80 34 Total noncurrent derivative assets (1) 90 35 Total derivative assets (2) $ 311 $ 137 Current liabilities: Commodity contracts: Electricity $ 51 $ 36 Natural gas 4 11 Total current derivative liabilities 55 47 Noncurrent liabilities: Commodity contracts: Electricity 63 87 Natural gas 4 3 Total noncurrent derivative liabilities 67 90 Total derivative liabilities (2) $ 122 $ 137 (1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets. (2) As of June 30, 2022 and December 31, 2021, no 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): June 30, 2022 December 31, 2021 Commodity contracts: Electricity 5 MWhs 4 MWhs Natural gas 173 Decatherms 181 Decatherms Foreign currency $ 41 Canadian $ 19 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 gross on the condensed consolidated balance sheets. 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 June 30, 2022 and December 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements were $3 million, for which PGE posted no collateral. Of the gross amounts recognized as of June 30, 2022 and December 31, 2021, $1 million was for electricity and $2 million was for natural gas. Net realized and unrealized losses (gains) on derivative transactions not designated as hedging instruments are classified in Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Commodity contracts: Electricity $ (14) $ (44) $ (54) $ (67) Natural Gas (27) (89) (238) (114) Foreign currency exchange 1 — 1 — Net unrealized and certain net realized losses/(gains) presented in the table above are offset within the condensed consolidated statements of income and comprehensive income by the effects of regulatory accounting. Of the net amounts recognized in Net income for the three-month periods ended June 30, 2022 and 2021, ne t losses o f $15 million and net gains of $112 million, respectively, have been offset. Net gains of $183 million and $151 million have been offset for the six-month periods ended June 30, 2022 and 2021, respectively. Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2022 2023 2024 2025 2026 Thereafter Total Commodity contracts: Electricity $ 9 $ 6 $ 9 $ 11 $ 2 $ 27 $ 64 Natural gas (117) (107) (23) (7) 1 — (253) Net unrealized loss/(gain) $ (108) $ (101) $ (14) $ 4 $ 3 $ 27 $ (189) 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 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 June 30, 2022 was $110 million, for which PGE has posted $54 million in collateral, consisting of $21 million of letters of credit and $33 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered at June 30, 2022, the cash requirement to either post as collateral or settle the instruments immediately would have been $60 million. As of June 30, 2022, PGE had no cash collateral posted for derivative instruments with no credit-risk-related contingent features. Cash collateral for derivative instruments is classified as Margin deposits included in Other current assets on the Company’s condensed consolidated balance sheets. As of June 30, 2022, PGE received from counterparties $228 million in collateral, consisting of $20 million of letters of credit and $208 million of cash. Increases in margin deposits received from wholesale counterparties is primarily due to the increase in PGE’s natural gas derivative asset positions. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s condensed consolidated balance sheets. PGE is exposed to credit risk in its commodity price risk management activities related to potential nonperformance by counterparties. Credit risk may be concentrated to the extent PGE’s counterparties have similar economic, industry or other characteristics and due to direct or indirect relationships among the counterparties. The Company manages the risk of counterparty default according to its credit policies by performing financial credit reviews, setting limits and monitoring exposures, and requiring collateral (in the form of cash, letters of credit, and guarantees) when needed. PGE also uses standardized enabling agreements and, in certain cases, master netting agreements, which allow for the netting of positive and negative exposures under multiple agreements with counterparties. Despite such mitigation efforts, defaults by counterparties may periodically occur. Based upon periodic review and evaluation, allowances are recorded as needed to reflect credit risk related to wholesale accounts receivable. See Note 4, Fair Value of Financial Instruments, for additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities.

Earnings Per Share (Notes)

Earnings Per Share (Notes)	6 Months Ended
	Jun. 30, 2022
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 period. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the period using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; and ii) contingently issuable time-based and performance-based restricted stock units, along with associated dividend equivalent rights. Unvested performance-based restricted stock units and associated dividend equivalent rights are included in dilutive potential common shares only after the performance criteria have been met. For the three and six months ended June 30, 2022, unvested performance-based restricted stock units and related dividend equivalent rights of 337 thousand shares were excluded from the dilutive calculation because the performance goals had not been met, with 367 thousand shares excluded for the three and six months ended June 30, 2021. Net income is the same for both the basic and diluted earnings per share computations. The denominators of the basic and diluted earnings per share computations are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Weighted-average common shares outstanding—basic 89,225 89,554 89,310 89,555 Dilutive effect of potential common shares 146 118 139 132 Weighted-average common shares outstanding—diluted 89,371 89,672 89,449 89,687

Equity (Notes)

Equity (Notes)	6 Months Ended
	Jun. 30, 2022
Equity [Abstract]
Equity	SHAREHOLDERS’ EQUITY The activity in equity during the three- and six-month periods ended June 30, 2022 and 2021 was as follows (dollars in millions, except per share amounts): Common Stock Accumulated Retained Shares Amount Total Balances as of December 31, 2021 89,410,612 $ 1,241 $ (10) $ 1,476 $ 2,707 Issuances of shares pursuant to equity-based plans 163,291 — — — — Stock-based compensation — — — — — Repurchase of common stock (350,000) (5) — (13) (18) Dividends declared ($0.4300 per share) — — — (40) (40) Net income — — — 60 60 Balances as of March 31, 2022 89,223,903 $ 1,236 $ (10) $ 1,483 $ 2,709 Issuances of shares pursuant to equity-based plans 18,769 1 — — 1 Stock-based compensation — 4 — — 4 Other comprehensive income — — 1 — 1 Dividends declared ($0.4525 per share) — — — (41) (41) Net income — — — 64 64 Balances as of June 30, 2022 89,242,672 $ 1,241 $ (9) $ 1,506 $ 2,738 Balances as of December 31, 2020 89,537,331 $ 1,231 $ (11) $ 1,393 $ 2,613 Issuances of shares pursuant to equity-based plans 39,417 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.4075 per share) — — — (36) (36) Net income — — — 96 96 Balances as of March 31, 2021 89,576,748 $ 1,233 $ (11) $ 1,453 $ 2,675 Issuances of shares pursuant to equity-based plans 74,974 1 — — 1 Stock-based compensation — 4 — — 4 Repurchase of common stock (250,000) (3) — (9) (12) Dividends declared ($0.4300 per share) — — — (39) (39) Net income — — — 32 32 Balances as of June 30, 2021 89,401,722 $ 1,235 $ (11) $ 1,437 $ 2,661

Contingencies (Notes)

Contingencies (Notes)	6 Months Ended
	Jun. 30, 2022
Contingencies [Abstract]
CONTINGENCIES	CONTINGENCIES PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed 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 PGE: 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. 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 may be 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 has been included among more than one hundred Potentially Responsible Parties (PRPs) as it historically owned or operated property near the river. A Portland Harbor site remedial investigation was 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 a feasibility study, along with a 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 Portland Harbor, which had 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. Stakeholders have raised concerns that EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The EPA acknowledged the estimated costs were 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 Portland Harbor had improved substantially with the passage of time. 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. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has indicated it will take the initial lead to perform remedial design on the remaining areas. The Company anticipates that remedial design 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 announced on February 12, 2021 that the entirety of Portland Harbor is under an active engineering design phase. 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, including conclusion of 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. Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor 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 costs related to EPA and NRD liabilities on 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 estimated liabilities and environmental expenditures related to Portland Harbor through a combination of third-party proceeds, including but not limited to 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 GRC. 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 collecting any Portland Harbor cost from the PHERA through customer prices. Putative Shareholder Derivative Lawsuits On January 26, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned Shimberg v. Pope , No. 21- cv-02957, (the “ Shimberg Action”) against one current and one former PGE executive and certain members and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought damages to be awarded to the Company of not less than $10 million, equitable relief to remedy the alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. On June 1, 2021, the plaintiff filed an unopposed motion to consolidate this lawsuit with the Ashabraner Action (described below), which the Court granted in an order dated July 27, 2021. On March 17, 2021, a putative shareholder derivative lawsuit was filed in U.S. District Court for the District of Oregon, captioned JS Halberstam Irrevocable Grantor Trust v. Davis , No. 3:21-cv-00413-SI, (the “ JS Halberstam Action”) against one current and one former PGE executive and certain current and former members of the Company's Board of Directors. The plaintiff asserted claims for alleged breaches of fiduciary duties, waste of corporate assets, contribution and indemnification, aiding and abetting, and gross mismanagement, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought equitable relief to remedy and prevent future alleged breaches of fiduciary duty, and an award of plaintiff’s attorneys’ fees and costs. On April 7, 2021, a putative shareholder derivative lawsuit was filed in Multnomah County Circuit Court, Oregon, captioned, Ashabraner v. Pope , 21-cv-13698 (the “ Ashabraner Action”), against one current and one former PGE executive and certain and former members of the Company's Board of Directors. The plaintiff asserted a claim for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff alleged that the defendants made material misstatements and omissions and allowed the Company to operate with inadequate internal controls. The complaint demanded a jury trial and sought damages to be awarded to the Company, equitable relief, and an award of plaintiff’s attorneys’ fees and costs. On July 27, 2021, the Court issued an order consolidating the Ashabrane r Action with the Shimberg Action. On May 21, 2021, a putative shareholder derivative lawsuit was filed in the U.S. District Court for the District of Oregon, Portland Division captioned Berning v. Pope , No. 3:21-cv-00783-SI, (the “ Berning Action”; collectively with the Shimberg, JS Halberstam , and Ashabraner Actions, the “Derivative Actions”), against one current and one former PGE executive and certain current and former members of the Company's Board of Directors and named the Company as a nominal defendant only. The plaintiff asserted claims for alleged breaches of fiduciary duties, purportedly on behalf of PGE, arising from the energy trading losses the Company previously announced in August 2020. The plaintiff also asserted a claim against the two executives for contribution and indemnity based on alleged violations of Sections 10(b) and 21D of the Exchange Act. The complaint demanded a jury trial and sought multiple forms of relief, including, among other things: a declaration that defendants breached and/or aided and abetted the breach of their fiduciary duties to PGE; an order directing PGE to reform and improve its corporate governance and internal procedures; restitution; and an award of attorneys’ fees, expenses, and costs. On December 17, 2021, the parties to the Derivative Actions entered into a Memorandum of Understanding to settle the Derivative Actions subject to court approval and other terms (the "MOU"). After the parties entered into the MOU, the Court in the Shimberg and Ashabraner Actions granted an order to abate the proceedings until June 21, 2022. On December 17, 2021, the parties in the JS Halberstam Action filed a motion to stay the proceedings pending submission and court review of the settlement contemplated in the MOU. On February 11, 2022, the parties to the Derivative Actions entered into a Stipulation of Settlement memorializing the terms of the non-monetary settlement, subject to Court approval, as set forth in the MOU. Under the Stipulation of Settlement, the parties to the JS Halberstam Action agreed to stay the proceedings in the Derivative Actions pending Court approval of the settlement. In addition, the Stipulation of Settlement provided that defendants would not oppose or object to a request by plaintiffs’ counsel for fees and expenses up to $750,000, which was subject to Court approval. Upon final approval of the Court, such fees and expenses were paid by the Company’s insurance provider under its insurance policy. On February 15, 2022, the plaintiff in the JS Halberstam Action filed a motion for preliminary approval of the settlement. On March 28, 2022, the United States District Court for the District of Oregon entered an order preliminarily approving the settlement and the form and content of the notice to shareholders and set a final hearing for May 9, 2022, in the JS Halberstam Action. On April 18, 2022, the plaintiff in the JS Halberstam Action filed a motion for final approval of the settlement and fee and expense award. On May 9, 2022 the Court issued orders that granted final judgment approval of the settlement. Governmental Investigations In March, April and May 2021, the Division of Enforcement of the Commodity Futures Trading Commission (the "CFTC"), the Division of Enforcement of the SEC, and the Division of Enforcement of the FERC, respectively, informed the Company they are conducting investigations arising out of the energy trading losses the Company previously announced in August 2020. The Company is cooperating with the CFTC, the SEC, and the FERC. Management cannot at this time predict the eventual scope or outcome of these matters. Colstrip Litigation The Company has a 20% ownership interest in the Colstrip Units 3 and 4 coal-fired generating plant (Colstrip), which is located in the state of Montana and operated by one of the co-owners, Talen Montana, LLC (Talen). Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. In addition, other parties have brought claims against the co-owners, which, along with the co-owner disagreements, are described below. On May 10, 2022, Talen’s parent company, Talen Energy Supply, LLC filed for chapter 11 bankruptcy protection, although Colstrip continues to operate and generate electricity for PGE customers and others. Petition to compel arbitration— On April 12, 2021, co-owners Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and Portland General Electric Company (the Petitioners) petitioned in Spokane County Superior Court, Washington, Case No. 21201000-32, against another co-owner, NorthWestern Corporation (Northwestern), and Talen to compel the arbitration initiated by NorthWestern to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or whether unanimous consent is required. The O&O Agreement among the parties states that any dispute shall be submitted for resolution to a single arbitrator with appropriate expertise. On April 14, 2021, the Petitioners filed a petition to compel arbitration. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Petitioners filed a motion to remand in June 2021 that was denied. Talen filed a motion, which, following a hearing in July 2021, was granted, to transfer the case to the U.S. District Court for the District of Montana. T his matter is stayed, as a result of the bankruptcy filing of Talen’s parent company. Challenge to constitutionality of Montana Senate Bills 265 and 266 (SB 265 and SB 266)— On May 4, 2021, the Petitioners filed a claim against NorthWestern and Talen in U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00047-SPW-KLD, based on the passage of SB 265, which attempts to void contractual provisions within the co-owner agreement for Colstrip if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. The passage of SB 265 was supported by Defendants and purports to void the O&O Agreement between all parties, which provides for one arbitrator and venue in Spokane, Washington. The petitioners allege that SB 265 violates the contracts clause of the U.S. Constitution and the Montana Constitution, and is preempted by the Federal Arbitration Act (FAA). The Petitioners seek declaratory relief that SB 265 is unconstitutional as applied to the O&O Agreement and the FAA preempts the enforcement of SB 265. Petitioners filed a First Amended Complaint on May 19, 2021, adding the Attorney General of Montana (Montana AG) as defendant and challenging the constitutionality of SB 266, which purportedly gives the Montana AG authority to penalize and restrain any co-owner of Colstrip who takes steps to shut-down the plant without unanimous consent, or otherwise fails to pay the costs to maintain the plant. Defendant Northwestern filed an answer on June 2, 2021 and asked tha t the case Talen filed, as described in the “Complaint to implement SB 265 and SB 266” below, and this case be consolidated. On May 27, 2021, Petitioners filed a Motion for Preliminary Injunction, to enjoin the Montana AG from enforcing SB 266 against them. On June 17, 2021, d efendants NorthWestern and Talen filed their Oppositions to Motion for Preliminary Injunction (PI) and the Montana AG filed a response taking no position on the PI, stating the State of Montana does not envision enforcing SB 266 any time soon. The Court held a hearing on the Petitioners’ Motion for PI August 6, 2021. On October 13, 2021, the Court issued an order that granted the Petitioners’ Motion for PI, enjoining the Montana AG from enforcing SB 266 against them and on December 17. 2021, the Court further clarified its PI order. On August 17, 2021, the Petitioners filed for partial summary judgment on their claim to declare unconstitutional or unenforceable SB 265, which purports to invalidate the arbitration provision of the parties’ contract. Talen opposes the motion and Northwestern does not oppose the motion, but requests the Court compel arbitration. On October 29, 2021, the Petitioners filed a motion for summary judgment on their claim to declare unconstitutional and unenforceable SB 266. In November 2021, parties filed responses, opposition, and a motion to stay action on the summary judgment. On December 3, 2021, NorthWestern moved to compel arbitration and to appoint a magistrate to oversee the arbitrator selection process. On December 23, 2021, Petitioners and Talen filed their responses. The Court conducted a hearing on April 26, 2022. A decision on this matter is stayed, as a result of the bankruptcy filing of Talen’s parent company. Complaint to implement Montana SB 265 and SB 266— On May 4, 2021, Talen filed a complaint against the Petitioners and NorthWestern, in the Thirteenth Judicial District Court in the State of Montana, as an attempt to implement Montana laws when determining the language of the O&O agreement based on the recent enactment of SB 265, which purports to invalidate provisions of the co-owner operating agreement regarding arbitration, and SB 266, which purports to give the Montana AG authority to prosecute and levy a $100,000 a day fine against any co-owner who takes steps to close Colstrip without unanimous consent of all co-owners. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. Talen filed a motion to remand the case to the State of Montana District Court. Petitioners and NorthWestern have filed a motion to consolidate this case with the Challenge to constitutionality of Montana Senate Bills 265 and 266, described above. On October 21, 2021, the Court stayed the motion to consolidate pending the outcome of Talen’s petition to remand. On December 1, 2021, the U.S. Magistrate Judge issued Findings and Recommendations to remand the case back to state Court. On December 15, 2021, the Petitioners filed Objections to the Findings and Recommendation. T his matter is stayed, as a result of the bankruptcy filing of Talen’s parent company. Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al. On December 14, 2020, the original claim was filed in the Montana Sixteenth Judicial District Court, Rosebud County, Cause No. CV-20-58. The plaintiffs allege they have suffered adverse effects from the defendants’ coal dust. On August 26, 2021, the claim was amended to add PGE as a defendant. On November 1, 2021, the defendants filed an answer to the complaint. Plaintiffs are seeking economic damages, costs and disbursements, punitive damages, attorneys’ fees, and an injunction prohibiting defendants from allowing coal dust to blow onto plaintiffs’ properties, as determined by the Court. The Court set a trial to begin September 26, 2023. Since these lawsuits are in early stages, the Company is unable to predict outcomes or estimate a range of reasonably possible losses. Other Matters PGE is subject to other regulatory, environmental, and legal proceedings, investigations, and claims that arise from time to time in the ordinary course of business that may result in judgments against the Company. Although management currently believes that resolution of such known matters, individually and in the aggregate, will not have a material impact on its financial position, results of operations, or cash flows, these matters are subject to inherent uncertainties, and management’s view of these matters may change in the future.

Guarantees (Notes)

Guarantees (Notes)	6 Months Ended
	Jun. 30, 2022
Guarantees [Abstract]
GUARANTEES	GUARANTEESPGE enters into financial agreements for, and purchase and sale agreements involving physical delivery of, both power and natural gas 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 June 30, 2022, management believes the likelihood is remote that PGE would be required to perform under such indemnification provisions or otherwise incur any significant losses with respect to such indemnities. The Company has not recorded any liability on the condensed consolidated balance sheets with respect to these indemnities.

Income tax Income tax (Notes)

Income tax Income tax (Notes)	6 Months Ended
	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Income Tax Disclosure [Text Block]	INCOME TAXES Income tax expense for interim periods is based on the estimated annual effective tax rate, which includes tax credits, regulatory flow-through adjustments, and other items, applied to the Company’s year-to-date, pre-tax income . The significant differences between the Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % 21.0 % Federal tax credits * (9.5) (11.7) (10.0) (9.6) State and local taxes, net of federal tax benefit 9.0 8.3 9.0 8.7 Flow-through depreciation and cost basis differences 0.6 (3.0) 0.6 (0.5) Amortization of excess deferred income tax (4.1) (3.4) (4.3) (3.3) Local tax flow-through adjustment — — — (6.1) Other (0.1) (0.1) (0.1) (1.0) Effective tax rate 16.9 % 11.1 % 16.2 % 9.2 % * Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. 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. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030. Local tax flow-through adjustment The Company is subject to a local tax that is recovered through a supplemental tariff based on current tax expense, but for which the Company has also recognized deferred income tax expenses over time. Because it is probable that the local deferred taxes will be flowed through future customer prices in accordance with the supplemental tariff, PGE determined a corresponding regulatory asset should have been recorded. In the first quarter of 2021, PGE recognized a regulatory asset to defer previously recorded deferred income tax expenses in the amount of $9 million with a corresponding credit to Income tax expense reflected in the condensed consolidated statements of income for the three months ended March 31, 2021. The adjustment has no impact to the three or six months ended June 30, 2022. Carryforwards Federal tax credit carryforwards as of June 30, 2022 and December 31, 2021 were $102 million and $98 million, respectively. These credits primarily consist of PTCs, which will expire at various dates through 2042. PGE believes that it is more likely than not that its deferred income tax assets as of June 30, 2022 will be realized; accordingly, no valuation allowance has been recorded. As of June 30, 2022, and December 31, 2021, PGE had no material unrecognized tax benefits.

Basis of Presentation (Policies

Basis of Presentation (Policies)	6 Months Ended
	Jun. 30, 2022
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	These condensed consolidated financial statements have been prepared pursuant to the rules and regulations of the United States Securities and Exchange Commission (SEC). Certain information and note disclosures normally included in financial statements prepared in conformity with accounting principles generally accepted in the United States of America (GAAP) have been condensed or omitted pursuant to such regulations
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, PGE assesses whether inventories are recorded at the lower of average cost or net realizable value.
Debt, Policy [Policy Text Block]	PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt on the condensed consolidated balance sheets. Long-term debt is recorded at amortized cost in PGE’s condensed consolidated balance sheets. The value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds is classified as a Level 2 fair value measurement.
Fair Value of Financial Instruments, Policy [Policy Text Block]	Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of 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.Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]	Assets held in the Nuclear decommissioning trust (NDT) and Non-qualified benefit plan (NQBP) trusts are recorded at fair value in PGE’s condensed consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors: Debt securities —PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the 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 yields and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities —Equity mutual fund and common stock securities are 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. Assets and liabilities from price risk management activities, recorded at fair value in PGE’s condensed consolidated balance sheets, consist of derivative instruments entered into by the Company to manage its risk exposure to commodity price and foreign currency exchange rates and reduce volatility in NVPC for the Company’s retail customers. For additional information regarding these assets and liabilities, see Note 5, 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.
Fair Value Transfer, Policy [Policy Text Block]	Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter.
Derivatives, Policy [Policy Text Block]	PGE utilizes derivative instruments to manage its exposure to commodity price risk and foreign exchange rate risk in order to reduce volatility in NVPC for its retail customers. Such derivative instruments, recorded at fair value on the condensed consolidated balance sheets, may include forwards, future, swap, and options contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the condensed consolidated statements of income and comprehensive income. PGE also enters into non-exchange-traded weather contract options, which are accounted for using the intrinsic value method. 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 ins truments as economic hedges. The Company does not intend to engage in trading activities for non-retail purposes.
Commitments and Contingencies, Policy [Policy Text Block]	PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. Contingencies are evaluated using the best information available at the time the condensed 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 PGE: 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. 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 may be considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
Guarantees, Indemnifications and Warranties Policies [Policy Text Block]	Generally, a maximum obligation is not explicitly stated in the indemnification provisions and, therefore, the overall maximum amount of the obligation under such indemnifications cannot be reasonably estimated. PGE periodically evaluates the likelihood of incurring costs under such indemnities based on the Company’s historical experience and the evaluation of the specific indemnities.

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 30, 2022
Revenue Recognition and Deferred Revenue [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table presents PGE’s revenue, disaggregated by customer type (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Retail: Residential $ 250 $ 249 $ 558 $ 559 Commercial 168 170 346 332 Industrial 73 62 142 122 Direct access customers 9 13 17 24 Subtotal 500 494 1,063 1,037 Alternative revenue programs, net of amortization 3 (8) 4 (11) Other accrued revenues, net — (2) — 11 Total retail revenues 503 484 1,067 1,037 Wholesale revenues * 65 41 121 74 Other operating revenues 23 12 29 35 Total revenues $ 591 $ 537 $ 1,217 $ 1,146 * Wholesale revenues include $14 million and $4 million related to electricity commodity contract derivative settlements for the three months ended June 30, 2022 and 2021, respectively, and $33 million

Balance Sheet Components (Table

Balance Sheet Components (Tables)	6 Months Ended
	Jun. 30, 2022
Balance Sheet Components [Abstract]
Allowance for Credit Losses [Text Block]	The following summarizes activity in the allowance for credit losses (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2022 Balance as of beginning of period $ 28 $ 26 (Decrease)/increase in provision (2) 4 Amounts written off (4) (10) Recoveries 1 3 Balance as of end of period $ 23 $ 23
Schedule of Other Current Assets [Table Text Block]	Other current assets consist of the following (in millions): June 30, 2022 December 31, 2021 Prepaid expenses $ 55 $ 66 Assets from price risk management activities 221 102 Margin deposits 34 37 Other current assets $ 310 $ 205
Schedule of Public Utility Property, Plant, and Equipment [Table Text Block]	Electric utility plant, net consists of the following (in millions): June 30, 2022 December 31, 2021 Electric utility plant $ 12,062 $ 11,838 Construction work-in-progress 383 313 Total cost 12,445 12,151 Less: accumulated depreciation and amortization (4,281) (4,146) Electric utility plant, net $ 8,164 $ 8,005
Schedule of Regulatory Assets and Liabilities [Text Block]	Regulatory assets and liabilities consist of the following (in millions): June 30, 2022 December 31, 2021 Current Noncurrent Current Noncurrent Regulatory assets: Price risk management $ — $ — $ — $ 55 Pension and other postretirement plans — 125 — 131 Debt issuance costs — 22 — 23 Trojan decommissioning activities — 99 — 90 February 2021 ice storm and damage — 72 — 67 Power cost adjustment mechanism — 30 — 29 2020 Labor Day wildfire — 30 — 45 COVID-19 — 34 — 36 Wildfire mitigation — 20 — — Other 16 66 24 57 Total regulatory assets $ 16 $ 498 $ 24 $ 533 Regulatory liabilities: Asset retirement removal costs $ — $ 1,121 $ — $ 1,047 Deferred income taxes — 201 — 208 Asset retirement obligations — 4 — 43 Price risk management 165 23 55 — Other 38 69 51 62 Total regulatory liabilities $ 203 * $ 1,418 $ 106 * $ 1,360
Other Liabilities Disclosure [Text Block]	Accrued expenses and other current liabilities consist of the following (in millions): June 30, 2022 December 31, 2021 Accrued employee compensation and benefits $ 51 $ 67 Accrued taxes payable 30 46 Accrued interest payable 30 29 Accrued dividends payable 42 40 Regulatory liabilities—current 203 106 Margin deposits from wholesale counterparties 208 58 Other 89 111 Total accrued expenses and other current liabilities $ 653 $ 457
Pension and Other Postretirement Benefits Disclosure [Text Block]	Components of net periodic benefit cost under the defined benefit pension plan are as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Service cost $ 4 $ 5 $ 8 $ 10 Interest cost* 7 7 14 14 Expected return on plan assets* (12) (11) (24) (22) Amortization of net actuarial loss* 4 5 8 10 Net periodic benefit cost $ 3 $ 6 $ 6 $ 12 * The net expense portion of non-service cost components are included in Miscellaneous income (expense), net within Other income on the Company’s condensed consolidated statements of income and comprehensive income.

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 30, 2022
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 in the Company’s condensed consolidated balance sheets are as follows by level within the fair value hierarchy (in millions): As of June 30, 2022 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 63 $ — $ — $ — $ 63 Nuclear decommissioning trust: (1) Debt securities: Domestic government 9 8 — — 17 Corporate credit — 12 — — 12 Money market funds — — — 14 14 Non-qualified benefit plan trust: (3) Debt securities—domestic government 3 — — — 3 Money market funds 1 — — — 1 Equity securities 3 — — — 3 Price risk management activities: (1) (4) Electricity — 39 11 — 50 Natural gas — 235 26 — 261 $ 79 $ 294 $ 37 $ 14 $ 424 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 43 $ 71 $ — $ 114 Natural gas — 7 1 — 8 $ — $ 50 $ 72 $ — $ 122 (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 $31 million, which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management. As of December 31, 2021 Level 1 Level 2 Level 3 Other (2) Total Assets: Cash equivalents $ 44 $ — $ — $ — $ 44 Nuclear decommissioning trust: (1) Debt securities: Domestic government 9 10 — — 19 Corporate credit — 14 — — 14 Money market funds — — — 14 14 Non-qualified benefit plan trust: (3) Debt securities—domestic government 4 — — — 4 Money market funds 1 — — — 1 Equity securities 4 — — — 4 Price risk management activities: (1) (4) Electricity — 16 1 — 17 Natural gas — 115 5 — 120 $ 62 $ 155 $ 6 $ 14 $ 237 Liabilities: Price risk management activities: (1) (4) Electricity $ — $ 33 $ 90 $ — $ 123 Natural gas — 13 1 — 14 $ — $ 46 $ 91 $ — $ 137 (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 $36 million, which are recorded at cash surrender value. (4) For further information, see Note 5, Risk Management.
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: Fair Value Valuation Technique Significant Unobservable Input Price per Unit Commodity Contracts Assets Liabilities Low High Weighted Average (in millions) As of June 30, 2022 Electricity physical forwards $ 5 $ 68 Discounted cash flow Electricity forward price (per MWh) $ 24.00 $ 161.94 $ 67.03 Natural gas financial swaps 26 1 Discounted cash flow Natural gas forward price (per Decatherm) 2.98 6.34 3.45 Electricity financial futures 6 3 Discounted cash flow Electricity forward price (per MWh) 31.42 161.94 80.47 $ 37 $ 72 As of December 31, 2021 Electricity physical forwards $ — $ 90 Discounted cash flow Electricity forward price (per MWh) $ 16.66 $ 129.75 $ 43.73 Natural gas financial swaps 5 1 Discounted cash flow Natural gas forward price (per Decatherm) 2.02 8.02 2.81 Electricity financial futures 1 — Discounted cash flow Electricity forward price (per MWh) 26.76 68.43 52.46 $ 6 $ 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): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Balance as of the beginning of the period $ 52 $ 117 $ 85 $ 137 Net realized and unrealized gains * (19) (62) (56) (83) Transfers from Level 3 to Level 2 2 3 6 4 Balance as of the end of the period $ 35 $ 58 $ 35 $ 58 * Both realized and unrealized losses/(gains), of which the unrealized portions are offset by the effects of regulatory accounting until settlement of the underlying transactions, are recorded in Revenues, net or Purchased power and fuel expense in the condensed consolidated statements of income and comprehensive income. Includes $2 million in net realized gains and $1 million in net realized losses for the three-month periods ended June 30, 2022 and June 30, 2021. respectively. For the six-month periods ended June 30, 2022 and June 30, 2021, includes $3 million in net realized gains and $2 million in net realized losses, respectively.

Price Risk Management (Tables)

Price Risk Management (Tables)	6 Months Ended
	Jun. 30, 2022
Derivative [Line Items]
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value [Table Text Block]	PGE’s Assets and Liabilities from price risk management activities consist of the following (in millions): June 30, 2022 December 31, 2021 Current assets: Commodity contracts: Electricity $ 40 $ 16 Natural gas 181 86 Total current derivative assets (1) 221 102 Noncurrent assets: Commodity contracts: Electricity 10 1 Natural gas 80 34 Total noncurrent derivative assets (1) 90 35 Total derivative assets (2) $ 311 $ 137 Current liabilities: Commodity contracts: Electricity $ 51 $ 36 Natural gas 4 11 Total current derivative liabilities 55 47 Noncurrent liabilities: Commodity contracts: Electricity 63 87 Natural gas 4 3 Total noncurrent derivative liabilities 67 90 Total derivative liabilities (2) $ 122 $ 137 (1) Total current derivative assets are included in Other current assets, and Total noncurrent derivative assets are included in Other noncurrent assets on the condensed consolidated balance sheets. (2) As of June 30, 2022 and December 31, 2021, no 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): June 30, 2022 December 31, 2021 Commodity contracts: Electricity 5 MWhs 4 MWhs Natural gas 173 Decatherms 181 Decatherms Foreign currency $ 41 Canadian $ 19 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 Revenues, net or Purchased power and fuel, as applicable, in the condensed consolidated statements of income and comprehensive income and were as follows (in millions): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Commodity contracts: Electricity $ (14) $ (44) $ (54) $ (67) Natural Gas (27) (89) (238) (114) Foreign currency exchange 1 — 1 —
Schedule of Risk Derivatives [Table Text Block]	Assuming no changes in market prices and interest rates, the following table indicates the year in which the net unrealized loss/(gain) recorded as of June 30, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions): 2022 2023 2024 2025 2026 Thereafter Total Commodity contracts: Electricity $ 9 $ 6 $ 9 $ 11 $ 2 $ 27 $ 64 Natural gas (117) (107) (23) (7) 1 — (253) Net unrealized loss/(gain) $ (108) $ (101) $ (14) $ 4 $ 3 $ 27 $ (189)

Earnings Per Share (Tables)

Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2022
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Schedule of Earnings Per Share, Basic and Diluted [Table Text Block]	The denominators of the basic and diluted earnings per share computations are as follows (in thousands): Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Weighted-average common shares outstanding—basic 89,225 89,554 89,310 89,555 Dilutive effect of potential common shares 146 118 139 132 Weighted-average common shares outstanding—diluted 89,371 89,672 89,449 89,687

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2022
Equity [Abstract]
Schedule of Stockholders Equity [Table Text Block]	The activity in equity during the three- and six-month periods ended June 30, 2022 and 2021 was as follows (dollars in millions, except per share amounts): Common Stock Accumulated Retained Shares Amount Total Balances as of December 31, 2021 89,410,612 $ 1,241 $ (10) $ 1,476 $ 2,707 Issuances of shares pursuant to equity-based plans 163,291 — — — — Stock-based compensation — — — — — Repurchase of common stock (350,000) (5) — (13) (18) Dividends declared ($0.4300 per share) — — — (40) (40) Net income — — — 60 60 Balances as of March 31, 2022 89,223,903 $ 1,236 $ (10) $ 1,483 $ 2,709 Issuances of shares pursuant to equity-based plans 18,769 1 — — 1 Stock-based compensation — 4 — — 4 Other comprehensive income — — 1 — 1 Dividends declared ($0.4525 per share) — — — (41) (41) Net income — — — 64 64 Balances as of June 30, 2022 89,242,672 $ 1,241 $ (9) $ 1,506 $ 2,738 Balances as of December 31, 2020 89,537,331 $ 1,231 $ (11) $ 1,393 $ 2,613 Issuances of shares pursuant to equity-based plans 39,417 — — — — Stock-based compensation — 2 — — 2 Dividends declared ($0.4075 per share) — — — (36) (36) Net income — — — 96 96 Balances as of March 31, 2021 89,576,748 $ 1,233 $ (11) $ 1,453 $ 2,675 Issuances of shares pursuant to equity-based plans 74,974 1 — — 1 Stock-based compensation — 4 — — 4 Repurchase of common stock (250,000) (3) — (9) (12) Dividends declared ($0.4300 per share) — — — (39) (39) Net income — — — 32 32 Balances as of June 30, 2021 89,401,722 $ 1,235 $ (11) $ 1,437 $ 2,661

Income tax Income tax (Tables)

Income tax Income tax (Tables)	6 Months Ended
	Jun. 30, 2022
Income Tax Disclosure [Abstract]
Schedule of Effective Income Tax Rate Reconciliation [Table Text Block]	The significant differences between the Federal statutory tax rate and PGE’s effective tax rate are reflected in the following table: Three Months Ended June 30, Six Months Ended June 30, 2022 2021 2022 2021 Federal statutory tax rate 21.0 % 21.0 % 21.0 % 21.0 % Federal tax credits * (9.5) (11.7) (10.0) (9.6) State and local taxes, net of federal tax benefit 9.0 8.3 9.0 8.7 Flow-through depreciation and cost basis differences 0.6 (3.0) 0.6 (0.5) Amortization of excess deferred income tax (4.1) (3.4) (4.3) (3.3) Local tax flow-through adjustment — — — (6.1) Other (0.1) (0.1) (0.1) (1.0) Effective tax rate 16.9 % 11.1 % 16.2 % 9.2 % * Federal tax credits primarily consist of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. 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. PTCs are earned for 10 years from the in-service dates of the corresponding facilities. PGE’s wind-powered generating facilities are eligible to earn PTCs until various dates through 2030.

Basis of Presentation (Details)

Basis of Presentation (Details) retail_customers in Thousands, mi² in Thousands, $ in Millions	6 Months Ended
	Jun. 30, 2022 USD ($) mi² retail_customers	Jun. 30, 2021 USD ($)
Basis of Presentation [Abstract]
Service Area Sq Miles | mi²	4
Incorporated Cities	51
Number of Retail Customers | retail_customers	922
Increase (Decrease) in Other Accounts Payable and Accrued Liabilities | $	$ 149	$ 17

Revenue Recognition (Details)

Revenue Recognition (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Disaggregation of Revenue [Line Items]
Subtotal	$ 500	$ 494	$ 1,063	$ 1,037
Alternative revenue programs, net of amortization	3	(8)	4	(11)
Other Cost of Operating Revenue	0
Other accrued (deferred) revenues, net		(2)	0	(11)
Total retail revenues	503	484	1,067	1,037
Wholesale revenues	65	41	121	74
Other operating revenue	23	12	29	35
Total revenues	591	537	1,217	1,146
Gain on Derivative Instruments, Pretax	14	4	33	9
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	250	249	558	559
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	168	170	346	332
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	73	62	142	122
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 9	$ 13	$ 17	$ 24

Balance Sheet Components Allowa

Balance Sheet Components Allowance for Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2022	Jun. 30, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Accounts Receivable, Allowance for Credit Loss	$ 28	$ 26
Accounts Receivable, Allowance for Credit Loss, Period Increase (Decrease)	(2)	4
Accounts Receivable, Allowance for Credit Loss, Writeoff	(4)	(10)
Accounts Receivable, Allowance for Credit Loss, Recovery	1	3
Accounts Receivable, Allowance for Credit Loss	$ 23	$ 23

Balance Sheet Components Other

Balance Sheet Components Other Current Assets (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Other Current Assets [Line Items]
Prepaid expenses	$ 55	$ 66
Assets from price risk management activities	221	102
Margin deposits	34	37
Other current assets	$ 310	$ 205

Balance Sheet Components Electr

Balance Sheet Components Electric Utility Plant, Net (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Electric utility plant	$ 12,062	$ 11,838
Construction work-in-progress	383	313
Total cost	12,445	12,151
Less: accumulated depreciation and amortization	(4,281)	(4,146)
Electric utility plant, net	$ 8,164	$ 8,005

Balance Sheet Components Regula

Balance Sheet Components Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	$ 16		$ 16		$ 24
Regulatory assets - noncurrent	498		498		533
Regulatory Liability, Current	203		203		106
Regulatory liabilities-noncurrent	1,418		1,418		1,360
Purchased power and fuel	168	$ 185	370	$ 354
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30
Removal Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	1,121		1,121		1,047
Deferred Income Tax Charge [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	201		201		208
Asset Retirement Obligation Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	0		0		0
Regulatory liabilities-noncurrent	4		4		43
Revenue Subject to Refund [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory liabilities-noncurrent	23		23		0
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	38		38		51
Regulatory liabilities-noncurrent	69		69		62
Regulatory Clause Revenues, under-recovered
Regulatory Assets and Liabilities [Line Items]
Regulatory Liability, Current	165		165		55
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	0		0		55
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	125		125		131
Loss on Reacquired Debt [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	22		22		23
Environmental Restoration Costs [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	0		0		0
Regulatory assets - noncurrent	99		99		90
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets and Liabilities [Line Items]
Regulatory Assets, Current	16		16		24
Regulatory assets - noncurrent	66		66		57
Storm Costs
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	72		72		67
221119 Other Electric Power Generation
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30		29
Fire
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30		30		45
pandemic
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	34		34		$ 36
wildfire
Regulatory Assets and Liabilities [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	$ 20		$ 20

Balance Sheet Components Othe_2

Balance Sheet Components Other Current Liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Accrued employee compensation and benefits	$ 51	$ 67
Accrued taxes payable	30	46
Accrued interest payable	30	29
Accrued dividends payable	42	40
Regulatory liabilities—current	203	106
Deposits, Wholesale	208	58
Other	89	111
Total accrued expenses and other current liabilities	$ 653	$ 457

Balance Sheet Components Pensio

Balance Sheet Components Pension and Other Postretirement Benefits (Details) - Pension Plan [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 4	$ 5	$ 8	$ 10
Interest cost	7	7	14	14
Expected return on plan assets	(12)	(11)	(24)	(22)
Amortization of net actuarial loss	4	5	8	10
Net periodic benefit cost	$ 3	$ 6	$ 6	$ 12

Balance Sheet Components (Detai

Balance Sheet Components (Details) $ in Millions	3 Months Ended			6 Months Ended		12 Months Ended
	Jun. 30, 2022 USD ($)	Mar. 31, 2022 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2022 USD ($)	Jun. 30, 2021 USD ($)	Dec. 31, 2021 USD ($)
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Accounts Receivable, Allowance for Credit Loss	$ 23	$ 28		$ 23		$ 26
Unbilled Receivables, Current	94			94		117
Finite-Lived Intangible Assets, Accumulated Amortization	470			470		446
Amortization of Intangible Assets	14		$ 15	29	$ 30
Line of Credit Facility, Maximum Borrowing Capacity	$ 750			$ 750
Debt Instrument, Covenant Description				65%
Ratio of Indebtedness to Net Capital	0.556			0.556
Line of Credit Facility, Remaining Borrowing Capacity	$ 650			$ 650
Line of Credit Facility, Current Borrowing Capacity	220		650	220	650
Authorized Short-Term Debt	900			900
Purchased power and fuel	168		$ 185	370	354
Repayments of Long-term Debt				0	140
Operating Lease, Right-of-Use Asset	29			29
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30
Amount above baseline net variable power costs				(32)		62
Lower deadband limit below baseline net variable power costs				15
Upper deadband limit above baseline net variable power costs				30
Proceeds from failed sale-leaseback transactions				25	$ 0
Letters of Credit Outstanding, Amount	91			91
Sale Leaseback Transaction, Net Book Value						37
Gain (Loss) on Disposition of Intangible Assets				11
Gain (Loss) on Disposition of Property Plant Equipment				1
Asset Impairment Charges				17
Increase (Decrease) in Deferred Charges		$ 15
Tangible Asset Impairment Charges				2
Finance Lease, Liability	25			25
221119 Other Electric Power Generation
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30		29
Fire
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	30			30		45
pandemic
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Increase (Decrease) in Accounts Payable and Other Operating Liabilities	34			34		$ 36
Letter of Credit [Member]
SEC Schedule, 12-09, Valuation and Qualifying Accounts Disclosure [Line Items]
Commercial paper	$ 0			$ 0

Fair Value of Financial Instr_3

Fair Value of Financial Instruments Financial Assets and Liabilities Recognized at Fair Value (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Assets:
Cash equivalents	$ 63	$ 44
Debt securities:
Domestic government	17	19
Corporate credit	12	14
Money market funds measured at NAV (2)	14	14
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	3	4
Debt securities—domestic government	3	4
Assets from price risk management activities: (1) (3)
Electricity	50	17
Natural gas	261	120
Total	14	14
Assets, Fair Value Disclosure	424	237
Liabilities from price risk management activities: (1) (3)
Electricity	114	123
Natural gas	8	14
Total	122	137
Fair Value, Inputs, Level 1 [Member]
Assets:
Cash equivalents	63	44
Debt securities:
Domestic government	9	9
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	1	1
Equity securities - domestic	3	4
Debt securities—domestic government	3	4
Assets from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	79	62
Liabilities from price risk management activities: (1) (3)
Electricity	0	0
Natural gas	0	0
Total	0	0
Fair Value, Inputs, Level 2 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	8	10
Corporate credit	12	14
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	39	16
Natural gas	235	115
Total	294	155
Liabilities from price risk management activities: (1) (3)
Electricity	43	33
Natural gas	7	13
Total	50	46
Fair Value, Inputs, Level 3 [Member]
Assets:
Cash equivalents	0	0
Debt securities:
Domestic government	0	0
Corporate credit	0	0
Non-qualified benefit plan trust: (2)
Money market funds	0	0
Equity securities - domestic	0	0
Debt securities—domestic government	0	0
Assets from price risk management activities: (1) (3)
Electricity	11	1
Natural gas	26	5
Total	37	6
Liabilities from price risk management activities: (1) (3)
Electricity	71	90
Natural gas	1	1
Total	$ 72	$ 91

Fair Value of Financial Instr_4

Fair Value of Financial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Low [Member]
Commodity Contracts
Electricity physical forwards	$ 24	$ 16.66
Natural gas financial swaps	2.98	2.02
Financial swaps - electricity	31.42	26.76
High [Member]
Commodity Contracts
Electricity physical forwards	161.94	129.75
Natural gas financial swaps	6.34	8.02
Financial swaps - electricity	161.94	68.43
Weighted Average [Member]
Commodity Contracts
Electricity physical forwards	67.03	43.73
Natural gas financial swaps	3.45	2.81
Financial swaps - electricity	80.47	52.46
Assets [Member]
Commodity Contracts
Electricity physical forwards	5,000,000	0
Natural gas financial swaps	26,000,000	5,000,000
Financial swaps - electricity	6,000,000	1,000,000
Total commodity contracts	37,000,000	6,000,000
Liabilities [Member]
Commodity Contracts
Electricity physical forwards	68,000,000	90,000,000
Natural gas financial swaps	1,000,000	1,000,000
Financial swaps - electricity	3,000,000	0
Total commodity contracts	$ 72,000,000	$ 91,000,000

Fair Value of Financial Instr_5

Fair Value of Financial Instruments Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Balance as of the beginning of the period	$ 52	$ 117	$ 85	$ 137
Net realized and unrealized (gains)/losses	(19)	(62)	(56)	(83)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	2
Transfers out of Level 3 to Level 2		3	6	4
Balance as of the end of the period	$ 35	$ 58	$ 35	$ 58

Fair Value of Financial Instr_6

Fair Value of Financial Instruments Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash Surrender Value, Fair Value Disclosure	$ 31		$ 31		$ 36
net realized loss	1			$ 2
Long-term Debt	3,286		3,286		3,285
Unamortized Debt Issuance Expense	13		13		14
Long-term Debt, Fair Value	3,092		3,092		$ 3,831
Net gain or loss recognized in the statement of income offset by regulatory accounting	15	$ (112)	(183)	$ (151)
net realized gains	$ 2		$ 3

Risk Management Fair values of

Risk Management Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Jun. 30, 2022	Dec. 31, 2021
Current Assets, Commodity Contracts:
Electricity	$ 40	$ 16
Natural gas	181	86
Total current derivative assets	221	102
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	10	1
Commodity Contract Asset, Noncurrent, Natural Gas	80	34
Derivative Asset, Noncurrent	90	35
Total derivative assets	311	137
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	51	36
Natural gas	4	11
Total current derivative liabilities	55	47
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	63	87
Natural gas	4	3
Total noncurrent derivative liabilities	67	90
Total derivative liabilities	$ 122	$ 137

Risk Management Net volumes rel

Risk Management Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Jun. 30, 2022 CAD ($) MWh MMBTU	Dec. 31, 2021 CAD ($) MWh MMBTU
Commodity contracts:
Electricity | MWh	5	4
Natural gas | MMBTU	173	181
Foreign currency | $	$ 41	$ 19

Risk Management Net realized an

Risk Management Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Commodity contracts:
Electricity	$ (14)	$ (44)	$ (54)	$ (67)
Natural Gas	(27)	(89)	(238)	(114)
Foreign currency exchange	$ 1	$ 0	$ 1	$ 0

Risk Management Future Year Net

Risk Management Future Year Net Unrealized Gain/Loss Recorded at Balance Sheet Date Expected to Become Realized (Details) $ in Millions	Jun. 30, 2022 USD ($)
Electricity [Member]
Commodity contracts:
2022	$ 9
2023	6
2024	(9)
2025	11
2026	2
Thereafter	27
Total	(64)
Natural Gas [Member]
Commodity contracts:
2022	117
2023	107
2024	(23)
2025	7
2026	1
Thereafter	0
Total	(253)
Net Unrealized Loss/(gain)[Member]
Commodity contracts:
2022	108
2023	101
2024	(14)
2025	4
2026	3
Thereafter	27
Total	$ (189)

Risk Management (Details)

Risk Management (Details) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021	Dec. 31, 2021
Net gain or (loss) recognized in the statement of income offset by regulatory accounting	$ (15)	$ 112	$ 183	$ 151
Derivative, Net Liability Position, Aggregate Fair Value	110		110
Collateral Already Posted, Aggregate Fair Value	54		54
Collateral cash requirement	60		60
Purchased power and fuel	168	$ 185	370	$ 354
Deposits, Wholesale	208		208		$ 58
Deposits	20		20
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	3		3
Letters of Credit Outstanding, Amount	91		91
Derivative, Collateral, Right to Reclaim Cash	33		33
Pledged Assets Separately Reported, Securities Pledged under Letter of Credit Facilities, at Fair Value	21		21
Derivative Asset, Fair Value, Amount Offset Against Collateral	228		228
Electricity [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	1		1
Natural Gas [Member]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 2		$ 2

Earnings Per Share Components o

Earnings Per Share Components of Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share [Abstract]
Weighted Average Number of Shares Outstanding, Basic	89,225	89,554	89,310	89,555
Dilutive effect of potential common shares	146	118	139	132
Weighted Average Number of Shares Outstanding, Diluted	89,371	89,672	89,449	89,687

Earnings Per Share Earnings Per

Earnings Per Share Earnings Per Share (Details) - shares shares in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Earnings Per Share [Abstract]
Incremental Common Shares Attributable to Dilutive Effect of Contingently Issuable Shares	337	367	337	367

Schedule of Stockholders Equity

Schedule of Stockholders Equity (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2022	Mar. 31, 2022	Jun. 30, 2021	Mar. 31, 2021	Jun. 30, 2022	Jun. 30, 2021
Common Stock, Shares, Outstanding beginning of period		89,410,612			89,410,612
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	2,709	2,707	2,675	2,613	$ 2,707	$ 2,613
Dividends declared	(41)	(40)	(39)	(36)
Net Income (Loss), Including Portion Attributable to Noncontrolling Interest	$ 64	60	32	96	$ 124	128
Common Stock, Shares, Outstanding end of period	89,242,672				89,242,672
Stockholders' Equity	$ 2,738	$ 2,709	$ 2,661	$ 2,675	$ 2,738	2,661
Common Stock, Dividends, Per Share, Declared	$ 0.4525	$ 0.4300	$ 0.4300	$ 0.4075
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	$ 4	$ 0	$ 4	$ 2
Repurchase of common stock		$ (18)	$ (12)		$ (18)	$ (12)
Stock Repurchased During Period, Shares		(350,000)	(250,000)
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	$ 1
Common Stock [Member]
Common Stock, Shares, Outstanding beginning of period	89,223,903	89,410,612	89,576,748	89,537,331	89,410,612	89,537,331
Issuances of shares pursuant to equity-based plans	18,769	163,291	74,974	39,417
Common Stock, Shares, Outstanding end of period	89,242,672	89,223,903	89,401,722	89,576,748	89,242,672	89,401,722
Common Stock Including Additional Paid in Capital [Member]
Issuance of shares pursuant to equity-based plans	$ 1	$ 0	$ 1	$ 0
Stockholders' Equity	1,236	1,241	1,233	1,231	$ 1,241	$ 1,231
Dividends declared	0	0	0	0
Stockholders' Equity	1,241	1,236	1,235	1,233	1,241	1,235
Shares Granted, Value, Share-based Payment Arrangement, after Forfeiture	4	0	4	2
Repurchase of common stock		(5)	(3)
AOCI Attributable to Parent [Member]
Stockholders' Equity	(10)	(10)	(11)	(11)	(10)	(11)
Dividends declared	0	0	0	0
Stockholders' Equity	(9)	(10)	(11)	(11)	(9)	(11)
Repurchase of common stock		0	0
Other Comprehensive Income (Loss), Net of Tax, Portion Attributable to Parent	1
Retained Earnings [Member]
Stockholders' Equity	1,483	1,476	1,453	1,393	1,476	1,393
Dividends declared	41	40	39	36
Stockholders' Equity	$ 1,506	1,483	1,437	$ 1,453	$ 1,506	$ 1,437
Repurchase of common stock		$ (13)	$ (9)

Contingencies (Details)

Contingencies (Details)	6 Months Ended
	Jun. 30, 2022 USD ($) party
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties | party	100
Litigation Settlement, Expense	$ 115,000,000
Loss Contingency, Estimate of Possible Loss	1,700,000,000
Loss Contingency, Damages Sought, Value	1,200,000,000
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500,000,000
Environmental Remediation Expense	6,000,000
amount authorized to levy	100,000
lower range of costs	1,900,000,000
upper range of costs	3,500,000,000
Class action damages sought	10,000,000
Estimated Litigation Liability	$ 750,000

Income tax Effective Income Tax

Income tax Effective Income Tax Rate Reconcilitation (Details)	3 Months Ended		6 Months Ended
	Jun. 30, 2022	Jun. 30, 2021	Jun. 30, 2022	Jun. 30, 2021
Income Tax Disclosure [Abstract]
Federal statutory tax rate	21%	21%	21%	21%
Federal tax credits	(9.50%)	(11.70%)	(10.00%)	(9.60%)
State and local taxes, net of federal tax benefit	9%	8.30%	9%	8.70%
Flow through depreciation and cost basis differences	0.60%	(3.00%)	0.60%	(0.50%)
Excess deferred tax amortization	(4.10%)	(3.40%)	(4.30%)	(3.30%)
Other	0%	0%	0%	(6.10%)
Effective Income Tax Rate Reconciliation,Other Reconciling Items, Percent	(0.10%)	(0.10%)	(0.10%)	(1.00%)
Effective tax rate	16.90%	11.10%	16.20%	9.20%

Income tax Income tax (Details)

Income tax Income tax (Details) - USD ($)	Jun. 30, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Deferred Tax Assets, Other Tax Carryforwards	$ 9,000,000
Deferred Tax Assets, Operating Loss Carryforwards, Domestic	102,000,000	$ 98,000,000
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0