0000784977-23-000005 | 10-K | XBRL Viewer | Portland General Electric CO OR

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Long-term Debt

12 Months Ended

Dec. 31, 2022

Long-term Debt Disclosure [Abstract]

Long-term Debt

LONG-TERM DEBT & OTHER FINANCING ARRANGEMENTS

Long-term debt

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


	As of December 31,
	2022		2021
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.09% in 2022 and 4.11% in 2021, due at various dates through 2051	$	3,280	$	3,180
Unsecured term bank loans, variable rate of approximately 5.30% at December 31, 2022	260		—
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033	119		119

Total long-term debt	3,659		3,299
Less: Unamortized debt expense	(13)		(14)


Less: Current portion of long-term debt	(260)		—
Long-term debt, net of current portion	$	3,386	$	3,285

First Mortgage Bonds—On November 30, 2022, PGE entered into a Bond Purchase Agreement related to the sale of $200 million in FMBs. The bonds consist of:

•a series, due in 2029, in the amount of $100 million that will bear interest at an annual rate of 5.47%; and

•a series, due in 2033, in the amount of $100 million that will bear interest at an annual rate of 5.56%.

The 2029 and 2033 series were issued in 2022 and funded in full on November 30, 2022 and January 13, 2023, respectively.

The Indenture securing PGE’s outstanding FMBs constitutes a direct first mortgage lien on substantially all regulated utility property, other than expressly excepted property. Interest is payable semi-annually on FMBs.

Term Loan—On October 21, 2022, PGE obtained a 366-day term loan from lenders in the aggregate principal of $260 million under a 366-Day Bridge Credit Agreement. The term loan bears interest for the relevant interest period at the Term Secured Overnight Financing Rate (SOFR) plus Term SOFR Adjustment Rate of 10 basis points and Applicable Margin of 87.5 basis points. The interest rate is subject to adjustment pursuant to the terms of the loan. The loan is prepayable, in whole or in part, without penalty, at any time. The credit agreement expires on October 22, 2023, with any outstanding balance due and payable on such date. The term loan is classified as Current portion of long-term debt on PGE’s consolidated balance sheet.

Pollution Control Revenue Bonds—On March 11, 2020, PGE completed the remarketing of an aggregate principal amount of $119 million of Pollution Control Revenue Refunding Bonds (PCRBs), which consist of $98 million aggregate principal of PCRBs that bear an interest rate of 2.125%, and $21 million aggregate principal of PCRBs that bear an interest rate of 2.375%, both due in 2033. At the time of remarketing, the Company chose a new interest rate period that was fixed term. The new interest rate was based on market conditions at the time of remarketing. The PCRBs could be backed by FMBs or a bank letter of credit depending on market conditions. Interest is payable semi-annually on the PCRBs.

As of December 31, 2022, the future minimum principal payments on long-term debt are as follows (in millions):


Years ending December 31:
2023	$	260
2024	80
2025	—
2026	—
2027	160
Thereafter	3,159
	$	3,659

Pelton/Round Butte financing arrangement

Under terms of an agreement (the “Agreement”) approved by the OPUC in 2000, PGE had a 66.67% ownership interest in the 455 Megawatt (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 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 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 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.

As of December 31, 2022, the future minimum payments on the financing arrangement are as follows (in millions):


Years ending December 31:
2023	$	2
2024	2
2025	5
2026	5
2027	5
Thereafter	69
Total Payments	88
Less: Imputed Interest	(61)
Present value of minimum payments	$	27

Contingencies	12 Months Ended
Contingencies	Dec. 31, 2022
Contingencies [Abstract]
Contingencies [Text Block]	CONTINGENCIES PGE is subject to legal, regulatory, and environmental proceedings, investigations, and claims that arise from time to time in the ordinary course of its business. 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. PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact. EPA Investigation of Portland Harbor An investigation by the United States Environmental Protection Agency (EPA) of a segment of the Willamette River known as Portland Harbor that began in 1997 revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. PGE 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 the feasibility study, along with the remedial investigation, and the results provided the framework for the EPA to determine a clean-up remedy for Portland Harbor that was documented in a Record of Decision (ROD) issued in 2017. The ROD outlined the EPA’s selected remediation plan for clean-up of Portland Harbor that 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 are based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost. A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of the Portland Harbor have improved substantially over the past ten years. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. 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 in February 2021 that the entirety of Portland Harbor was 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 represents 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, 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, 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 recovering any Portland Harbor cost from the PHERA through customer prices. 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, SEC, and FERC. Management cannot at this time predict the eventual scope or outcome of these matters. Colstrip-Related Litigation The Company has a 20% ownership interest in Colstrip, which is operated by one of the co-owners, Talen Montana, LLC (Talen). 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. Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation (O&O) Agreement and other matters. An arbitration process has been initiated to address such business disagreements and has resulted in several legal proceedings. These legal proceedings, as well as other matters related to Colstrip, are summarized below. Arbitration—On March 12, 2021, co-owner NorthWestern Corporation (NorthWestern) initiated arbitration against all other co-owners of Colstrip to determine whether co-owners representing 55% or more of the ownership shares can vote to close one or both units of Colstrip, or, alternatively, 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. This arbitration process was initially stayed as a result of the bankruptcy filing of Talen’s parent company, but that stay was lifted in August 2022, by a voluntary stipulation, described below. The arbitration has once again been stayed through March 31, 2023, by agreement of the parties. PGE cannot predict the ultimate outcome of the arbitration process. Petition to compel arbitration—In April 2021, Avista Corporation, Puget Sound Energy Inc., PacifiCorp, and PGE (the Petitioners) petitioned in Spokane County Superior Court, Washington, Case No. 21201000-32, against NorthWestern and Talen to compel the arbitration initiated by NorthWestern that is described above. In May 2021, Talen removed the case to Federal Court (Eastern District of Washington Case No. 2:21-cv-00163-RMP). Following a hearing in July 2021, Talen’s motion to transfer the case to the U.S. District Court for the District of Montana was granted. This matter is stayed, because of the bankruptcy filing of Talen’s parent company. The voluntary stipulation described below (see “Challenge to constitutionality of Montana Senate Bills 265 and 266 (MSB 265 and MSB 266)”) did not lift the stay on this court action. Challenge to constitutionality of Montana Senate Bills 265 and 266 (MSB 265 and MSB 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 MSB 265, which attempted to void contractual arbitration provisions within the O&O Agreement if they do not provide for three arbitrators or provide for venue outside of the county where the plant is located. The passage of MSB 265 was supported by Defendants and purported to void the O&O Agreement among all parties, which provides for one arbitrator and venue in Spokane, Washington. The Petitioners allege that MSB 265 violated the contracts clause of the U.S. Constitution and the Montana Constitution, and is preempted by the Federal Arbitration Act (FAA). The Petitioners sought declaratory relief that MSB 265 was unconstitutional as applied to the O&O Agreement and the FAA preempted the enforcement of MSB 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 MSB 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, and authority to penalize any co-owner who fails or refuses to pay the costs to maintain the plant. The Court held a hearing on August 6, 2021 and on October 13, 2021, the Court issued an order that granted the Petitioners’ Motion for Preliminary Injunction, enjoining the Montana AG from enforcing MSB 266 against them. On August 17, 2021, the Petitioners filed for partial summary judgment on their claim to declare MSB 265 preempted by the FAA and unconstitutional. On October 29, 2021, the Petitioners filed a motion for partial summary judgment on their claim to declare MSB 266 unconstitutional and unenforceable. A decision on this matter had been stayed as a result of the bankruptcy filing of Talen’s parent company, but the stay was lifted by a voluntary stipulation filed by Petitioners, Talen, and NorthWestern, and ordered by the bankruptcy court on August 25, 2022. On September 29, 2022, the Magistrate Judge issued Findings and Recommendations, which were adopted in full by the Court on October 19, 2022, granting both of the Petitioners’ motions for summary judgment regarding the constitutionality of MSB 265 and MSB 266 by finding that MSB 266 was unconstitutional, and MSB 265 was unconstitutional and in the alternative preempted by the FAA. Complaint to implement MSB 265—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 MSB 265. The case was subsequently removed to the U.S. District Court - Montana, Billings Division, Case No. 1:21-cv-00058-SPW-TJC. This matter is stayed, because of the bankruptcy filing of Talen’s parent company. Richard Burnett; Colstrip Properties Inc., et al v. Talen Montana, LLC; PGE, et al—In December 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. In August 2021, the claim was amended to add PGE as a defendant. 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 trial to begin September 26, 2023. This matter was stayed as a result of the bankruptcy filing of Talen’s parent company. On September 23, 2022, by stipulation by the parties and order of the Court, the stay was modified to allow for some limited discovery by the parties in this matter. Pursuant to a stipulation by the parties, litigation can fully resume after February 13, 2023. Since these lawsuits (except for the challenge to constitutionality of MSB 265 and MSB 266) 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, which 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.

- Definition

The entire disclosure for loss and gain contingencies. Describes any existing condition, situation, or set of circumstances involving uncertainty as of the balance sheet date (or prior to issuance of the financial statements) as to a probable or reasonably possible loss incurred by an entity that will ultimately be resolved when one or more future events occur or fail to occur, and typically discloses the amount of loss recorded or a range of possible loss, or an assertion that no reasonable estimate can be made.

+ References + Details

Credit Facilities

12 Months Ended

Dec. 31, 2022

Line of Credit Facility [Abstract]

Credit Facilities

CREDIT FACILITIESIn September 2022, PGE amended its existing revolving credit facility. As of December 31, 2022, PGE had a $650 million revolving credit facility scheduled to expire in September 2027. The Company has the ability to expand the revolving credit facility to $750 million, if needed. 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 65.0% of total capitalization. As of December 31, 2022, PGE was in compliance with this covenant with a 56.9% debt to total capital ratio. 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.

Under the revolving credit facility, as of December 31, 2022, PGE had no borrowings outstanding and there were no commercial paper or letters of credit issued. As a result, the aggregate unused available credit capacity under the revolving credit facility was $650 million.

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 to cover any potential need to repay commercial paper that may be outstanding at the time. As of December 31, 2022, PGE had no commercial paper outstanding.

PGE typically classifies borrowings under the revolving credit facility and outstanding commercial paper as Short-term debt in the 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, a total of $97 million of letters of credit were outstanding as of December 31, 2022. Outstanding letters of credit are not reflected on the Company’s consolidated balance sheets.

Pursuant to an order issued by the FERC, the Company is authorized to issue short-term debt in an aggregate amount up to $900 million through February 6, 2024.

Short-term borrowings under these credit facilities, and related interest rates, are reflected in the following table (dollars in millions).


	Year Ended December 31,
	2022			2021			2020
Average daily amount of short-term debt outstanding	$	2		$	139		$	131
Weighted daily average interest rate *	3.4		%	0.9		%	1.5		%
Maximum amount outstanding during the year	$	135		$	230		$	225

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

Income Taxes Schedule of Deferred tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred income tax assets:
Employee benefits	$ 99	$ 114
Deferred income taxes	75	39
Deferred Tax Assets, tax credits, net of valuation allowance	102	98
Total deferred income tax assets	276	251
Deferred income tax liabilities:
Depreciation and amortization	547	536
Deferred Tax Liabilities, Derivatives	54	0
Regulatory assets	101	121
Deferred Tax Liabilities, Other	13	7
Deferred Tax Liabilities, Gross, Noncurrent	715	664
Total deferred income tax liabilities	$ 439	$ 413

Stock-based Compensation Expense Schedule Of Share Based Payment Award Stock Options Valuation Assumptions (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Risk Free Interest Rate	1.70%	0.20%	1.40%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Term	2 years 10 months 24 days	2 years 10 months 24 days	2 years 10 months 24 days
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Minimum	26.40%	26.10%	13.50%
Share-based Compensation Arrangement by Share-based Payment Award, Fair Value Assumptions, Expected Volatility Rate, Maximum	37.90%	37.90%	97.30%

Fair Value of FInancial Instruments

12 Months Ended

Dec. 31, 2022

Fair Value of Financial Instruments Note [Abstract]

Fair Value of FInancial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTSPGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value for each reporting period. The Company then classifies these financial assets and liabilities based on a fair value hierarchy applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are discussed below.

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

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

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

Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels. There were no significant transfers between levels during the years ended December 31, 2022 and 2021, except those presented in this note.

The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):


	December 31, 2022
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		11		11
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	3		—		—		—		3



Price risk management activities: (1) (4)
Electricity	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:

Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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 regarding price risk management derivatives, see Note 6, Risk Management.


	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 measured at NAV (2)	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4

Debt securities—domestic government	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 regarding price risk management derivatives, see Note 6, Risk Management.

Cash equivalents are highly liquid investments with maturities of three months or less at the date of acquisition and primarily consist of money market funds. Such funds seek to maintain a stable net asset value and are comprised of short-term, government funds. Policies of such funds require that the weighted-average maturity of securities held by the funds do not exceed 90 days and investors have the ability to redeem shares daily at the net asset value of the respective fund. 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 NDT and NQBP trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors:

Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date.

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

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE.

Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice.

The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy.

Assets and liabilities from price risk management activities, recorded at fair value in PGE’s 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 additional information regarding these assets and liabilities, see Note 6, Risk Management.

For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps.

Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer-term commodity forwards, futures, and swaps.

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:


						Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)
As of December 31, 2022:
Electricity physical forwards	$	52	$	93	Discounted cash flow	Electricity forward price (per MWh)	$	35.00	$	270.00	$	101.27
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Dth)	2.71		24.71		4.42
Electricity financial futures	11		—		Discounted cash flow	Electricity forward price (per MWh)	54.17		143.70		104.21
	$	69	$	101
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 Dth)	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 shorter-term contracts, PGE employs the mid-point of the bid-ask spread of the market and these inputs are derived using observed transactions in active markets, as well as historical experience as a participant in those markets. These price inputs are validated against independent market data from multiple sources. For certain long-term contracts, observable, liquid market transactions are not available for the duration of the delivery period. In such instances, the Company uses internally-developed price curves, which derive longer-term prices and utilize observable data when available. When not available, regression techniques are used to estimate unobservable future prices. In addition, changes in the fair value measurement of price risk management assets and liabilities are analyzed and reviewed on a quarterly basis by the Company.

The Company’s Level 3 assets and liabilities from price risk management activities are sensitive to market price changes in the respective underlying commodities. The significance of the impact is dependent upon the magnitude of the price change and the Company’s position as either the buyer or seller of the contract. Sensitivity of the fair value measurements to changes in the significant unobservable inputs is as follows:

Significant Unobservable Input

Position

Change to Input

Impact on Fair Value Measurement

Market price

Buy

Increase (decrease)

Gain (loss)

Market price

Sell

Increase (decrease)

Loss (gain)

Changes in the fair value of net liabilities from price risk management activities (net of assets from price risk management activities) classified as Level 3 in the fair value hierarchy were as follows (in millions):


	Years Ended December 31,
	2022		2021
Net liabilities from price risk management activities as of beginning of year	$	85	$	137
Net realized and unrealized losses/(gains) *	(84)		(50)




Net transfers from Level 3 to Level 2	31		(2)
Net liabilities from price risk management activities as of end of year	$	32	$	85
Level 3 net unrealized losses/(gains) that have been fully offset by the effect of regulatory accounting	$	(82)	$	(55)

* Includes $2 million in net realized gains in 2022 and $5 million in 2021.

Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2022 and 2021, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers into and from Level 3 at the end of the reporting period for all of its derivative instruments.

Transfers from Level 2 to Level 1 for the Company’s price risk management assets and liabilities do not occur as quoted prices are not available for identical instruments. As such, the Company’s assets and liabilities from price risk management activities mature and settle as Level 2 fair value measurements.

Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCRBs) is classified as a Level 2 fair value measurement.

As of December 31, 2022, the carrying amount of PGE’s long-term debt was $3,646 million, net of $13 million of unamortized debt expense, and its estimated aggregate fair value was $2,984 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, with an estimated aggregate fair value of $3,831 million.

For fair value information concerning the Company’s pension plan assets, see Note 11, Employee Benefits.

- Definition

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

+ References + Details

Fair values of price risk management assets and liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current Assets, Commodity Contracts:
Electricity	$ 112	$ 16
Natural Gas	201	86
Total current derivative assets	313	102
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	44	1
Commodity Contract Asset, Noncurrent, Natural Gas	30	34
Derivative Asset, Noncurrent	74	35
Total derivative assets	387	137
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	93	36
Natural Gas	25	11
Total current derivative liabilities	118	47
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	53	87
Natural Gas	22	3
Total noncurrent derivative liabilities	75	90
Total derivative liabilities	$ 193	$ 137

Equity-Based Plans (Details)	12 Months Ended
Equity-Based Plans (Details)	Dec. 31, 2022 USD ($) shares
employee stock purchase plan shares authorized	625,000
Employee Stock Purchase Plan, Base Pay Threshold	10.00%
Employee Stock Purchase Plan, Purchased Stock Value Limitation \| $	$ 25,000
Employee Stock Purchase Plan, Share Purchase Limitation	1,500
Employee Stock Purchase Plan, Purchase Price	95.00%
Employee Stock Purchase Plan, Number of Available Shares	177,145
Dividend Reinvestment and Direct Stock Purchase Plan Shares	2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares	2,458,622

Income Taxes Schedule of Components of Income Tax Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current:
Federal	$ 9	$ 4	$ 6
State and local	24	14	17
Current Income Tax Expense (Benefit)	33	18	23
Deferred:
Federal	(1)	0	(22)
State and local	7	5	(1)
deferred income tax expense	6	5	(23)
Income tax expense	$ 39	$ 23	$ 0

- Definition

Amount of current income tax expense (benefit) and deferred income tax expense (benefit) pertaining to continuing operations.

+ References + Details

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2022

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets and Liabilities [Text Block]

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

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


	Remaining Amortization Period	As of December 31,
		2022						2021
		Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	1	$	1	$	55
Pension and other postretirement plans	(3)	—		95		95		131


Debt issuance costs	2049	—		21		21		23
Trojan decommissioning activities	2059	—		133		133		90
February 2021 ice storm and damage	(4)	74		—		74		67
Power cost adjustment mechanism	(5)	28		—		28		29
2020 Labor Day wildfire	(4)	31		—		31		45
COVID-19	(6)	22		—		22		36
Wildfire mitigation	(6)	28		—		28		—
Other	Various	70		24		94		81
Total regulatory assets		$	253	$	274	$	527	$	557
Regulatory liabilities:
Asset retirement removal costs	(7)	$	1,136	$	—	$	1,136	$	1,047
Deferred income taxes	(8)	194		—		194		208

Asset retirement obligations	(7)	7		—		7		43

Price risk management	(2)	—		195		195		55
Other	Various	67		24		91		113
Total regulatory liabilities		$	1,404	$	219	$	1,623	$	1,466

(1)Earning a return includes either interest on the regulatory asset or liability, or inclusion of the regulatory asset or liability as an increase or decrease to rate base at the allowed rate of return.

(2)No amortization period in accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains on derivative instruments until settlement.

(3)Recovery expected over the average service life of employees.

(4)Amortization will occur over a 7-year period starting January 1, 2023.

(5)Amortization will occur over a 2-year period starting January 1, 2023.

(6)Amortization period not yet determined.

(7)Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base.

(8)Refund expected as the balance is reversed using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base.

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 continued 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. The Company had requested that recovery of the capital cost of improvements at the Faraday hydroelectric facility be included in the new rate base. PGE was permitted to pursue recovery in the Company’s next GRC. As of December 31, 2022, the construction work-in-progress balance of the project

was $168 million, including AFUDC and was placed in-service on January 31, 2023. The Company’s 2024 GRC pursues recovery of the Faraday project in its rate base request;

•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 in 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 that could result in additional disallowances or refunds compared to the amount reserved by the Company as of December 31, 2022, which could be material.

Price risk management represents the difference between the net unrealized losses recognized on derivative instruments related to price risk management activities and their realization and subsequent recovery in customer prices. For further information regarding assets and liabilities from price risk management activities, see Note 6, Risk Management.

Pension and other postretirement plans represents unrecognized components of the benefit plans’ funded status, which are recoverable in customer prices when recognized in net periodic pension and postretirement benefit costs. For further information, see Note 11, Employee Benefits.

Debt issuance costs represents unrecognized debt issuance costs related to debt instruments retired prior to the stipulated maturity date.

Trojan decommissioning activities represents the deferral of ongoing costs and adjustments to the Trojan ARO associated with monitoring spent nuclear fuel at Trojan, net of amortization of customer collections. In addition, proceeds received from the United States Department of Energy (USDOE) for the reimbursement of costs to monitor the ISFSI is deferred and offsets customer collections.

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 2021 ice storm (OPUC Docket UM 2156), which was approved on January 26, 2022 (OPUC Order No. 22-020). On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and would allow PGE full recovery of the deferred amounts with amortization over a seven-year period. The OPUC adopted the stipulation approving amortization of amounts with amortization that began on January 1, 2023.

Power Cost Adjustment Mechanism—For the year ended December 31, 2021, actual NVPC was $62 million above baseline NVPC, and therefore PGE deferred $29 million, which represents 90% of the excess variance expected to be collected from customers for the year ended December 31, 2021. In conjunction with the OPUC’s annual review of the Company’s PCAM filing, parties reached a settlement and on October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to this deferral and would allow PGE full recovery except for $2 million, which was recorded as a charge to earnings. Amortization will occur over a two-year period beginning January 1, 2023. Order 22-440, issued November 8, 2022, adopted the stipulation approving amortization of amounts.

2020 Labor Day wildfire in 2020, the State experienced the most destructive wildfire season 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 December 31, 2022 and December 31, 2021, PGE’s cumulative deferred costs related to the wildfire response was $31 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 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 consolidated statements of income. On July 27, 2022, PGE made a request for amortization with the OPUC that would allow collection in customer prices over a seven-year amortization period beginning November 1, 2022. On October 24, 2022, PGE and parties submitted a stipulation with the OPUC reflecting an agreement that resolved all matters related to 2021 under this deferral and would allow PGE full recovery of the amounts deferred as of September 30, 2022, with amortization over a seven-year period. Order 22-435, issued November 3, 2022, adopted the stipulation approving amortization of amounts with amortization that began on January 1, 2023.

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 which may qualify for deferral under Docket UM2114, 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 to 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 December 31, 2022 and December 31, 2021, PGE’s deferred balance was $22 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 in 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. PGE filed a request for amortization of deferred amounts on December 16, 2022, which reflected a $12 million adjustment primarily related to bad debt write-offs being lower than estimated. The request for amortization has an effective date of April 1, 2023, and is still pending the approval of the Commission. 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 and the application of an 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.

Wildfire mitigation represents incremental costs and investments made by PGE under 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 execute a wildfire protection plan, in which reasonable costs can be recovered through prices to 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 that exceed the amount granted in base rates. As of December 31, 2022, PGE’s deferred balance related to wildfire mitigation was $28 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, or application of a

potential 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.

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

Deferred income taxes represents income tax benefits primarily from property-related timing differences that will be refunded to customers when the temporary differences reverse. Substantially all of the amounts deferred are subject to tax normalization rules that require that the impact to the results of operations of reversing the excess deferred income tax balance cannot occur more rapidly than over the book life of the related assets. The Company uses the average rate assumption method to account for the refund to customers. For further information, see Note 12, Income Taxes.

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

Balance Sheet Components Schedule of Other Asssets and Other Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Other current assets:
Prepaid Expense, Current	$ 69	$ 66
Margin Deposit Assets	116	37
Assets from price risk management activities	313	102
Other Assets, Current	498	205
Accrued expenses and other current liabilities:
Regulatory Liability, Current	234	106
Accrued employee compensation and benefits	66	67
Accrued interest payable	31	29
Dividends payable	42	40
Taxes Payable, Current	29	46
Derivative, Collateral, Obligation to Return Cash	140	58
Other	99	111
Other Liabilities, Current	$ 641	$ 457

Basis of Presentation Basis of Presentation (Policies)	12 Months Ended
Basis of Presentation Basis of Presentation (Policies)	Dec. 31, 2022
Basis of Presentation [Abstract]
Consolidation, Policy [Policy Text Block]	The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 18, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated.

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

12 Months Ended

Dec. 31, 2022

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

Share-based Payment Arrangement, Restricted Stock Unit, Activity [Table Text Block]

Pursuant to the Portland General Electric Company Stock Incentive Plan as amended and restated effective February 13, 2018 (the Plan), the Company may grant a variety of equity-based awards, including restricted stock units (RSUs) with time-based vesting conditions (time-based RSUs) and performance-based vesting conditions (performance-based RSUs), to non-employee directors, officers, or certain key employees. RSU activity is summarized in the following table:


	Units	Weighted Average Grant Date Fair Value
Nonvested units as of December 31, 2019	463,390	$	43.52
Granted	202,883	56.45
Forfeited	(17,341)	50.27
Vested	(170,536)	45.67
Nonvested units as of December 31, 2020	478,396	48.00
Granted	318,844	43.01
Forfeited	(9,754)	48.35
Vested	(212,676)	40.33
Nonvested units as of December 31, 2021	574,810	48.07
Granted	271,696	51.29
Forfeited	(76,913)	49.48
Vested	(190,132)	49.11
Nonvested units as of December 31, 2022	579,461	49.23

Schedule of Share-based Payment Award, Stock Options, Valuation Assumptions [Table Text Block]

For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation with the following weighted average assumptions:


	2022					2021					2020
Risk-free interest rate				1.7	%				0.2	%				1.4	%

Expected term (in years)				2.9					2.9					2.9
Volatility	26.4	%	-	37.9	%	26.1	%	-	37.9	%	13.5	%	-	97.3	%

Earnings Per Share

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

Earnings Per Share

EARNINGS PER SHAREBasic earnings per share are computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: i) employee stock purchase plan shares; ii) contingently issuable time-based and performance-based restricted stock units, along with associated DERs; and iii) shares issuable pursuant to the EFSA. See Note 13, Equity-based Plans, for additional information on the EFSA and its impact on earnings per share. Unvested performance-based restricted stock units and associated DERs are included in dilutive potential common shares only after the performance criteria have been met. Anti-dilutive stock awards are excluded from the calculation of diluted earnings per common share.

Net income attributable to PGE common shareholders is the same for both the basic and diluted earnings per share computations. The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):


	Years Ended December 31,
	2022	2021	2020


Weighted average common shares outstanding—basic	89,290	89,481	89,485
Dilutive potential common shares	353	146	160
Weighted average common shares outstanding—diluted	89,643	89,627	89,645

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash flows from operating activities:
Net income	$ 233	$ 244	$ 155
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	417	404	454
Deferred income taxes	6	5	(23)
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	(14)	(17)	(16)
Pension and other postretirement benefits	13	24	22
Other Comprehensive Income (Loss), Defined Benefit Plan, Settlement and Curtailment Gain (Loss), after Tax	(11)	0	0
Decoupling mechanism deferrals, net of amortization	(11)	29	6
(Amortization) Deferral of net benefits due to Tax Reform	0	0	(23)
Share-based Payment Arrangement, Noncash Expense	15	14	11
Increase (Decrease) in Other Operating Liabilities	(5)	(67)	0
Increase (Decrease) in Cash Flow from Deferral of incremental wildfire costs	0	(30)	(15)
2020 Labor Day wildfire earnings test reserve	15	0	0
Increase(Decrease) in Cash Flows from Deferral of wildfire mitigation costs	(28)
Other non-cash income and expenses, net	54	(10)	23
Changes in working capital:
Decrease (increase) in receivables and unbilled revenues	(66)	(64)	(24)
(Increase) in margin deposits	(80)	(29)	8
(Decrease) increase in payables and accrued liabilities	157	61	26
Increase (Decrease) in Contract with Customer, Asset	82	58	0
Other working capital items, net	(22)	(21)	17
Contribution to non-qualified employee benefit trust	(9)	(11)	(11)
Asset Retirement Obligation, Cash Paid to Settle	(27)	(18)	(18)
Other, net	(45)	(40)	(25)
Net cash provided by operating activities	674	532	567
Cash flows from investing activities:
Capital expenditures	(766)	(636)	(784)
Purchases of nuclear decommissioning trust securities	(3)	(10)	(6)
Sales of nuclear decommissioning trust securities	3	12	9
Proceeds from Sale of Property, Plant, and Equipment	13	4	0
Other, net	(5)	(26)	(6)
Net cash used in investing activities	(758)	(656)	(787)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	360	400	549
Payments on long-term debt	0	(160)	(98)
Proceeds from Short-term Debt	0	200	275
Repayments of Short-term Debt	0	(350)	(125)
Proceeds from Other Debt	25	0	0
Dividends paid	(158)	(150)	(140)
Payments for Repurchase of Common Stock	(18)	(12)	0
Other	(12)	(9)	(14)
Net cash used in financing activities	197	(81)	447
(Decrease) increase in cash and cash equivalents	113	(205)	227
Cash and cash equivalents, beginning of year	52	257	30
Cash and cash equivalents, end of year	165	52	257
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	128	120	113
Cash paid for income taxes	37	16	17
Non-cash investing and financing activities:
Accrued capital additions	111	87	72
Accrued dividends payable	$ 42	$ 40	$ 38

Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Long-Term Debt, Unclassified [Abstract]
2023	$ 260
2024	80
2025	0
2026	0
2027	160
Thereafter	3,159
Total long-term debt	$ 3,659	$ 3,299

- Definition

Amount, excluding unamortized premium (discount) and debt issuance cost, of long-term debt. Excludes lease obligation.

+ References + Details

Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Mar. 11, 2020
Debt Instrument [Line Items]
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.09% in 2022 and 4.11% in 2021, due at various dates through 2051	$ 3,280	$ 3,180
Other Loans Payable, Long-Term, Noncurrent	260	0
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033	119	119	$ 119
Total long-term debt	3,659	3,299
Less: Unamortized debt expense	(13)	(14)
Less: current portion of long-term debt	(260)	0
Long-term debt, net of current portion	$ 3,386	$ 3,285
First mortgage Bonds - minimum rate	1.82%
First Mortgage Bonds - maximum rate	6.88%
Debt, Weighted Average Interest Rate	4.09%	4.11%

Contingencies (Details) $ in Millions	12 Months Ended
Contingencies (Details) $ in Millions	Dec. 31, 2022 USD ($) name
Loss Contingencies [Line Items]
Site Contingency, Names of Other Potentially Responsible Parties \| name	100
Litigation Settlement, Expense	$ 115
Loss Contingency, Range of Possible Loss, Maximum	1,700
Loss Contingency, Range of Possible Loss, Portion Not Accrued	500
lower range of costs	1,900
upper range of costs	3,500
Payments for Environmental Liabilities	6
EPA Investigation of Portland Harbor [Member]
Loss Contingencies [Line Items]
Loss Contingency, Damages Sought, Value	$ 1,200

Leases (Notes)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Lessee, Finance Leases [Text Block]

LEASESPGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability.

Operating leases reflect lease expense on a straight-line basis, while finance leases result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes.

PGE does not record leases with a term of 12-months or less in the consolidated balance sheets. Total short-term lease costs as of December 31, 2022 are immaterial. PGE has lease agreements with lease and non-lease components, which are accounted for separately.

The Company’s leases relate primarily to the use of land, support facilities, gas storage, energy storage equipment, and power purchase agreements that rely on identified plant. Variable payments are generally related to gas storage and power purchase agreements for components dependent upon variable factors, such as energy production and property taxes, and are not included in the determination of the present value of lease payments.

The components of lease cost were as follows (in millions):


	2022		2021

Operating lease cost	$	4	$	8
Finance lease cost:
Amortization of right-of-use assets	$	14	$	7
Interest on lease liabilities	15		11
Total finance lease cost	$	29	$	18

Variable lease cost	$	31	$	24

Supplemental information related to amounts and presentation of leases in the consolidated balance sheets is presented below (in millions):


	Balance Sheet Classification	As of December 31,
		2022		2021
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	22	$	25

Current liabilities	Accrued expenses and other current liabilities	$	4	$	4
Noncurrent liabilities	Other noncurrent liabilities	18		22
Total operating lease liabilities *		$	22	$	26
Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	305	$	291

Current liabilities	Current portion of finance lease obligations	$	20	$	20
Noncurrent liabilities	Finance lease obligations, net of current portion	294		273
Total finance lease liabilities *		$	314	$	293

* Included in lease liabilities are $186 million and $161 million related to power purchase agreements for the years ended December 31, 2022 and 2021, respectively.

Lease term and discount rates were as follows:


	December 31, 2022		December 31, 2021
Weighted Average Remaining Lease Term (in years)
Operating leases	44		40
Finance leases	22		23
Weighted Average Discount Rate
Operating leases	3.9	%	3.8	%
Finance leases	4.9	%	5.0	%

PGE’s gas storage finance lease contains five 10-year renewal periods which have not been included in the finance lease obligation.

As of December 31, 2022, maturities of lease liabilities were as follows (in millions):


	Operating Leases		Finance Leases

2023	$	4	$	20
2024	3		20
2025	1		27
2026	1		27
2027	1		27
Thereafter	42		382
Total lease payments	52		503
Less imputed interest	(30)		(189)
Total	$	22	$	314

Supplemental cash flow information related to leases for the years indicated was as follows (in millions):


	2022		2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	4	$	8	$	8
Operating cash flows from finance leases	15		11		10
Financing cash flows from finance leases	7		6		$	6
Right-of-use assets obtained in leasing arrangements:
Operating leases	$	—	$	(12)	$	—
Finance leases	29		153		—

Income Taxes Income Taxes (Tables)

12 Months Ended

Dec. 31, 2022

Income Taxes [Abstract]

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

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


	Years Ended December 31,
	2022		2021		2020
Current:
Federal	$	9	$	4	$	6
State and local	24		14		17
	33		18		23
Deferred:
Federal	(1)		—		(22)
State and local	7		5		(1)
	6		5		(23)
Income tax expense	$	39	$	23	$	—

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

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


	Years Ended December 31,
	2022		2021		2020
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
Federal tax credits (1)	(11.6)		(11.9)		(20.5)

State and local taxes, net of federal tax benefit	8.8		8.9		10.1
Flow through depreciation and cost basis differences	0.8		(0.2)		(4.9)
Local tax flow-through adjustment	—		(3.2)		—
Reversal of excess deferred income tax (2)	(4.5)		(4.8)		(4.7)
Other	(0.2)		(1.2)		(1.0)
Effective tax rate	14.3	%	8.6	%	—	%

(1) Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities. The federal PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. The PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation will end at various dates through 2030.

(2) The majority of excess deferred income taxes related to remeasurement under the TCJA is subject to IRS normalization rules and will be reversed over the remaining regulatory life of the assets using the average rate assumption method.

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

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


	As of December 31,
	2022		2021
Deferred income tax assets:
Employee benefits	$	99	$	114
Regulatory liabilities	75		39
Tax credits	102		98

Total deferred income tax assets	276		251
Deferred income tax liabilities:
Depreciation and amortization	547		536
Price risk management	54		—
Regulatory assets	101		121
Other	13		7
Total deferred income tax liabilities	715		664
Deferred income tax liability, net	$	439	$	413

Price Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
Price Risk Management (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral	$ 5	$ 3
Net gain or loss recognized in the statement of income offset by regulatory accounting	(188)	(119)	$ 12
Margin Deposit Assets	0
Right to reclaim cash collateral	0	0
Derivative, Collateral, Obligation to Return Cash	140	58
Derivative, Collateral, Obligation to Return Securities	16
Derivative Asset, Fair Value, Amount Offset Against Collateral	156
Credit Risk Contract [Member]
Derivative [Line Items]
Derivative, Net Liability Position, Aggregate Fair Value	183
Collateral Already Posted, Aggregate Fair Value	130
Collateral Aggregate Fair Value	27
Right to reclaim cash collateral	$ 109
Letter of Credit [Member] \| Credit Risk Contract [Member]
Derivative [Line Items]
Collateral posted as letter of credit	21 million
Electricity [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		1
Natural Gas [Member]
Derivative [Line Items]
Derivative Liability, Fair Value, Amount Not Offset Against Collateral		$ 2

Commitments and Guarantees (Policies)	12 Months Ended
Commitments and Guarantees (Policies)	Dec. 31, 2022
Commitments and Contingencies Disclosure [Abstract]
Minimum Guarantees, Policy [Policy Text Block]	PGE enters into financial agreements, 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.

Revenue Recogniton Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2022

Revenue Recognition [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table presents PGE’s revenue, disaggregated by customer type (in millions):


	Year Ended December 31,
	2022		2021		2020
Retail:
Residential	$	1,158	$	1,118	$	1,030
Commercial	723		690		616
Industrial	289		250		218
Direct access customers	35		47		46
Subtotal	2,205		2,105		1,910
Alternative revenue programs, net of amortization	11		(29)		(6)
Other accrued revenues, net (1)	7		2		28
Total retail revenues	2,223		2,078		1,932
Wholesale revenues (2)	363		255		162
Other operating revenues	61		63		51
Total revenues	$	2,647	$	2,396	$	2,145

(1) Amount for the year ended December 31,2020 is primarily comprised of $24 million of amortization, including interest, related to the net tax benefits due to the change in corporate tax rate under the United States Tax Cuts and Jobs Act of 2017 (TCJA).

(2) Wholesale revenues include $133 million, $63 million, and $65 million related to physical electricity commodity contract derivative settlements for the years ended December 31, 2022, 2021, and 2020, respectively. Price risk management derivative activities are included within Total revenues but do not represent revenues from contracts with customers as defined by GAAP, pursuant to Topic 606. For further information, see Note 6, Risk Management.

Employee Benefits Schedule of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 65
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	60
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	61
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	61
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	58
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	284
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	59
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	54
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	54
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	54
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	53
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	262
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	3
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	14
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	2
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	2
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	$ 8

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 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 are as follows by level within the fair value hierarchy (in millions):


	December 31, 2022
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		11		11
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	3		—		—		—		3



Price risk management activities: (1) (4)
Electricity	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:

Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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 regarding price risk management derivatives, see Note 6, Risk Management.


	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 measured at NAV (2)	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4

Debt securities—domestic government	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 regarding price risk management derivatives, see Note 6, Risk Management.

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


	Level 1		Level 2		Level 3		Other *		Total
As of December 31, 2022:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	16	$	—	$	—	$	—	$	16




Investments measured at NAV:
Money market funds	—		—		—		4		4
Collective trust funds	—		—		—		525		525
Private equity funds	—		—		—		2		2

	$	16	$	—	$	—	$	531	$	547
Other Postretirement Benefit Plans assets:
Money market funds	$	4	$	—	$	—	$	—	$	4
Equity securities:
Domestic	—		2		—		—		2
International	3		—		—		—		3
Debt securities—Domestic	—		4		—		—		4
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		3		3
	$	7	$	6	$	—	$	8	$	21
As of December 31, 2021:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	25	$	—	$	—	$	—	$	25




Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		764		764
Private equity funds	—		—		—		5		5
	$	25	$	—	$	—	$	775	$	800
Other Postretirement Benefit Plans assets:
Money market funds	$	3	$	—	$	—	$	—	$	3
Equity securities:
Domestic	—		4		—		—		4
International	10		—		—		—		10
Debt securities—Domestic government	—		6		—		—		6
Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		8		8

	$	13	$	10	$	—	$	14	$	37

*Assets are measured at NAV as a practical expedient and not subject to hierarchy level classification disclosure. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements.

Fair Value Option, Disclosures [Table Text Block]

Quantitative information regarding the significant, unobservable inputs used in the measurement of Level 3 assets and liabilities from price risk management activities is presented below:


						Significant	Price per Unit
	Fair Value				Valuation	Unobservable					Weighted
Commodity Contracts	Assets		Liabilities		Technique	Input	Low		High		Average
	(in millions)
As of December 31, 2022:
Electricity physical forwards	$	52	$	93	Discounted cash flow	Electricity forward price (per MWh)	$	35.00	$	270.00	$	101.27
Natural gas financial swaps	6		8		Discounted cash flow	Natural gas forward price (per Dth)	2.71		24.71		4.42
Electricity financial futures	11		—		Discounted cash flow	Electricity forward price (per MWh)	54.17		143.70		104.21
	$	69	$	101
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 Dth)	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]


	Years Ended December 31,
	2022		2021
Net liabilities from price risk management activities as of beginning of year	$	85	$	137
Net realized and unrealized losses/(gains) *	(84)		(50)




Net transfers from Level 3 to Level 2	31		(2)
Net liabilities from price risk management activities as of end of year	$	32	$	85
Level 3 net unrealized losses/(gains) that have been fully offset by the effect of regulatory accounting	$	(82)	$	(55)

* Includes $2 million in net realized gains in 2022 and $5 million in 2021.

Income Taxes

12 Months Ended

Dec. 31, 2022

Income Taxes Note [Abstract]

Income Taxes

INCOME TAXES

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


	Years Ended December 31,
	2022		2021		2020
Current:
Federal	$	9	$	4	$	6
State and local	24		14		17
	33		18		23
Deferred:
Federal	(1)		—		(22)
State and local	7		5		(1)
	6		5		(23)
Income tax expense	$	39	$	23	$	—

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


	Years Ended December 31,
	2022		2021		2020
Federal statutory tax rate	21.0	%	21.0	%	21.0	%
Federal tax credits (1)	(11.6)		(11.9)		(20.5)

State and local taxes, net of federal tax benefit	8.8		8.9		10.1
Flow through depreciation and cost basis differences	0.8		(0.2)		(4.9)
Local tax flow-through adjustment	—		(3.2)		—
Reversal of excess deferred income tax (2)	(4.5)		(4.8)		(4.7)
Other	(0.2)		(1.2)		(1.0)
Effective tax rate	14.3	%	8.6	%	—	%

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


	As of December 31,
	2022		2021
Deferred income tax assets:
Employee benefits	$	99	$	114
Regulatory liabilities	75		39
Tax credits	102		98

Total deferred income tax assets	276		251
Deferred income tax liabilities:
Depreciation and amortization	547		536
Price risk management	54		—
Regulatory assets	101		121
Other	13		7
Total deferred income tax liabilities	715		664
Deferred income tax liability, net	$	439	$	413

As of December 31, 2022, PGE has federal credit carryforwards of $102 million, consisting 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 December 31, 2022 and 2021 will be realized; accordingly, no valuation allowance has been recorded. As of December 31, 2022, and 2021, PGE had no material unrecognized tax benefits.

PGE and its subsidiaries file a consolidated federal income tax return. The Company also files income tax returns in the states of Oregon, California, and Montana, and in certain local jurisdictions. The Company files in other states to maintain compliance with remote worker rules and regulations. These additional state filings are not significant to the consolidated financial statements. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2010 and all issues were resolved related to those years. The Company does not believe that any open tax years for federal or state income taxes could result in any adjustments that would be significant to the consolidated financial statements.

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 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 consolidated statements of income for the year ended December 31, 2021.

Inflation Reduction Act

The Inflation Reduction Act of 2022 (“IRA”) was signed into law by President Biden on August 16, 2022. There is no immediate impact of the IRA to the year ended December 31, 2022. PGE will be closely monitoring guidance from the IRS regarding the enhanced energy credits available under the IRA. PGE expects to be able to generate and utilize increased energy credits in future periods, and as such, continues to hold that it is more likely than not that the deferred income tax assets will be realized.

- Definition

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

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section 50
-Paragraph 21
-URI https://asc.fasb.org/extlink&oid=121826272&loc=d3e32857-109319

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 740
-SubTopic 10
-Section S99
-Paragraph 2
-Subparagraph (SAB Topic 11.C)
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+ Details

Revenue Recogniton Revenue Recognition

12 Months Ended

Dec. 31, 2022

Revenue Recognition [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

Disaggregated Revenue

The following table presents PGE’s revenue, disaggregated by customer type (in millions):


	Year Ended December 31,
	2022		2021		2020
Retail:
Residential	$	1,158	$	1,118	$	1,030
Commercial	723		690		616
Industrial	289		250		218
Direct access customers	35		47		46
Subtotal	2,205		2,105		1,910
Alternative revenue programs, net of amortization	11		(29)		(6)
Other accrued revenues, net (1)	7		2		28
Total retail revenues	2,223		2,078		1,932
Wholesale revenues (2)	363		255		162
Other operating revenues	61		63		51
Total revenues	$	2,647	$	2,396	$	2,145

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single family housing, multiple family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers 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 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 throughout the month.

PGE’s obligation to sell electricity to retail customers generally represents a single performance obligation representing a series of distinct services that are substantially the same and have the same pattern of transfer to the customer that is satisfied over time as customers simultaneously receive and consume the benefits provided. PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.

Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the consolidated statements of income.

Wholesale Revenues

PGE participates in the wholesale electricity marketplace in order to balance its supply of power to meet the needs of its retail customers. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow the Company to purchase and sell electricity within the region depending upon the relative price and availability of power, hydro, solar, and wind conditions, and daily and seasonal retail demand.

PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

Other Operating Revenues

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 resale, excess fuel sales, utility pole attachment revenues, and other electric services provided to customers.

- Definition

The entire disclosure of revenue from contract with customer to transfer good or service and to transfer nonfinancial asset. Includes, but is not limited to, disaggregation of revenue, credit loss recognized from contract with customer, judgment and change in judgment related to contract with customer, and asset recognized from cost incurred to obtain or fulfill contract with customer. Excludes insurance and lease contracts.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-URI https://asc.fasb.org/topic&trid=49130388

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
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-Paragraph 15
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130558-203045

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 606
-SubTopic 10
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-Paragraph 12
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=126920106&loc=SL49130554-203045

+ Details

Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 2,042
PGE Share of Output	8.60%
PGE Share of Capacity \| MW	163
commitment costs	$ 45	$ 26	$ 25
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 421
PGE Share of Output	18.80%
PGE Share of Capacity \| MW	113
commitment costs	$ 12	$ 13	$ 23

Employee Benefits

12 Months Ended

Dec. 31, 2022

Employee Benefits [Abstract]

Employee Benefits

EMPLOYEE BENEFITS

Pension and Other Postretirement Plans

Defined Benefit Pension Plan—PGE sponsors a non-contributory defined benefit pension plan, which is closed to new employees.

The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate.

As expected, PGE contributed no additional funds to the pension plan in both 2022 and 2021. PGE does not expect to contribute to the pension plan in 2023.

Other Postretirement Benefits—PGE offers non-contributory postretirement health and life insurance plans, and provides health reimbursement arrangements (HRAs) to its employees (collectively, “Other Postretirement Benefits” in the following tables). PGE’s obligation pursuant to the postretirement health plan is limited by establishing a maximum benefit per employee with any additional cost the responsibility of the employee.

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

In 2022, PGE executed a buyout of the Non-represented Retiree Medical Plan, resulting in an $11 million settlement gain, which has been recorded in Miscellaneous income (expense), net on the consolidated statement of income.

Non-Qualified Benefit Plan—The NQBP in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also includes pension make-up benefits for employees that participate in the Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide partial funding for the future requirements of these plans. The assets of such trust are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bonds, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the NQBP is December 31. For further information regarding these trust investments, see Note 5, Fair Value of Financial Instruments.

Other NQBP—In addition to the NQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. PGE holds investments in a NQBP trust that are intended to be a funding source for these plans.

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


	2022						2021
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust assets	$	19	$	19	$	38	$	21	$	24	$	45
Non-qualified benefit plan liabilities *	16		67		83		25		70		95

* For the NQBP, excludes the current portion of $2 million in 2022 and 2021, which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets.

Investment Policy and Asset Allocation—The Finance Committee of the PGE Board of Directors appoints an Investment Committee, which is comprised of certain members of management from the Company, and establishes the Company’s asset allocation. The Investment Committee is then responsible for the implementation of the asset allocation and oversight of the benefit plan investments. The Company’s investment strategy for its pension and other postretirement plans is to balance risk and return through a diversified portfolio of equity securities, fixed income securities, and other alternative investments. Asset classes are regularly rebalanced to ensure asset allocations remain within prescribed parameters.

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


	As of December 31,
	2022				2021
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	55	%	55	%	61	%	60	%
Debt securities	45		45		39		40
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	39	%	40	%	59	%	57	%
Debt securities	61		60		41		43
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	7	%	5	%	8	%	7	%
Debt securities	9		11		13		14
Insurance contracts	84		84		79		79
Total	100	%	100	%	100	%	100	%

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

The Company’s overall investment strategy is to meet the goals and objectives of the individual plans through a wide diversification of asset types, fund strategies, and fund managers.

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


	Level 1		Level 2		Level 3		Other *		Total
As of December 31, 2022:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	16	$	—	$	—	$	—	$	16




Investments measured at NAV:
Money market funds	—		—		—		4		4
Collective trust funds	—		—		—		525		525
Private equity funds	—		—		—		2		2

	$	16	$	—	$	—	$	531	$	547
Other Postretirement Benefit Plans assets:
Money market funds	$	4	$	—	$	—	$	—	$	4
Equity securities:
Domestic	—		2		—		—		2
International	3		—		—		—		3
Debt securities—Domestic	—		4		—		—		4
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		3		3
	$	7	$	6	$	—	$	8	$	21
As of December 31, 2021:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	25	$	—	$	—	$	—	$	25




Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		764		764
Private equity funds	—		—		—		5		5
	$	25	$	—	$	—	$	775	$	800
Other Postretirement Benefit Plans assets:
Money market funds	$	3	$	—	$	—	$	—	$	3
Equity securities:
Domestic	—		4		—		—		4
International	10		—		—		—		10
Debt securities—Domestic government	—		6		—		—		6
Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		8		8

	$	13	$	10	$	—	$	14	$	37

An overview of the identification of Level 1, 2, and 3 financial instruments is provided in Note 5, Fair Value of Financial Instruments. The following discussion provides information regarding the methods used in valuation of the various asset class investments held in the pension and other postretirement benefit plan trusts.

Money market funds—PGE invests in money market funds that seek to maintain a stable NAV. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.

Equity securities—Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace.

Debt Securities—Debt security investment funds are classified as Level 2 securities as pricing for underlying securities are determined by evaluating pricing data, such as broker quotes for similar securities, adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, if applicable.

Collective trust funds—Domestic and international mutual fund assets and debt security assets, including municipal debt and corporate credit securities, mortgage-backed securities, and asset back securities assets, are included in commingled trusts or separately managed accounts. The Company believes the redemption value of the collective trust funds are likely to be the fair value, which is represented by the net asset value as a practical expedient. The funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.

Private equity funds—PGE invests in a combination of primary and secondary fund-of-funds, which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.

The following tables provide certain information with respect to the Company’s defined benefit pension plan, other postretirement benefits, and NQBP as of and for the years ended December 31, 2022 and 2021. Information related to the Other NQBP is not included in the following tables (dollars in millions):


	Defined Benefit Pension Plan				Other Postretirement Benefits				Non-Qualified Benefit Plans
	2022		2021		2022		2021		2022		2021
Benefit obligation:
As of January 1	$	972	$	1,010	$	71	$	76	$	27	$	28
Service cost	17		19		1		2		—		—
Interest cost	28		27		2		2		1		1

Actuarial gain	(255)		(26)		(15)		(5)		(7)		—

Benefit payments	(69)		(47)		(4)		(5)		(3)		(2)
Administrative expenses	(3)		(3)		—		—		—		—
Plan amendment	5		(8)		1		1		—		—
Plan settlements	—		—		(13)		—		—		—
As of December 31	$	695	$	972	$	43	$	71	$	18	$	27
Fair value of plan assets:
As of January 1	$	800	$	753	$	37	$	35	$	21	$	19
Actual return on plan assets	(181)		97		(6)		4		(2)		1
Company contributions	—		—		7		3		3		3

Benefit payments	(69)		(47)		(4)		(5)		(3)		(2)
Administrative expenses	(3)		(3)		—		—		—		—
Plan settlements	—		—		(13)		—		—		—
As of December 31	$	547	$	800	$	21	$	37	$	19	$	21
Unfunded position as of December 31	$	(148)	$	(172)	$	(22)	$	(34)	$	1	$	(6)
Accumulated benefit plan obligation as of December 31	$	656	$	885	N/A		N/A		$	17	$	23
Classification in consolidated balance sheet:
Noncurrent asset	$	—	$	—	$	—	$	—	$	19	$	21
Current liability	—		—		(1)		—		(2)		(2)
Noncurrent liability	(148)		(172)		(21)		(34)		(16)		(25)
Net asset (liability)	$	(148)	$	(172)	$	(22)	$	(34)	$	1	$	(6)
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	(28)	$	(78)	$	(8)	$	(7)	$	(7)	$	(1)
Net settlement gain	—		—		11		—		—		—
Net prior service credit	5		(9)		—		—		—		—
Amortization of net actuarial loss	(15)		(22)		—		—		(1)		(1)
Amortization of prior service credit	2		—		—		1		—		—
	$	(36)	$	(109)	$	3	$	(6)	$	(8)	$	(2)
Amounts included in AOCL: *
Net actuarial loss (gain)	$	96	$	139	$	(7)	$	(3)	$	6	$	14
Prior service cost	(1)		(8)		—		(7)		—		—
	$	95	$	131	$	(7)	$	(10)	$	6	$	14

* Amounts included in AOCL related to the Company’s defined benefit pension plan and other postretirement benefits are classified as Regulatory assets or liabilities as future recoverability is expected from retail customers.

Significant actuarial gains (losses) experienced that resulted in changes in projected benefit obligation included the following:

•For the defined benefit pension plan, actuarial gains and losses due to demographic experience, including assumption changes, were gains of $255 million and $26 million, and the changes between actual and expected return on plan assets were a loss of $227 million and a gain of $52 million, for the years ended December 31, 2022 and 2021, respectively.

•For the other postretirement benefits, actuarial gains and losses due to demographic experience, including assumption changes, were gains of $15 million and $5 million, and the changes between actual and expected return on plan assets were a loss of $6 million and a gain of $2 million, for each of the years ended December 31, 2022 and 2021, respectively.

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


	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2022		2021		2020		2022		2021		2020		2022		2021		2020
Service cost	$	17	$	19	$	17	$	1	$	2	$	2	$	—	$	—	$	—
Interest cost on benefit obligation	28		27		31		2		2		2		1		1		1
Expected return on plan assets	(46)		(45)		(44)		(2)		(2)		(2)		—		—		—

Amortization of prior service credit	(2)		—		—		—		(1)		(1)		—		—		—
Amortization of net actuarial loss	15		22		17		—		—		—		1		1		1
Settlement gain	—		—		—		(11)		—		—		—		—		—
Net periodic benefit cost	$	12	$	23	$	21	$	(10)	$	1	$	1	$	2	$	2	$	2

The portion of non-service costs attributable to expense related to the pension and other postretirement benefit plans, is classified as Miscellaneous income (expense), net within Other income, net on the Company’s consolidated statements of income. A portion of current period non-service costs attributable capital projects is recorded as a regulatory asset and amortized to Miscellaneous income (expense), net over time.

The following assumptions were used in determining benefit obligations and net period benefit costs:


	Defined Benefit Pension Plan				Other Postretirement Benefits				Non-Qualified Benefit Plans
	2022		2021		2022		2021			2022		2021
Assumptions used to determine benefit obligations:
Discount rate	5.42	%	2.92	%	5.47% -		2.75% -			5.42	%	2.92	%
					5.51	%	3.11	%
Rate of compensation increase	4.21	%	4.26	%	4.04	%	4.13	%		5.10	%	4.10	%

Assumptions used to determine net periodic benefit cost:
Discount rate	2.92	%	2.64	%	2.75% -		2.22% -			2.92	%	2.64	%
					3.11	%	2.92	%
Rate of compensation increase	4.26	%	3.65	%	4.13	%	4.58	%		4.10	%	4.10	%
Long-term rate of return on plan assets	6.75	%	6.88	%	4.83	%	5.04	%		N/A		N/A

As of December 31, 2022, there are no liabilities with sensitivity to health care cost trend rates.

Changes in actuarial assumptions can also have a material effect on net periodic pension expense. A 0.50% reduction in the expected long-term rate of return on plan assets, or a 0.50% reduction in the discount rate, would have the effect of increasing the 2022 net periodic pension expense by approximately $4 million and $6 million, respectively.

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


	Payments Due
	2023		2024		2025		2026		2027		2028 - 2032
Defined benefit pension plan	$	59	$	54	$	54	$	54	$	53	$	262
Other postretirement benefits	4		4		5		5		3		14
Non-qualified benefit plans	2		2		2		2		2		8
Total	$	65	$	60	$	61	$	61	$	58	$	284

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

401(k) Retirement Savings Plan

PGE sponsors a 401(k) Plan that covers substantially all employees. For eligible employees who are covered by PGE’s defined benefit pension plan, the Company matches employee contributions to the 401(k) Plan up to 6% of the employee’s base pay. For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company contributes 5% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan, and also matches employee contributions up to 5% of the employee’s base pay.

For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company contributes an additional 1% of the employee’s base salary, whether or not the employee contributes to the 401(k) Plan.

All contributions are invested in accordance with employees’ elections, limited to investment options available under the 401(k) Plan. PGE made contributions to employee accounts of $29 million in 2022, and $26 million in 2021 and 2020.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 55
-Paragraph 17
-URI https://asc.fasb.org/extlink&oid=123450688&loc=d3e4179-114921

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section S99
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=21916913&loc=d3e273930-122802

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (o)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (p)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 70
-Section 50
-Paragraph 1
-URI https://asc.fasb.org/extlink&oid=49170846&loc=d3e28014-114942

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-URI https://asc.fasb.org/topic&trid=2235017

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 60
-Section 50
-Paragraph 3
-Subparagraph (c)
-URI https://asc.fasb.org/extlink&oid=6414203&loc=d3e39689-114964

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (q)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (l)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 715
-SubTopic 20
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-URI https://asc.fasb.org/extlink&oid=123447040&loc=d3e1928-114920

+ Details

Stock-based Compensation Expense Restricted and Performance Stock Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Outstanding, Units	574,810	478,396	463,390
Outstanding, Weighted Average Grant Date Fair Value	$ 48.07	$ 48.00	$ 43.52
Granted, Units	271,696	318,844	202,883
Granted, Weighted Average Grant Date Fair Value	$ 51.29	$ 43.01	$ 56.45
Forfeited, Units	(76,913)	(9,754)	(17,341)
Forfeited, Weighted Average Grant Date Fair Value	$ 49.48	$ 48.35	$ 50.27
Vested, Units	(190,132)	(212,676)	(170,536)
Vested, Weighted Average Grant Date Fair Value	$ 49.11	$ 40.33	$ 45.67
Outstanding, Units	579,461	574,810	478,396
Outstanding, Weighted Average Grant Date Fair Value	$ 49.23	$ 48.07	$ 48.00

Leases Lease Term and Discount Rate (Details)	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	44 years	40 years
Finance Lease, Weighted Average Remaining Lease Term	22 years	23 years
Operating Lease, Weighted Average Discount Rate, Percent	3.90%	3.80%
Finance Lease, Weighted Average Discount Rate, Percent	4.90%	5.00%

Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	$ 150	$ 44
Domestic government, Debt securities	19	19
Corporate debt securities held in decommissioning trust assets	9	14
Money market funds	11	14
Fair Value - Money market funds	1	1
Domestic Equity Securities	3	4
Debt securities - domestic government	3	4
Electricity	156	17
Natural gas	231	120
Financial Instruments, Owned, at Fair Value	11	14
Assets, Fair Value Disclosure	583	237
Liabilities from price risk management activities: [Abstract]
Electricity	146	123
Natural gas	47	14
Liabilities, Fair Value Disclosure	193	137
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	150	44
Domestic government, Debt securities	9	9
Corporate debt securities held in decommissioning trust assets	0	0
Fair Value - Money market funds	1	1
Domestic Equity Securities	3	4
Debt securities - domestic government	3	4
Electricity	0	0
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	166	62
Liabilities from price risk management activities: [Abstract]
Electricity	0	0
Natural gas	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Domestic government, Debt securities	10	10
Corporate debt securities held in decommissioning trust assets	9	14
Fair Value - Money market funds	0	0
Domestic Equity Securities	0	0
Debt securities - domestic government	0	0
Electricity	93	16
Natural gas	225	115
Financial Instruments, Owned, at Fair Value	337	155
Liabilities from price risk management activities: [Abstract]
Electricity	53	33
Natural gas	39	13
Liabilities, Fair Value Disclosure	92	46
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	0	0
Domestic government, Debt securities	0	0
Corporate debt securities held in decommissioning trust assets	0	0
Money market funds	0
Fair Value - Money market funds		0
Domestic Equity Securities	0	0
Debt securities - domestic government	0	0
Electricity	63	1
Natural gas	6	5
Financial Instruments, Owned, at Fair Value	69	6
Liabilities from price risk management activities: [Abstract]
Electricity	93	90
Natural gas	8	1
Liabilities, Fair Value Disclosure	101	91
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 31	$ 36

Leases Leases (Policies)	12 Months Ended
Leases Leases (Policies)	Dec. 31, 2022
Leases [Abstract]
Lessee, Leases [Policy Text Block]	PGE determines if an arrangement is a lease at inception and whether the arrangement is classified as an operating or finance lease. At commencement of the lease, PGE records a right-of-use (ROU) asset and lease liability in the consolidated balance sheets based on the present value of lease payments over the term of the arrangement. ROU assets represent the right to use an underlying asset for the lease term and lease liabilities represent PGE's obligation to make lease payments arising from the lease. If the implicit rate is not readily determinable in the contract, PGE uses its incremental borrowing rate based on the information available at commencement date in determining the present value of lease payments. Contract terms may include options to extend or terminate the lease, and, when the Company deems it is reasonably certain that PGE will exercise that option, it is included in the ROU asset and lease liability. Operating leases reflect lease expense on a straight-line basis, while finance leases result in the separate presentation of interest expense on the lease liability and amortization expense of the ROU asset. Any material differences between expense recognition and timing of payments is deferred as a regulatory asset or liability in order to match what is being recovered in customer prices for ratemaking purposes. PGE does not record leases with a term of 12-months or less in the consolidated balance sheets.

Leases Leases (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 12
Operating Lease, Liability	22	$ 26
Operating Lease, Liability, Related to Power Purchase Agreements	186	161
Operating Lease, Liability, Current	4	4
Operating Lease, Liability, Noncurrent	18	$ 22
Lessee, Operating Lease, Liability, Payments, Due	$ 52

Jointly-owned Plant (Details) $ in Millions	Dec. 31, 2022 USD ($)
Jointly-owned Plant [Abstract]
Accrued Capping, Closure, Post-closure and Environmental Costs	$ 13

Employee Benefits Assumptions (Details)	12 Months Ended
Employee Benefits Assumptions (Details)	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.04%	4.13%	4.58%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	4.83%	5.04%
Pension Plan [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.42%	2.92%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.21%	4.26%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.92%	2.64%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	6.75%	6.88%
Other Pension, Postretirement and Supplemental Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.42%	2.92%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	5.10%	4.10%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.92%	2.64%
Maximum [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.51%	3.11%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	3.11%	2.92%
Minimum [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.47%	2.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	2.75%	2.22%

Employee Benefits Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1	$ 2	$ 2
Interest cost on benefit obligation	2	2	2
Expected return on plan assets	(2)	(2)	(2)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	(1)	(1)
Amortization of net actuarial loss	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(11)	0	0
Net periodic benefit cost	(10)	1	1
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	17	19	17
Interest cost on benefit obligation	28	27	31
Expected return on plan assets	(46)	(45)	(44)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	(2)	0	0
Amortization of net actuarial loss	15	22	17
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Net periodic benefit cost	12	23	21
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Expected return on plan assets	0	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of net actuarial loss	1	1	1
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Net periodic benefit cost	$ 2	$ 2	$ 2

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2022

Summary of Significant Accounting Policies [Abstract]

Estimated average service lives [Table Text Block]

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


Generation, excluding thermal:
Hydro			97
Wind			30
Transmission			61
Distribution			51
General			16

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Revision of Estimate	$ 36	$ (14)	$ 17
Asset Retirement Obligation, Accretion Expense	10	10	10
Asset Retirement Obligation, Liabilities Incurred	$ 1	0	3
Document Period End Date	Dec. 31, 2022
Decommissioning Liability, Noncurrent	$ 6
Asset Retirement Obligation, Liabilities Settled	11
Asset Retirement Obligation, Cash Paid to Settle	27	18	$ 18
Recorded Third-Party Environmental Recoveries, Amount	$ 6	$ 5
Asset Retirement Obligations, Significant Changes	13 million
Utility Plant [Domain]
Asset Retirement Obligation, Accretion Expense	$ 3
Asset Retirement Obligation, Period Increase (Decrease)	$ 9

Credit Facilities Schedule of Short term debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Abstract]
Average daily amount of short-term debt outstanding	$ 2	$ 139	$ 131
Weighted daily average interest rate	3.40%	0.90%	1.50%
Maximum amount outstanding during the year	$ 135	$ 230	$ 225

Price Risk Management (Policies)	12 Months Ended
Price Risk Management (Policies)	Dec. 31, 2022
Price Risk Management [Abstract]
Gross Reporting of Positive and Negative Exposures Related to Derivative Instruments [Policy Text Block]	PGE has elected to report positive and negative exposures resulting from derivative instruments pursuant to agreements that meet the definition of a master netting arrangement at gross values on the consolidated balance sheet. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit.

Long term debt (Details) - USD ($) $ in Millions	12 Months Ended
Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Mar. 11, 2020
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt	$ 360	$ 400	$ 549
Long-term Debt, Current Maturities	260	0
Repayments of Long-term Debt	$ 0	$ (160)	$ (98)
Pollution Control Revenue Bonds at 2,125%				$ 98
Pollution Control Revenue Bonds at 2.375%				$ 21

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	$ 1,623	$ 1,466
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	274
Other Investments	$ 150	44
Document Period End Date	Dec. 31, 2022
Letters of Credit Outstanding, Amount	$ 97	$ 18
Public Utilities, Allowance for Funds Used During Construction, Rate	6.50%	6.70%	6.90%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 7	$ 8	$ 8
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	$ 14	$ 17	$ 16
Depreciation expense rate	3.40%	3.40%	3.50%
Amortization of Intangible Assets	$ 58	$ 58	$ 64
Public Utilities, Approved Return on Equity, Percentage	9.50%	9.50%
Regulatory Assets	$ 527	$ 557
Finite-Lived Intangible Assets, Accumulated Amortization	499	446
Future Amortization Expense, Year One	54
Future Amortization Expense, Year Two	49
Future Amortization Expense, Year Three	37
Future Amortization Expense, Year Four	28
Future Amortization Expense, Year Five	23
Power Cost Deadband - Lower Threshold	15
Power Cost Deadband - Upper Threshold	30
Quantifying Misstatement in Current Year Financial Statements, Amount	4,813	4,469
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	4,423	4,146
Asset Retirement Obligation, Cash Paid to Settle	27	18	18
Deferred Purchased Power Costs	23	62
Unbilled Receivables, Current	131	117
Excise Taxes Collected	53	48	$ 46
Letter of Credit [Member]
Property, Plant and Equipment [Line Items]
Letters of Credit Outstanding, Amount	33
Trojan decommissioning [Member]
Property, Plant and Equipment [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	131	90
Asset Retirement Obligation Costs [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	7	43
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Deferred Income Tax Charge [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	194	$ 208
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 0

Price Risk Management (Notes)

12 Months Ended

Dec. 31, 2022

Price Risk Management [Abstract]

Price Risk Management

RISK MANAGEMENT

Price Risk Management

PGE participates in the wholesale marketplace to balance its supply of power, which consists of its own generation combined with wholesale market transactions, to meet the needs of its retail customers, manage risk, and administer the Company’s long-term wholesale contracts. Wholesale market transactions include purchases and sales of both power and fuel resulting from economic dispatch decisions with respect to Company-owned generating resources. 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 consolidated balance sheets, may include forward, future, swap, and option contracts for electricity, natural gas, and foreign currency, with changes in fair value recorded in the consolidated statements of 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 instruments 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):


	As of December 31,
	2022		2021
Current assets:
Commodity contracts:
Electricity	$	112	$	16
Natural gas	201		86
Total current derivative assets(1)	313		102
Noncurrent assets:
Commodity contracts:
Electricity	44		1
Natural gas	30		34
Total noncurrent derivative assets(1)	74		35

Total derivative assets(2)	$	387	$	137
Current liabilities:
Commodity contracts:
Electricity	$	93	$	36
Natural gas	25		11
Total current derivative liabilities	118		47
Noncurrent liabilities:
Commodity contracts:
Electricity	53		87
Natural gas	22		3
Total noncurrent derivative liabilities	75		90

Total derivative liabilities(2)	$	193	$	137

(1)Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the consolidated balance sheets.

(2)As of December 31, 2022 and 2021, no commodity derivative assets or liabilities were designated as hedging instruments.

PGE’s net volumes related to its Assets and Liabilities from price risk management activities resulting from its derivative transactions, which are expected to deliver or settle at various dates through 2035, were as follows (in millions):


	As of December 31,
	2022			2021
Commodity contracts:
Electricity	6		MWh	4		MWh
Natural gas	211		Dth	181		Dth
Foreign currency contracts	$	10	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 at gross values on the consolidated balance sheet. In the case of default on, or termination of, any contract under the master netting arrangements, such agreements provide for the net settlement of all related contractual obligations with a given counterparty through a single payment. These types of transactions may include non-derivative instruments, derivatives qualifying for scope exceptions, receivables and payables arising from settled positions, and other forms of non-cash collateral, such as letters of credit. As of December 31, 2022, gross amounts included as Price risk management liabilities subject to master netting agreements were $5 million, entirely for natural gas, for which PGE has posted no collateral. As of December 31, 2021, gross amounts included as Price risk management liabilities subject to master netting agreements were $3 million, for which PGE has posted no collateral. Of the gross amounts recognized as of 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 Purchased power and fuel in the consolidated statements of income and were as follows (in millions):


	Years Ended December 31,
	2022		2021		2020
Commodity contracts:
Electricity	$	(187)	$	(38)	$	160
Natural Gas	(388)		(177)		(34)
Foreign currency contracts	1		—		(1)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net amounts recognized in Net income, net gains of $188 million, net gains of $119 million, and net losses of $12 million for the years ended December 31, 2022, 2021, and 2020, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized (gains)/losses recorded as of December 31, 2022 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):


	2023		2024		2025		2026		2027		Thereafter		Total
Commodity contracts:
Electricity	$	(19)	$	10	$	21	$	(3)	$	(3)	$	(16)	$	(10)
Natural gas	(177)		(8)		(2)		3		—		—		(184)
Net unrealized (gain)/loss	$	(196)	$	2	$	19	$	—	$	(3)	$	(16)	$	(194)

PGE’s secured and unsecured debt is currently rated at investment grade by Moody’s Investors Service (Moody’s) and S&P Global Ratings (S&P). Should Moody’s and/or S&P reduce their rating on the Company’s unsecured debt to below investment grade, PGE could be subject to requests by certain wholesale counterparties to post additional

performance assurance collateral, in the form of cash or letters of credit, based on total portfolio positions with each of those counterparties. Certain other counterparties would have the right to terminate their agreements with the Company.

The aggregate fair value of derivative instruments with credit-risk-related contingent features that were in a liability position as of December 31, 2022 was $183 million, for which the Company has posted $130 million in collateral, consisting of $21 million of letters of credit and $109 million of cash. If the credit-risk-related contingent features underlying these agreements were triggered as of December 31, 2022, the cash requirement to either post as collateral or settle the instruments immediately would have been $27 million. As of December 31, 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 consolidated balance sheet.

As of December 31, 2022, PGE received from counterparties $156 million in collateral, consisting of $16 million of letters of credit and $140 million of cash. Increases in collateral received from counterparties is due to the increase in PGE’s derivative asset position. The obligation to return cash collateral held for derivative instruments is included in Accrued expenses and other current liabilities on the Company’s 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.

For additional information concerning the determination of fair value for the Company’s Assets and Liabilities from price risk management activities, see Note 5, Fair Value of Financial Instruments.

Balance Sheet Components

12 Months Ended

Dec. 31, 2022

Balance Sheet Components [Abstract]

Balance Sheet Components

BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable, net includes $131 million and $117 million of unbilled revenues as of December 31, 2022 and 2021, respectively. Accounts receivable is net of an allowance for uncollectible accounts of $12 million as of December 31, 2022 and $26 million as of December 31, 2021. The following is the activity in the allowance for uncollectible accounts (in millions):


	Years Ended December 31,
	2022		2021		2020
Balance as of beginning of year	$	26	$	16	$	5
(Decrease)/Increase in provision *	(2)		35		15
Amounts written off, less recoveries	(12)		(25)		(4)
Balance as of end of year	$	12	$	26	$	16

* Pursuant to the Company’s COVID-19 deferral, certain decreases and increases in the provision for bad debt have been deferred as a net Regulatory Asset. Of the amounts recorded as decreases and increases in the provision, reductions of $10 million and increases of $29 million for the years ended December 31, 2022 and December 31, 2021, respectively, have been offset within the COVID-19 Regulatory Asset. See Note 7, Regulatory Assets and Liabilities for more information.

Other Current Assets and Accrued Expenses and Other Current Liabilities

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


	As of December 31,
	2022		2021
Other current assets:
Prepaid expenses	$	69	$	66


Margin deposits	116		37
Assets from price risk management activities	313		102

	$	498	$	205
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	234	$	106
Accrued employee compensation and benefits	66		67
Accrued dividends payable	42		40
Accrued interest payable	31		29
Accrued taxes payable	29		46
Margin deposits from wholesale counterparties	140		58
Other	99		111
	$	641	$	457

Electric Utility Plant, Net

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


	As of December 31,
	2022		2021
Electric utility plant:
Generation	$	4,709	$	4,649
Transmission	1,119		1,012
Distribution	4,813		4,469
General	973		914
Intangible	807		794
Total in service	12,421		11,838
Accumulated depreciation and amortization	(4,423)		(4,146)
Total in service, net	7,998		7,692
Construction work-in-progress	467		313
Electric utility plant, net	$	8,465	$	8,005

Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2022

Balance Sheet Components [Abstract]

SEC Schedule, 12-09, Schedule of Valuation and Qualifying Accounts Disclosure [Text Block]

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


	Years Ended December 31,
	2022		2021		2020
Balance as of beginning of year	$	26	$	16	$	5
(Decrease)/Increase in provision *	(2)		35		15
Amounts written off, less recoveries	(12)		(25)		(4)
Balance as of end of year	$	12	$	26	$	16

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

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


	As of December 31,
	2022		2021
Other current assets:
Prepaid expenses	$	69	$	66


Margin deposits	116		37
Assets from price risk management activities	313		102

	$	498	$	205
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	234	$	106
Accrued employee compensation and benefits	66		67
Accrued dividends payable	42		40
Accrued interest payable	31		29
Accrued taxes payable	29		46
Margin deposits from wholesale counterparties	140		58
Other	99		111
	$	641	$	457

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

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


	As of December 31,
	2022		2021
Electric utility plant:
Generation	$	4,709	$	4,649
Transmission	1,119		1,012
Distribution	4,813		4,469
General	973		914
Intangible	807		794
Total in service	12,421		11,838
Accumulated depreciation and amortization	(4,423)		(4,146)
Total in service, net	7,998		7,692
Construction work-in-progress	467		313
Electric utility plant, net	$	8,465	$	8,005

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Net income	$ 233	$ 244	$ 155
Other comprehensive income (loss)- Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in 2021, $1 million in 2020, and an immaterial amount in 2019	6	1	(1)
Comprehensive income	$ 239	$ 245	$ 154

- Definition

Amount after tax of increase (decrease) in equity from transactions and other events and circumstances from net income and other comprehensive income. Excludes changes in equity resulting from investments by owners and distributions to owners.

+ References + Details

- Definition

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

+ References

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+ Details

Commitments and Guarantees (Details) $ in Millions	Dec. 31, 2022 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 12

Commitments and Guarantees

12 Months Ended

Dec. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Commitments and Guarantees [Text Block]

COMMITMENTS AND GUARANTEES

Purchase Commitments

As of December 31, 2022, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):


	Payments Due
	2023		2024		2025		2026		2027		Thereafter		Total
Capital and other purchase commitments	$	239	$	70	$	36	$	5	$	2	$	43	$	395
Purchased power and fuel:
Electricity purchases	457		449		428		303		309		3,653		5,599
Capacity contracts	17		17		20		5		5		69		133
Public utility districts	12		12		11		10		9		23		77
Natural gas	158		43		38		37		30		202		508
Coal and transportation	27		27		27		—		—		—		81
Total	$	910	$	618	$	560	$	360	$	355	$	3,990	$	6,793

Capital and other purchase commitments—Certain commitments have been made for 2023 and beyond that include those related to hydro licenses, upgrades to generation, distribution, and transmission facilities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges.

Electricity purchases and Capacity contracts—PGE has power purchase agreements with counterparties, which expire at varying dates through 2053, and power capacity contracts through 2051. Expenses associated with these commitments are recorded in purchased power and fuel on the Company’s Consolidated Statements of Income.

Public utility districts—PGE has long-term power purchase agreements with certain public utility districts (PUDs) in the state of Washington:

•Grant County PUD for the Priest Rapids and Wanapum Hydroelectric Projects, and

•Douglas County PUD for the Wells Hydroelectric Project.

Under the Grant County agreements, the Company is required to pay its proportionate share of the operating and debt service costs of the hydroelectric projects whether they are operable or not. Under the Douglas County agreement, the Company is required to make monthly payments for capacity that will not vary with annual project generation provided to PGE. The Company has estimated the capacity payments, which are subject to annual adjustments based on Douglas County’s loads, and included the estimated amounts in the table above. The future minimum payments for the PUDs in the preceding table reflect the principal and capacity payments only and do not include interest, operation, or maintenance expenses.

Selected information regarding these projects is summarized as follows (dollars in millions):


	Capacity Charges and Revenue Bonds as of December 31, 2022		PGE’s Average Share as of December 31, 2022			Contract Expiration	Total PGE Contract Costs
			Output		Capacity		2022		2021		2020
					(in MW)
Priest Rapids and Wanapum	$	2,042	8.6	%	163	2052	$	45	$	26	$	25
Wells	421		18.8		113	2028	12		13		23

The agreements for Priest Rapids, Wanapum, and Wells provide that, should any other purchaser of output default on payments as a result of bankruptcy or insolvency, PGE would be allocated a pro-rata share of the output and operating and debt service costs of the defaulting purchaser. For Wells, PGE would be responsible for a pro-rata portion of the defaulting purchaser’s share with no limitation, regardless of the reason for any default. For Priest Rapids and Wanapum, PGE would be allocated up to a cumulative maximum that would not adversely affect the tax-exempt status of any of the public utility district’s outstanding debt for the portion of the project that benefits tax-exempt purchasers.

Natural gas—PGE has contracts for the purchase and transportation of natural gas from domestic and Canadian sources for its natural gas-fired generating facilities.

Coal—The Company has a coal agreement with take-or-pay provisions related to Colstrip Units 3 and 4 coal-fired generating plant (Colstrip) that expires in December 2025.

Guarantees

PGE enters into financial agreements, 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 December 31, 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 consolidated balance sheets with respect to these indemnities.

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations [Table Text Block]

AROs consist of the following (in millions):


	As of December 31,
	2022		2021
Trojan decommissioning activities	$	170	$	139
Utility plant	86		95
Non-utility property	33		35
Total asset retirement obligations	289		269
Less: current portion *	32		31
Noncurrent asset retirement obligations	$	257	$	238

* Current portion of AROs are classified within Accrued expenses and other current liabilities in the consolidated balance sheets.

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

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


	Years Ended December 31,
	2022		2021		2020
Balance as of beginning of year	$	269	$	291	$	279
Liabilities incurred	1		—		3
Liabilities settled	(27)		(18)		(18)
Accretion expense	10		10		10
Revisions in estimated cash flows	36		(14)		17
Balance as of end of year	$	289	$	269	$	291

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2022

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Cash Equivalents

Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents, of which PGE had $150 million as of December 31, 2022 and $44 million as of December 31, 2021 included within Cash and cash equivalents in the consolidated balance sheets.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and State (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 8 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. During 2020, 2021, and much of 2022, the Company took steps to support customers during the COVID-19 pandemic, including suspending late fees and developing time payment arrangements. COVID-19 protections ended in September 2022.

Provisions for uncollectible accounts receivable and unbilled revenues related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates for credit losses are based on management’s assessment of the current and forecasted probability of collection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other factors that help determine credit loss estimates for accounts receivable and unbilled revenues. For more information on PGE’s provision for uncollectible accounts receivable and unbilled revenues see “Accounts Receivable, Net” in Note 4, Balance Sheet Components. A portion of PGE’s provision for uncollectible accounts receivable and unbilled revenues is deferred as a regulatory asset, for more information see “COVID-19” in Note 7, Regulatory Assets and Liabilities.

Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable. There have been no material write-offs of accounts receivable related to wholesale sales in 2022, 2021, or 2020.

Price Risk Management

PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statements of income, offset by the effects of regulatory accounting when it is expected that the gain or loss upon settlement will be reflected in future retail rates. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting.

Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net variable power costs (NVPC).

In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, the Company recognizes a realized gain or loss on the derivative instrument.

Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.

Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral to certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period. Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets and were $116 million as of December 31, 2022 and $37 million as of December 31, 2021. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheets and were $33 million and $18 million as of December 31, 2022 and 2021, respectively.

Inventories

PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value.

Electric Utility Plant

Capitalization Policy

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

During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made. If any costs are expensed, PGE may seek recovery of such costs in customer prices, although there can be no guarantee such recovery would be granted. Costs disallowed for recovery in customer prices, if any, are charged to expense at the time such disallowance becomes probable.

PGE records AFUDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. In 2020, the FERC issued a waiver that allowed jurisdictional utilities to apply an alternative AFUDC calculation formula that excluded the actual outstanding short-term debt balance and replaced it with the simple average of the actual 2019 short-term debt balance. PGE adopted the waiver in the second quarter of 2020. The purpose of the waiver, which ultimately expired March 31, 2022, was to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction in response to COVID-19.

AFUDC is capitalized as part of the cost of plant and credited to the consolidated statements of income. The average rate used by PGE was 6.5% in 2022, 6.7% in 2021, and 6.9% in 2020. AFUDC from borrowed funds, reflected as a reduction to Interest expense, net, was $7 million in 2022 and $8 million in both 2021 and 2020. AFUDC from equity funds, included in Other income, net, was $14 million in 2022, $17 million in 2021, and $16 million in 2020.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.4% in 2022, 3.4% in 2021, and 3.5% in 2020. A component of depreciation expense includes estimated asset retirement removal costs allowed in customer prices.

Periodic studies are conducted to update depreciation parameters (i.e. retirement dispersion patterns, average service lives, and net salvage rates), including estimates of asset retirement obligations (AROs) and asset retirement removal costs. The studies are conducted at a minimum of every five years and are filed with the OPUC for approval and inclusion in a future rate proceeding. In 2021, PGE completed a depreciation study based on 2019 data, with an order received from the OPUC in December 2021 authorizing new depreciation rates effective May 9, 2022.

Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2025 to 2061. Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years):


Generation, excluding thermal:
Hydro			97
Wind			30
Transmission			61
Distribution			51
General			16

When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities.

Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years. Accumulated amortization was $499 million and $446 million as of December 31, 2022 and 2021, respectively, with amortization expense of $58 million in 2022, $58 million in 2021 and $64 million in 2020. Future estimated amortization expense as of December 31, 2022 is as follows: $54 million in 2023; $49 million in 2024; $37 million in 2025; $28 million in 2026; and $23 million in 2027.

Marketable Securities

Nuclear decommissioning trust

Reflects assets held in trust to cover general decommissioning costs and operation of the Independent Spent Fuel Storage Installation (ISFSI) at the decommissioned Trojan nuclear power plant (Trojan), which was closed in 1993. The Nuclear decommissioning trust (NDT) includes contributions made by the Company, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein.

Non-qualified benefit plan trust

Reflects assets held in trust to cover the obligations of PGE’s non-qualified benefit plans (NQBP) and represents contributions made by the Company, less qualified expenditures, plus any realized and unrealized gains and losses on the investments held therein.

All of PGE’s investments in marketable securities included in NDT and NQBP trust on the consolidated balance sheets, are classified as equity or trading debt securities. These securities are classified as noncurrent because they are not available for use in operations. Such securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the NQBP trust assets are included in Other income, net. Realized and unrealized gains and losses on the NDT fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold in the NDT and the NQBP are based on the first in first out method.

Regulatory Accounting

Regulatory Assets and Liabilities

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

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

For additional information concerning the Company’s regulatory assets and liabilities, see Note 7, Regulatory Assets and Liabilities.

Power Cost Adjustment Mechanism

PGE is subject to a Power Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the consolidated statements of income.

The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC.

To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given

year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE. PGE’s authorized ROE was 9.5% for 2022 and 2021.

Any estimated refund to customers pursuant to the PCAM is recorded as a reduction in Revenues, net in PGE’s consolidated statements of income, while any estimated collection from customers is recorded as a reduction in Purchased power and fuel expense. For the year ended December 31, 2022, PGE’s actual NVPC was $23 million above baseline NVPC, which is within the established deadband range, therefore no estimated collection from customers was recorded as of December 31, 2022. A final determination regarding the 2022 PCAM results will be made by the OPUC through a public filing and review in 2023. For the year ended December 31, 2021, actual NVPC was above baseline NVPC by $62 million, which was outside the established deadband range. Pursuant to the PCAM, as PGE’s preliminary regulatory ROE was below 8.5% as determined under the related earnings test, PGE deferred $29 million, which represents 90% of the excess variance expected to be collected from customers. On October 24, 2022, PGE and Parties submitted a stipulation with the OPUC that resolved all matters related to the 2021 PCAM and would allow PGE full recovery except for $2 million, which was recorded as a charge to earnings. Amortization will occur over a two-year period beginning January 1, 2023. Order 22-440, issued November 11, 2022, adopted the stipulation approving amortization of amounts.

Asset Retirement Obligations

Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred.

The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, with such depreciation included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is included in Depreciation and amortization expense in the Company’s consolidated statements of income.

For additional information concerning the Company’s AROs, see Note 8, Asset Retirement Obligations.

The difference between the timing of the recognition of ARO depreciation and accretion expenses and the amount included in customers’ prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. As of December 31, 2022, PGE had a net regulatory liability related to Utility plant AROs in the amount of $7 million and a net regulatory asset related to Trojan decommissioning ARO activities of $131 million. As of December 31, 2021, PGE had a net regulatory liability related to Utility plant AROs in the amount of $43 million and a net regulatory asset related to Trojan decommissioning ARO activities of $90 million. For additional information concerning the Company’s regulatory assets and liabilities related to AROs, see Note 7, Regulatory Assets and Liabilities.

Contingencies

Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental contingencies, are accrued, and disclosed if material, when it is probable

that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate.

A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be determined, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made.

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

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

For additional information concerning the Company’s contingencies, see Note 19, Contingencies.

Accumulated Other Comprehensive Loss

Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the obligations of the non-qualified benefit plans recognized in net income and the unfunded position.

Revenue Recognition

Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided. The prices charged, and amount of consideration PGE receives in exchange for its services provided, are regulated by the OPUC or the FERC. PGE recognizes revenue through the following steps: i) identifying the contract with the customer; ii) identifying the performance obligations in the contract; iii) determining the transaction price; iv) allocating the transaction price to the performance obligations; and v) recognizing revenue when or as each performance obligation is satisfied.

Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes and totaled $53 million in 2022, $48 million in 2021, and $46 million in 2020.

Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that remained unbilled to customers. The unbilled revenues estimate, which is included in Accounts receivable, net in the Company’s consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices.

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

Alternative Revenue Programs

Revenues related to PGE’s decoupling mechanism are considered earned under alternative revenue programs, as this amount represents a contract with the regulator and not with customers. Such revenues are presented separately from revenues from contracts with customers and classified as Alternative revenue programs, net of amortization on the consolidated statements of income. The activity within this line item is comprised of current period deferral adjustments, which can either be a collection from or a refund to customers, and is net of any related amortization. When amounts related to alternative revenue programs are ultimately included in prices and customer bills, the amounts are included within Revenues, net, with an equal and offsetting amount of amortization recorded on the Alternative revenue programs, net of amortization line item.

In the 2022 GRC, parties reached an agreement that has eliminated PGE’s decoupling mechanism upon the effective date of new customer prices pursuant to the case, which began May 9, 2022. Pursuant to the GRC Order, the OPUC adopted the agreement such that deferrals will not occur after 2022, although amortization of then previously recorded deferrals will continue as scheduled until collected or refunded in future customer prices and deferral continued through the end of 2022 on a prorated basis.

Stock-Based Compensation

The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis. For additional information concerning the Company’s Stock-Based Compensation, see Note 14, Stock-Based Compensation Expense.

Income Taxes

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

Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability. Such amounts were recognized as net regulatory liabilities of $194 million and $208 million as of December 31, 2022 and 2021, respectively, and will primarily be reversed using the average rate assumption method to account for the refund to customers as the temporary differences reverse.

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

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

Jointly-owned Plant (Tables)

12 Months Ended

Dec. 31, 2022

Jointly-owned Plant [Abstract]

Schedule of Jointly Owned Utility Plants [Table Text Block]

As of December 31, 2022, PGE had the following investments in jointly-owned plant (dollars in millions):


	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation (1)		Construction Work In Progress

Colstrip	20.00	%	1986			$	571	$	421	$	—
Pelton/Round Butte (2)	50.01	%	1958	/	1964	210		69		12
Total						$	781	$	490	$	12

(1) Excludes AROs and accumulated asset retirement removal costs.

(2) PGE operates the Pelton/Round Butte Project and had a 66.67% ownership interest as of December 31, 2021. Effective January 1, 2022, PGE sold an additional 16.66% ownership interest to the party who holds the remaining ownership interest, resulting in PGE’s 50.01% ownership interest.

Cover Page Document - USD ($)	12 Months Ended
Cover Page Document - USD ($)	Dec. 31, 2022	Feb. 08, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
Document Transition Report	false
Entity File Number	001-05532-99
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 S.W. Salmon Street
Entity Address, City or Town	Portland
Entity Address, State or Province	OR
Entity Address, Postal Zip Code	97204
City Area Code	503
Local Phone Number	464-8000
Title of 12(b) Security	Common Stock, no par value
Trading Symbol	POR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
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
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 4,297,974,093
Entity Common Stock, Shares Outstanding		89,312,765
Entity Central Index Key	0000784977
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Current Fiscal Year End Date	--12-31
Auditor Name	Deloitte & Touche LLP
Auditor Firm ID	34
Auditor Location	Portland, Oregon

Balance Sheet Components Allowance for Uncollectible accounts activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts, Notes, Loans and Financing Receivable [Line Items]
Balance as of beginning of year	$ 26	$ 16	$ 5
Increase in provision	(2)	(35)	(15)
Amounts written off, less recoveries	(12)	(25)	(4)
Balance as of end of year	$ 12	$ 26	$ 16

Leases Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
Leases Lease Cost (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Lease, Cost	$ 4	$ 8
Finance Lease, Right-of-Use Asset, Amortization	14	7
Finance Lease, Interest Expense	15	11
FinanceLeaseCost	29	18
Variable Lease, Cost	$ 31	$ 24

Consolidated Statements of Equity - USD ($) $ in Millions	Total	Common Stock Shares	Common Stock Amount	Accumulated Other Comprehensive Loss	Retained Earnings
Balance, shares at Dec. 31, 2019		89,387,124
Balance at Dec. 31, 2019	$ 2,591		$ 1,220	$ (10)	$ 1,381
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		150,207
Proceeds from issuance of shares pursuant to equity-based plans	2		2
Stock-based compensation	$ 9		9	0	0
Common Stock, Dividends, Per Share, Declared	$ 1.5850
Dividends declared	$ (143)		0	0	(143)
Net income	155		0	0	155
Other comprehensive income (loss)	(1)		0	(1)	0
Balance, shares at Dec. 31, 2020		89,537,331
Balance at Dec. 31, 2020	2,613		1,231	(11)	1,393
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		123,281
Proceeds from issuance of shares pursuant to equity-based plans	0		0
Stock-based compensation	13		13	0	0
Stock Repurchased During Period, Value	$ 12		(3)		(9)
Stock Repurchased During Period, Shares		(250,000)
Common Stock, Dividends, Per Share, Declared	$ 1.6975
Dividends declared	$ (152)		0	0	(152)
Net income	244		0	0	244
Other comprehensive income (loss)	1		0	1	0
Balance, shares at Dec. 31, 2021		89,410,612
Balance at Dec. 31, 2021	2,707		1,241	(10)	1,476
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares issued pursuant to equity-based plans		222,741
Proceeds from issuance of shares pursuant to equity-based plans	2		2
Stock-based compensation	11		11	0	0
Stock Repurchased During Period, Value	$ 18		(5)	0	(13)
Stock Repurchased During Period, Shares		(350,000)
Common Stock, Dividends, Per Share, Declared	$ 1.7875
Dividends declared	$ (162)		0	0	(162)
Net income	233		0	0	233
Other comprehensive income (loss)	6		0	6	0
Balance, shares at Dec. 31, 2022		89,283,353
Balance at Dec. 31, 2022	$ 2,779		$ 1,249	$ (4)	$ 1,534

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2022

Employee Benefits [Abstract]

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

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


	2022						2021
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust assets	$	19	$	19	$	38	$	21	$	24	$	45
Non-qualified benefit plan liabilities *	16		67		83		25		70		95

* For the NQBP, excludes the current portion of $2 million in 2022 and 2021, which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets.

Schedule of Allocation of Plan Assets [Table Text Block]

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


	As of December 31,
	2022				2021
	Actual		Target *		Actual		Target *
Defined Benefit Pension Plan:
Equity securities	55	%	55	%	61	%	60	%
Debt securities	45		45		39		40
Total	100	%	100	%	100	%	100	%
Other Postretirement Benefit Plans:
Equity securities	39	%	40	%	59	%	57	%
Debt securities	61		60		41		43
Total	100	%	100	%	100	%	100	%
Non-Qualified Benefits Plans:
Equity securities	7	%	5	%	8	%	7	%
Debt securities	9		11		13		14
Insurance contracts	84		84		79		79
Total	100	%	100	%	100	%	100	%

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

The Company’s financial assets and liabilities whose values were recognized at fair value are as follows by level within the fair value hierarchy (in millions):


	December 31, 2022
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	150	$	—	$	—	$	—	$	150
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government	9		10		—		—		19
Corporate credit	—		9		—		—		9
Money market funds measured at NAV (2)	—		—		—		11		11
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	3		—		—		—		3
Debt securities—domestic government	3		—		—		—		3



Price risk management activities: (1) (4)
Electricity	—		93		63		—		156
Natural gas	—		225		6		—		231
	$	166	$	337	$	69	$	11	$	583
Liabilities:

Price risk management activities: (1) (4)
Electricity	$	—	$	53	$	93	$	—	$	146
Natural gas	—		39		8		—		47
	$	—	$	92	$	101	$	—	$	193

(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 regarding price risk management derivatives, see Note 6, Risk Management.


	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 measured at NAV (2)	—		—		—		14		14
Non-qualified benefit plan trust: (3)
Money market funds	1		—		—		—		1
Equity securities—domestic	4		—		—		—		4

Debt securities—domestic government	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 regarding price risk management derivatives, see Note 6, Risk Management.

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


	Level 1		Level 2		Level 3		Other *		Total
As of December 31, 2022:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	16	$	—	$	—	$	—	$	16




Investments measured at NAV:
Money market funds	—		—		—		4		4
Collective trust funds	—		—		—		525		525
Private equity funds	—		—		—		2		2

	$	16	$	—	$	—	$	531	$	547
Other Postretirement Benefit Plans assets:
Money market funds	$	4	$	—	$	—	$	—	$	4
Equity securities:
Domestic	—		2		—		—		2
International	3		—		—		—		3
Debt securities—Domestic	—		4		—		—		4
Investments measured at NAV:
Money market funds	—		—		—		5		5
Collective trust funds	—		—		—		3		3
	$	7	$	6	$	—	$	8	$	21
As of December 31, 2021:
Defined Benefit Pension Plan assets:


Equity securities—Domestic	$	25	$	—	$	—	$	—	$	25




Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		764		764
Private equity funds	—		—		—		5		5
	$	25	$	—	$	—	$	775	$	800
Other Postretirement Benefit Plans assets:
Money market funds	$	3	$	—	$	—	$	—	$	3
Equity securities:
Domestic	—		4		—		—		4
International	10		—		—		—		10
Debt securities—Domestic government	—		6		—		—		6
Investments measured at NAV:
Money market funds	—		—		—		6		6
Collective trust funds	—		—		—		8		8

	$	13	$	10	$	—	$	14	$	37

Schedule of Defined Benefit Plans Disclosures [Table Text Block]


	Defined Benefit Pension Plan				Other Postretirement Benefits				Non-Qualified Benefit Plans
	2022		2021		2022		2021		2022		2021
Benefit obligation:
As of January 1	$	972	$	1,010	$	71	$	76	$	27	$	28
Service cost	17		19		1		2		—		—
Interest cost	28		27		2		2		1		1

Actuarial gain	(255)		(26)		(15)		(5)		(7)		—

Benefit payments	(69)		(47)		(4)		(5)		(3)		(2)
Administrative expenses	(3)		(3)		—		—		—		—
Plan amendment	5		(8)		1		1		—		—
Plan settlements	—		—		(13)		—		—		—
As of December 31	$	695	$	972	$	43	$	71	$	18	$	27
Fair value of plan assets:
As of January 1	$	800	$	753	$	37	$	35	$	21	$	19
Actual return on plan assets	(181)		97		(6)		4		(2)		1
Company contributions	—		—		7		3		3		3

Benefit payments	(69)		(47)		(4)		(5)		(3)		(2)
Administrative expenses	(3)		(3)		—		—		—		—
Plan settlements	—		—		(13)		—		—		—
As of December 31	$	547	$	800	$	21	$	37	$	19	$	21
Unfunded position as of December 31	$	(148)	$	(172)	$	(22)	$	(34)	$	1	$	(6)
Accumulated benefit plan obligation as of December 31	$	656	$	885	N/A		N/A		$	17	$	23
Classification in consolidated balance sheet:
Noncurrent asset	$	—	$	—	$	—	$	—	$	19	$	21
Current liability	—		—		(1)		—		(2)		(2)
Noncurrent liability	(148)		(172)		(21)		(34)		(16)		(25)
Net asset (liability)	$	(148)	$	(172)	$	(22)	$	(34)	$	1	$	(6)
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	(28)	$	(78)	$	(8)	$	(7)	$	(7)	$	(1)
Net settlement gain	—		—		11		—		—		—
Net prior service credit	5		(9)		—		—		—		—
Amortization of net actuarial loss	(15)		(22)		—		—		(1)		(1)
Amortization of prior service credit	2		—		—		1		—		—
	$	(36)	$	(109)	$	3	$	(6)	$	(8)	$	(2)
Amounts included in AOCL: *
Net actuarial loss (gain)	$	96	$	139	$	(7)	$	(3)	$	6	$	14
Prior service cost	(1)		(8)		—		(7)		—		—
	$	95	$	131	$	(7)	$	(10)	$	6	$	14

Significant actuarial gains (losses) experienced that resulted in changes in projected benefit obligation included the following:

Schedule of Net Benefit Costs [Table Text Block]

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


	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2022		2021		2020		2022		2021		2020		2022		2021		2020
Service cost	$	17	$	19	$	17	$	1	$	2	$	2	$	—	$	—	$	—
Interest cost on benefit obligation	28		27		31		2		2		2		1		1		1
Expected return on plan assets	(46)		(45)		(44)		(2)		(2)		(2)		—		—		—

Amortization of prior service credit	(2)		—		—		—		(1)		(1)		—		—		—
Amortization of net actuarial loss	15		22		17		—		—		—		1		1		1
Settlement gain	—		—		—		(11)		—		—		—		—		—
Net periodic benefit cost	$	12	$	23	$	21	$	(10)	$	1	$	1	$	2	$	2	$	2

Employee Benefits Assumptions [Table]

The following assumptions were used in determining benefit obligations and net period benefit costs:


	Defined Benefit Pension Plan				Other Postretirement Benefits				Non-Qualified Benefit Plans
	2022		2021		2022		2021			2022		2021
Assumptions used to determine benefit obligations:
Discount rate	5.42	%	2.92	%	5.47% -		2.75% -			5.42	%	2.92	%
					5.51	%	3.11	%
Rate of compensation increase	4.21	%	4.26	%	4.04	%	4.13	%		5.10	%	4.10	%

Assumptions used to determine net periodic benefit cost:
Discount rate	2.92	%	2.64	%	2.75% -		2.22% -			2.92	%	2.64	%
					3.11	%	2.92	%
Rate of compensation increase	4.26	%	3.65	%	4.13	%	4.58	%		4.10	%	4.10	%
Long-term rate of return on plan assets	6.75	%	6.88	%	4.83	%	5.04	%		N/A		N/A

Schedule of Expected Benefit Payments [Table Text Block]

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


	Payments Due
	2023		2024		2025		2026		2027		2028 - 2032
Defined benefit pension plan	$	59	$	54	$	54	$	54	$	53	$	262
Other postretirement benefits	4		4		5		5		3		14
Non-qualified benefit plans	2		2		2		2		2		8
Total	$	65	$	60	$	61	$	61	$	58	$	284

Jointly-owned Plant

12 Months Ended

Dec. 31, 2022

Jointly-owned Plant [Abstract]

Jointly-owned Plant [Text Block]

JOINTLY-OWNED PLANT

As of December 31, 2022, PGE had the following investments in jointly-owned plant (dollars in millions):


	PGE Share		In-service Date			Plant In-service		Accumulated Depreciation (1)		Construction Work In Progress

Colstrip	20.00	%	1986			$	571	$	421	$	—
Pelton/Round Butte (2)	50.01	%	1958	/	1964	210		69		12
Total						$	781	$	490	$	12

(1) Excludes AROs and accumulated asset retirement removal costs.

Under the respective joint operating agreements for the generating facilities, each participating owner is responsible for financing its share of capital and operating expenses. PGE’s proportionate share of direct operating and maintenance expenses of the facilities is included in the corresponding operating and maintenance expense categories in the consolidated statements of income.

The Company operated, and continues to have a 90% ownership interest in Boardman, which ceased coal-fired operations during 2020. The Company has begun decommissioning the facility. As of December 31, 2022, PGE’s ARO liability for its 90% share of the decommissioning costs was $13 million.

Revenue Recogniton Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Document Period End Date	Dec. 31, 2022
Regulated Operating Revenue, Electric, Non-Nuclear	$ 2,205	$ 2,105	$ 1,910
Contract with Customer, Liability, Cumulative Catch-up Adjustment to Revenue, Change in Estimate of Transaction Price	11	(29)	(6)
Deferred Revenue, Revenue Recognized	7	2	28
Regulated Operating Revenue	2,223	2,078	1,932
Unregulated Operating Revenue	363	255	162
Regulated and Unregulated Operating Revenue	61	63	51
Total Revenues	2,647	2,396	2,145
Effective Income Tax Rate Reconciliation at Federal Statutory Income Tax Rate, Amount			24
Gain on Derivative Instruments, Pretax	133	63	65
Asset Retirement Obligation, Cash Paid to Settle	27	18	18
Residential [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	1,158	1,118	1,030
Commercial [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	723	690	616
Industrial [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	289	250	218
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Regulated Operating Revenue, Electric, Non-Nuclear	$ 35	$ 47	$ 46

Regulatory Assets and Liabilities Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Regulatory Assets	$ 527	$ 557
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	274
Regulatory Liabilities	1,623	1,466
Deferred Purchased Power Costs	23	62
Removal Costs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	1,136	1,047
Deferred Income Tax Charge [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	194	208
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	7	43
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	24
Regulatory Liabilities	91	113
Regulatory Assets Earning a Rate of Return at the Approved Rate	67
RemainingAmountsOfRegulatoryLiabilitesForWhichNoInterstAccruesDuringRecoveryPeriodIsProvided	219
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets [Line Items]
Regulatory Assets		55
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	195
Regulatory Liabilities	0
Earning a return [Member]
Regulatory Assets [Line Items]
Regulatory Liabilities	1,404
Other Regulatory Assets Earning a Return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	70
Earning a return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	253
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	55
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	1
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	131
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	95
Loss on Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	23
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	21
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	133	90
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets	94	81
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	24
February2021IceStormAndDamageDeferral
Regulatory Assets [Line Items]
Regulatory Assets	74	67
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
PowerCostAdjustmentMechanismDeferral
Regulatory Assets [Line Items]
Regulatory Assets	28	29
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
2020LaborDayWildfireDeferral
Regulatory Assets [Line Items]
Regulatory Assets	31	45
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
COVID-19Deferral
Regulatory Assets [Line Items]
Regulatory Assets	22	36
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Wildfire mitigation
Regulatory Assets [Line Items]
Regulatory Assets	28	$ 0
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 0

Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2022 USD ($)
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 395
Unrecorded Unconditional Purchase Obligation, Due within One Year	239
Unrecorded Unconditional Purchase Obligation, Due within Two Years	70
Unrecorded Unconditional Purchase Obligation, Due within Three Years	36
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	2
Unrecorded Unconditional Purchase Obligation, Due after Five Years	43
Long-term Contract for Purchase of Electric Power [Domain]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	5,599
Unrecorded Unconditional Purchase Obligation, Due within One Year	457
Unrecorded Unconditional Purchase Obligation, Due within Two Years	449
Unrecorded Unconditional Purchase Obligation, Due within Three Years	428
Unrecorded Unconditional Purchase Obligation, Due within Four Years	303
Unrecorded Unconditional Purchase Obligation, Due within Five Years	309
Unrecorded Unconditional Purchase Obligation, Due after Five Years	3,653
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	133
Unrecorded Unconditional Purchase Obligation, Due within One Year	17
Unrecorded Unconditional Purchase Obligation, Due within Two Years	17
Unrecorded Unconditional Purchase Obligation, Due within Three Years	20
Unrecorded Unconditional Purchase Obligation, Due within Four Years	5
Unrecorded Unconditional Purchase Obligation, Due within Five Years	5
Unrecorded Unconditional Purchase Obligation, Due after Five Years	69
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	77
Unrecorded Unconditional Purchase Obligation, Due within One Year	12
Unrecorded Unconditional Purchase Obligation, Due within Two Years	12
Unrecorded Unconditional Purchase Obligation, Due within Three Years	11
Unrecorded Unconditional Purchase Obligation, Due within Four Years	10
Unrecorded Unconditional Purchase Obligation, Due within Five Years	9
Unrecorded Unconditional Purchase Obligation, Due after Five Years	23
Natural gas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	508
Unrecorded Unconditional Purchase Obligation, Due within One Year	158
Unrecorded Unconditional Purchase Obligation, Due within Two Years	43
Unrecorded Unconditional Purchase Obligation, Due within Three Years	38
Unrecorded Unconditional Purchase Obligation, Due within Four Years	37
Unrecorded Unconditional Purchase Obligation, Due within Five Years	30
Unrecorded Unconditional Purchase Obligation, Due after Five Years	202
Coal and transportationSupply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	81
Unrecorded Unconditional Purchase Obligation, Due within One Year	27
Unrecorded Unconditional Purchase Obligation, Due within Two Years	27
Unrecorded Unconditional Purchase Obligation, Due within Three Years	27
Unrecorded Unconditional Purchase Obligation, Due within Four Years	0
Unrecorded Unconditional Purchase Obligation, Due within Five Years	0
Unrecorded Unconditional Purchase Obligation, Due after Five Years	0
Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	6,793
Unrecorded Unconditional Purchase Obligation, Due within One Year	910
Unrecorded Unconditional Purchase Obligation, Due within Two Years	618
Unrecorded Unconditional Purchase Obligation, Due within Three Years	560
Unrecorded Unconditional Purchase Obligation, Due within Four Years	360
Unrecorded Unconditional Purchase Obligation, Due within Five Years	355
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 3,990

Balance Sheet Components (Details) - USD ($) $ in Millions	12 Months Ended
Balance Sheet Components (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Balance Sheet Components [Abstract]
Unbilled Receivables, Current	$ 131	$ 117
Accounts Receivable, Allowance for Credit Loss, Current	12	26	$ 16	$ 5
Increase in provision	$ 2	$ 35	$ 15

Income Taxes Income taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes Income taxes (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	21.00%
Tax Credit Carryforward, Federal	$ 102
Deferred Tax Assets, Valuation Allowance	0
Unrecognized Tax Benefits	0
(Amortization) Deferral of net benefits due to Tax Reform	0	$ 0	$ (23)
Deferred Tax Assets, Other Tax Carryforwards	$ 9

Employee Benefits Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Dec. 31, 2022
Defined Benefit Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Defined Benefit Pension Plan [Member] \| Collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	55.00%	60.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	55.00%	61.00%
Defined Benefit Pension Plan [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	45.00%	40.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	45.00%	39.00%
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Other Postretirement Benefit Plans [Member] \| Collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%	57.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	39.00%	59.00%
Other Postretirement Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	60.00%	43.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	61.00%	41.00%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	100.00%	100.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	100.00%	100.00%
Non Qualified Benefit Plans [Member] \| Collective trust funds
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	5.00%	7.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	7.00%	8.00%
Non Qualified Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	11.00%	14.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	9.00%	13.00%
Non Qualified Benefit Plans [Member] \| Other Contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	84.00%	79.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	84.00%	79.00%

Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net realized and unrealized losses	$ (84)	$ (50)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	(31)	(2)
Net liabilities from price risk management activities as of end of year	32	85	$ 137
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	(82)	(55)
Net realized losses	$ (2)	$ 5

Balance Sheet Components Balance Sheet Components Public Utility Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Public Utilities, Property, Plant and Equipment, Generation or Processing	$ 4,709	$ 4,649
Public Utilities, Property, Plant and Equipment, Transmission	1,119	1,012
Public Utilities, Property, Plant and Equipment, Distribution	4,813	4,469
Public Utilities, Property, Plant and Equipment, General	973	914
Public Utilities, Property, Plant and Equipment, Intangible	807	794
Public Utilities, Property, Plant and Equipment, Plant in Service	12,421	11,838
Public Utilities, Property, Plant and Equipment, Accumulated Depreciation	4,423	4,146
In service, net	7,998	7,692
Construction work-in-progress	467	313
Public Utilities, Property, Plant and Equipment, Net	$ 8,465	$ 8,005

Long term debt (Tables)

12 Months Ended

Dec. 31, 2022

Long-Term Debt, Unclassified [Abstract]

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

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


	As of December 31,
	2022		2021
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.09% in 2022 and 4.11% in 2021, due at various dates through 2051	$	3,280	$	3,180
Unsecured term bank loans, variable rate of approximately 5.30% at December 31, 2022	260		—
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033	119		119

Total long-term debt	3,659		3,299
Less: Unamortized debt expense	(13)		(14)


Less: Current portion of long-term debt	(260)		—
Long-term debt, net of current portion	$	3,386	$	3,285

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

As of December 31, 2022, the future minimum principal payments on long-term debt are as follows (in millions):


Years ending December 31:
2023	$	260
2024	80
2025	—
2026	—
2027	160
Thereafter	3,159
	$	3,659

Lessee, Operating Lease, Liability, Maturity

As of December 31, 2022, the future minimum payments on the financing arrangement are as follows (in millions):


Years ending December 31:
2023	$	2
2024	2
2025	5
2026	5
2027	5
Thereafter	69
Total Payments	88
Less: Imputed Interest	(61)
Present value of minimum payments	$	27

- Definition

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

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 210
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02.22)
-URI https://asc.fasb.org/extlink&oid=120391452&loc=d3e13212-122682

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-URI https://asc.fasb.org/extlink&oid=120395691&loc=d3e24072-122690

Reference 3: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 1A
-URI https://asc.fasb.org/extlink&oid=124435984&loc=d3e28541-108399

Reference 4: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 6
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21506-112644

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 55
-Paragraph 69B
-URI https://asc.fasb.org/extlink&oid=123466577&loc=SL123495735-112612

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 45
-Paragraph 2
-URI https://asc.fasb.org/extlink&oid=124435984&loc=d3e28551-108399

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 470
-SubTopic 20
-Section 55
-Paragraph 69E
-URI https://asc.fasb.org/extlink&oid=123466577&loc=SL123495743-112612

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
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-Section 50
-Paragraph 7
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21521-112644

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-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 8
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21538-112644

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
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Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 835
-SubTopic 30
-Section 55
-Paragraph 8
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Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section 50
-Paragraph 3
-URI https://asc.fasb.org/extlink&oid=126973232&loc=d3e21475-112644

+ Details

Contingencies (Policies)	12 Months Ended
Contingencies (Policies)	Dec. 31, 2022
Contingencies [Abstract]
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental contingencies, are accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be determined, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event. Gain contingencies are recognized when realized and are disclosed when material. For additional information concerning the Company’s contingencies, see Note 19, Contingencies. 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.PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.

Asset Retirement Obilgations

12 Months Ended

Dec. 31, 2022

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):


	As of December 31,
	2022		2021
Trojan decommissioning activities	$	170	$	139
Utility plant	86		95
Non-utility property	33		35
Total asset retirement obligations	289		269
Less: current portion *	32		31
Noncurrent asset retirement obligations	$	257	$	238

* Current portion of AROs are classified within Accrued expenses and other current liabilities in the consolidated balance sheets.

Trojan decommissioning activities represents the present value of future decommissioning costs for PGE’s 67.5% ownership interest in Trojan, which ceased operation in 1993. The remaining decommissioning activities primarily consist of the long-term operation and decommissioning of the ISFSI, an interim dry storage facility that is licensed by the Nuclear Regulatory Commission. The ISFSI will store the spent nuclear fuel at the former plant site until an off-site storage facility is available. Decommissioning of the ISFSI and final site restoration activities will begin once shipment of all the spent fuel to a USDOE facility is complete, which is not expected prior to 2059. In 2022, the Company recorded an increase in the ARO of $36 million due to an increase in expected annual ISFSI operation costs. The Company also recorded accretion of $6 million and a reduction of $11 million due to settled liabilities.

Under a settlement agreement reached with the USDOE, the Company receives annual reimbursement from the USDOE for certain costs related to monitoring the ISFSI. Pursuant to this process, the USDOE reimbursed the co-owners $6 million in 2022 for costs incurred in 2021 and $5 million in 2021 for costs incurred in 2020 resulting from USDOE delays in accepting spent nuclear fuel.

Utility plant represents AROs that have been recognized for the Company’s thermal and wind generation sites, and distribution and transmission assets, the disposal of which is legally required. During 2022, utility AROs decreased

by $9 million, with the change comprised of new liabilities incurred of $1 million, accretion of $3 million, and a reduction of $13 million due to settled liabilities.

Non-utility property primarily represents AROs that have been recognized for portions of unregulated properties that are currently or previously leased to third parties. Revisions to estimates for non-utility AROs relate to assets that are no longer in service and the offset is charged directly to Depreciation and amortization on the consolidated statements of income in the period in which the revisions are probable and reasonably estimable. Non-utility AROs are not subject to regulatory deferral.

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


	Years Ended December 31,
	2022		2021		2020
Balance as of beginning of year	$	269	$	291	$	279
Liabilities incurred	1		—		3
Liabilities settled	(27)		(18)		(18)
Accretion expense	10		10		10
Revisions in estimated cash flows	36		(14)		17
Balance as of end of year	$	289	$	269	$	291

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

PGE maintains a separate Nuclear decommissioning trust in the consolidated balance sheet for funds collected from customers through prices to cover the cost of Trojan decommissioning activities.

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

Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) - USD ($)	Dec. 31, 2022	Dec. 31, 2021
Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	$ 35.00	$ 16.66
Natural gas financial swaps	2.71	2.02
Fnancial swaps - electricity	54.17	26.76
Maximum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	270.00	129.75
Natural gas financial swaps	24.71	8.02
Fnancial swaps - electricity	143.70	68.43
Weighted Average [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	101.27	43.73
Natural gas financial swaps	4.42	2.81
Fnancial swaps - electricity	104.21	52.46
Assets [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	52,000,000	0
Natural gas financial swaps	6,000,000	5,000,000
Fnancial swaps - electricity	11,000,000	1,000,000
Total commodity contracts	69,000,000	6,000,000
Liabilities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	93,000,000	90,000,000
Natural gas financial swaps	8,000,000	1,000,000
Fnancial swaps - electricity	0	0
Total commodity contracts	$ 101,000,000	$ 91,000,000

Employee Benefits Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair value of plan assets:
Actuarial loss (gain)	$ (15)	$ (5)
Defined Benefit Plan, Plan Assets, Payment for Settlement	(13)
Classification in consolidated balance sheet:
Noncurrent asset	(38)	(45)
Assumptions used:
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	2	2
2020 Labor Day wildfire earnings test reserve	15	0	$ 0
Pension Plans, Defined Benefit [Member]
Benefit obligation:
As of January 1	695	972	1,010
Fair value of plan assets:
Service cost	17	19	17
Interest cost on benefit obligation	28	27	31
Actuarial loss (gain)	(255)	(26)
Benefit payments	(69)	(47)
Defined Benefit Plan, Plan Assets, Administration Expense	(3)	(3)
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	(5)	8
As of January 1	547	800	753
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(148)	(172)
Net actuarial loss (gain) included in comprehensive income	(28)	(78)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Other Postretirement Benefits Cost (Reversal of Cost)	(1)	(8)
Defined Benefit Plan, Amortization of Gain (Loss)	(15)	(22)	$ (17)
Total Amounts included in comprehensive income	(36)	(109)
Defined Benefit Plan, Accumulated Benefit Obligation	656	885
Actual return on plan assets	(181)	97
Company contributions	0	0
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(148)	(172)
Amounts included in AOCL:
Net actuarial loss	96	139
Prior service cost	(5)	9
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 95	$ 131
Assumptions used:
Discount rate used to calculate benefit obligation	2.92%	2.64%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.21%	4.26%	3.65%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	6.75%	6.88%
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	$ 227	$ 52
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	2	0	$ 0
Pension Plans, Defined Benefit [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair value of plan assets:
As of January 1	0	0
Pension Plans, Defined Benefit [Member] \| Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets:
As of January 1	16	25
Pension Plans, Defined Benefit [Member] \| Fair Value, Inputs, Level 2 [Member]
Fair value of plan assets:
As of January 1	0	0
Other Postretirement Benefit Plans [Member]
Benefit obligation:
As of January 1	43	71	76
Fair value of plan assets:
Service cost	1	2	2
Interest cost on benefit obligation	2	2	2
Actuarial loss (gain)	15	5
Benefit payments	(4)	(5)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Defined Benefit Plan, Benefit Obligation, Increase (Decrease) for Plan Amendment	(1)	(1)
Defined Benefit Plan, Benefit Obligation, (Increase) Decrease for Curtailment		0
As of January 1	21	37	35
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(22)	(34)
Net actuarial loss (gain) included in comprehensive income	(8)	(7)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	11	0	0
Other Postretirement Benefits Cost (Reversal of Cost)	0	(7)
Defined Benefit Plan, Amortization of Gain (Loss)	0	0	$ 0
Total Amounts included in comprehensive income	3	(6)
Actual return on plan assets	(6)	4
Company contributions	7	3
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	(1)	0
Noncurrent liability	(21)	(34)
Amounts included in AOCL:
Net actuarial loss	(7)	(3)
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ (7)	$ (10)
Assumptions used:
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.04%	4.13%	4.58%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	4.83%	5.04%
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	$ 0	$ 1	$ 1
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member]
Fair value of plan assets:
As of January 1	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets:
As of January 1	7	13
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member]
Fair value of plan assets:
As of January 1	6	10
Non Qualified Benefit Plans [Member]
Benefit obligation:
As of January 1	18	27	28
Fair value of plan assets:
Service cost	0	0	0
Interest cost on benefit obligation	1	1	1
Actuarial loss (gain)	7	0
Benefit payments	(3)	(2)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
As of January 1	19	21	19
Defined Benefit Plan, Funded (Unfunded) Status of Plan	1	(6)
Net actuarial loss (gain) included in comprehensive income	(7)	(1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Other Postretirement Benefits Cost (Reversal of Cost)	0	0
Defined Benefit Plan, Amortization of Gain (Loss)	(1)	(1)	(1)
Total Amounts included in comprehensive income	(8)	(2)
Defined Benefit Plan, Accumulated Benefit Obligation	17	23
Actual return on plan assets	(2)	1
Company contributions	3	3
Classification in consolidated balance sheet:
Noncurrent asset	(19)	(21)
Current liability	(2)	(2)
Noncurrent liability	(16)	(25)
Amounts included in AOCL:
Net actuarial loss	6	14
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 6	$ 14
Assumptions used:
Discount rate used to calculate benefit obligation	2.92%	2.64%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	5.10%	4.10%
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	$ 0	$ 0	$ 0

Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Noncash Expense	$ 15	$ 14	$ 11
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	4,687,500
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Available for Grant	2,082,469
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Total Fair Value	$ 6	7	9
Share-based Payment Arrangement, Decrease for Tax Withholding Obligation	4	$ 1	$ 1
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized	$ 13
Stock-based Compensation, Attainment of Performance Goals That Allows Vesting	118.70%	88.60%	110.60%
Stock-based Compensation, Forfeiture Rate	5.00%
Share-based Payment Arrangement, Amount Capitalized	$ 0
Performance based stock award percentage - minimum	0.00%
Performance based stock award percentage - maximum	200.00%
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Share-based Liabilities Paid	$ 5	$ 3	$ 1

Jointly-owned Plant Schedule of Jointly-owned plant (Details) $ in Millions	Dec. 31, 2022 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	$ 781
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	490
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	12
Colstrip [Member]
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	571
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	421
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	0
Pelton/Round Butte Member
Jointly Owned Utility Plant Interests [Line Items]
Jointly Owned Utility Plant, Gross Ownership Amount of Plant in Service	210
Jointly Owned Utility Plant, Ownership Amount of Plant Accumulated Depreciation	69
Jointly Owned Utility Plant, Ownership Amount of Construction Work in Progress	$ 12

Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 269	$ 291	$ 279
Asset Retirement Obligation, Liabilities Incurred	1	0	3
Asset Retirement Obligation, Cash Paid to Settle	(27)	(18)	(18)
Asset Retirement Obligation, Accretion Expense	10	10	10
Asset Retirement Obligation, Revision of Estimate	36	(14)	17
Asset Retirement Obligation	$ 289	$ 269	$ 291

Leases Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Lease, Payments	$ 4	$ 8	$ 8
Finance Lease, Interest Payment on Liability	15	11	10
Finance Lease, Principal Payments	7	6	6
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	(12)	0
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	29	153	$ 0
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Current	4	4
Operating Lease, Liability, Noncurrent	$ 18	$ 22
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Accounts payable
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List]	Other noncurrent liabilities

Employee Benefits (Details) - USD ($) $ in Millions	12 Months Ended
Employee Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 13	$ 24	$ 22
Actuarial loss (gain)	15	5
Defined Benefit Plan, Effect of Decrease of Rate of Return on Plan Assets on Service and Interest Cost Components	4
Payment for Pension Benefits	0
Defined Benefit Plan, Effect of One Percentage Point Increase on Service and Interest Cost Components	$ 6
Company match pre 2009 hire	6.00%
Company match post 2008 hire	5.00%
Company contribution percentage to 401k for post 2008 hires	5.00%
Company contribution percent to 401k for bargaining employees	1.00%
401k Plan Company contributions	$ 29	26	26
Actuarial loss (gain)	15	5
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	11	0	0
Actuarial loss (gain)	(15)	(5)
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	4	5
Actuarial loss (gain)	(15)	(5)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Actuarial loss (gain)	255	26
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	69	47
Actuarial loss (gain)	255	26
Other Pension, Postretirement and Supplemental Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	$ 0
Actuarial loss (gain)	(7)	0
Defined Benefit Plan, Benefits Paid (Deprecated 2017-01-31)	3	2
Actuarial loss (gain)	$ (7)	$ 0

Fair Value of Financial Instruments (Policies)	12 Months Ended
Fair Value of Financial Instruments (Policies)	Dec. 31, 2022
Fair Value of Financial Instruments [Abstract]
Fair Value of Financial Instruments, Policy [Policy Text Block]	PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value for each reporting period. The Company then classifies these financial assets and liabilities based on a fair value hierarchy applied to prioritize the inputs to the valuation techniques used to measure fair value. The three levels of the fair value hierarchy and application to the Company are discussed below. Level 1 Quoted prices are available in active markets for identical assets or liabilities as of the measurement date. Level 2 Pricing inputs include those that are directly or indirectly observable in the marketplace as of the measurement date. Level 3 Pricing inputs include significant inputs that are unobservable for the asset or liability. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy. Assets measured at fair value using net asset value (NAV) as a practical expedient are not categorized in the fair value hierarchy. These assets are listed in the totals of the fair value hierarchy to permit the reconciliation to amounts presented in the financial statements. PGE recognizes transfers between levels in the fair value hierarchy as of the end of the reporting period for all of its financial instruments. Changes to market liquidity conditions, the availability of observable inputs, or changes in the economic structure of a security marketplace may require transfer of the securities between levels.
Allocation of Financial Asset to Hierarchy Levels [Policy Text Block]	Assets held in the NDT and NQBP trusts are recorded at fair value in PGE’s consolidated balance sheets and invested in securities that are exposed to interest rate, credit, and market volatility risks. These assets are classified within Level 1, 2, or 3 based on the following factors: Debt securities—PGE invests in highly-liquid United States Treasury securities to support the investment objectives of the trusts. These domestic government securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Assets classified as Level 2 in the fair value hierarchy include domestic government debt securities, such as municipal debt, and corporate credit securities. Prices are determined by evaluating pricing data such as broker quotes for similar securities and adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, as applicable. Equity securities—Equity mutual fund and common stock securities are classified as Level 1 in the fair value hierarchy due to the availability of quoted prices for identical assets in an active market as of the measurement date. Principal markets for equity prices include published exchanges such as NASDAQ and the NYSE. Money market funds—PGE invests in money market funds that seek to maintain a stable net asset value. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, certificates of deposits, and commercial paper. The Company believes the redemption value of these funds is likely to be the fair value, which is represented by the net asset value. Redemption is permitted daily without written notice. The NQBP trust is invested in exchange traded government money market funds and is classified as Level 1 in the fair value hierarchy due to the availability of quoted prices in published exchanges such as NASDAQ and the NYSE. The money market fund in the NDT is valued at NAV as a practical expedient and is not included in the fair value hierarchy. Assets and liabilities from price risk management activities, recorded at fair value in PGE’s 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 additional information regarding these assets and liabilities, see Note 6, Risk Management. For those assets and liabilities from price risk management activities classified as Level 2, fair value is derived using present value formulas that utilize inputs such as forward commodity prices and interest rates. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument, can be derived from observable data, or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include commodity forwards, futures, and swaps. Assets and liabilities from price risk management activities classified as Level 3 consist of instruments for which fair value is derived using one or more significant inputs that are not observable for the entire term of the instrument. These instruments consist of longer-term commodity forwards, futures, and swaps.
Transfers in and out of Level 3 [Policy Text Block]	Transfers into Level 3 occur when significant inputs used to value the Company’s derivative instruments become less observable, such as a delivery location becoming significantly less liquid. During the years ended December 31, 2022 and 2021, there were no transfers into Level 3 from Level 2. Transfers out of Level 3 occur when the significant inputs become more observable, such as when the time between the valuation date and the delivery term of a transaction becomes shorter. PGE records transfers into and from Level 3 at the end of the reporting period for all of its derivative instruments.
Debt, Policy [Policy Text Block]	Long-term debt is recorded at amortized cost in PGE’s consolidated balance sheets. The fair value of the Company’s First Mortgage Bonds (FMBs) and Pollution Control Revenue Bonds (PCRBs) is classified as a Level 2 fair value measurement.

Price Risk Management (Tables)

12 Months Ended

Dec. 31, 2022

Price Risk Management [Abstract]

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

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


	As of December 31,
	2022		2021
Current assets:
Commodity contracts:
Electricity	$	112	$	16
Natural gas	201		86
Total current derivative assets(1)	313		102
Noncurrent assets:
Commodity contracts:
Electricity	44		1
Natural gas	30		34
Total noncurrent derivative assets(1)	74		35

Total derivative assets(2)	$	387	$	137
Current liabilities:
Commodity contracts:
Electricity	$	93	$	36
Natural gas	25		11
Total current derivative liabilities	118		47
Noncurrent liabilities:
Commodity contracts:
Electricity	53		87
Natural gas	22		3
Total noncurrent derivative liabilities	75		90

Total derivative liabilities(2)	$	193	$	137

(1)Total current derivative assets is included in Other current assets, and Total noncurrent derivative assets is included in Other noncurrent assets on the consolidated balance sheets.

(2)As of December 31, 2022 and 2021, no commodity derivative assets or liabilities were designated as hedging instruments.

Schedule of Derivative Instruments [Table Text Block]


	As of December 31,
	2022			2021
Commodity contracts:
Electricity	6		MWh	4		MWh
Natural gas	211		Dth	181		Dth
Foreign currency contracts	$	10	Canadian	$	19	Canadian

Derivatives Not Designated as Hedging Instruments [Table Text Block]


	Years Ended December 31,
	2022		2021		2020
Commodity contracts:
Electricity	$	(187)	$	(38)	$	160
Natural Gas	(388)		(177)		(34)
Foreign currency contracts	1		—		(1)

Schedule of Price Risk Derivatives [Table Text Block]


	2023		2024		2025		2026		2027		Thereafter		Total
Commodity contracts:
Electricity	$	(19)	$	10	$	21	$	(3)	$	(3)	$	(16)	$	(10)
Natural gas	(177)		(8)		(2)		3		—		—		(184)
Net unrealized (gain)/loss	$	(196)	$	2	$	19	$	—	$	(3)	$	(16)	$	(194)

- Definition

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

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+ Details

Summary of Significant Accounting Policies Estimated average service lives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Generation, excluding thermal:
Hydro	97 years
Wind	30 years
Transmission	61 years
Distribution	51 years
General	16 years
Other Investments	$ 150	$ 44

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2022
Basis of Presentation [Abstract]
Basis of Presentation	BASIS OF PRESENTATION Nature of Operations Portland General Electric Company (PGE or the Company) is a single, vertically-integrated electric utility engaged in the generation, purchase, transmission, distribution, and retail sale of electricity in the state of Oregon (State). The Company also participates in the wholesale market by purchasing and selling electricity and natural gas in an effort to obtain reasonably-priced power for its retail customers. PGE continues to develop products and service offerings for the benefit of retail and wholesale customers. PGE operates as a single segment, with revenues and costs related to its business activities maintained and analyzed on a total electric operations basis. The Company owns unregulated, non-utility real estate comprised primarily of PGE’s corporate headquarters. The Company’s corporate headquarters is located in Portland, Oregon and its approximately four thousand square mile, State-approved service area is located entirely within the State. PGE’s allocated service area includes 51 incorporated cities. As of December 31, 2022, PGE served approximately 926 thousand retail customers with a service area population of approximately 1.9 million. As of December 31, 2022, PGE had 2,873 employees in its workforce, with 673 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. One agreement covers 610 employees and expires March 2025, and the other covers 63 employees and expires August 2027. PGE also utilizes independent contractors and temporary personnel to supplement its workforce. PGE is subject to the jurisdiction of the Public Utility Commission of Oregon (OPUC) with respect to retail prices, utility services, accounting policies and practices, issuances of securities, and certain other matters. Retail prices are based on the Company’s cost to serve customers, including an opportunity to earn a reasonable rate of return, as determined by the OPUC. The Company is also subject to regulation by the Federal Energy Regulatory Commission (FERC) in matters related to wholesale energy transactions, transmission services, reliability standards, natural gas pipelines, hydroelectric project licensing, accounting policies and practices, short-term debt issuances, and certain other matters. Consolidation Principles The consolidated financial statements include the accounts of PGE and its wholly-owned subsidiaries. The Company’s ownership share of direct expenses and costs related to jointly-owned generating plants are also included in its consolidated financial statements. For further information on PGE’s jointly-owned plant, see Note 18, Jointly-Owned Plant. Intercompany balances and transactions have been eliminated. Use of Estimates The preparation of financial statements in accordance with accounting principles generally accepted in the United States of America (GAAP) requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, and disclosures of gain or loss contingencies, as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ materially from those estimates. Reclassifications To conform with current year presentation, the Company has reclassified $2 million from Debt extinguishment costs to Other in the financing activities section of the consolidated statements of cash flows for the year ended December 31, 2020 and $2 million from Contribution to pension and other postretirement plans to Other, net in the operating activities section of the consolidated statements of cash flows for the years ended December 31, 2021 and 2020, respectively.

Income Taxes Schedule of Effective Income Tax Rate Reconciliation (Details)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Abstract]
Federal statutory tax rate	21.00%	21.00%	21.00%
State and local taxes, net of federal tax benefit	8.80%	8.90%	10.10%
Flow through depreciation and cost basis differences	0.80%	(0.20%)	(4.90%)
Effective Income Tax Rate Reconciliation, Tax Settlement, State and Local, Percent	0.00%	(3.20%)	0.00%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Amortization, Percent	(4.50%)	(4.80%)	(4.70%)
Other	(0.20%)	(1.20%)	(1.00%)
Effective tax rate	14.30%	8.60%	0.00%
Effective Income Tax Rate Reconciliation, Tax Credit, Percent	(11.60%)	(11.90%)	(20.50%)

Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Shares Outstanding, Basic	89,290	89,481	89,485
Weighted Average Number Diluted Shares Outstanding Adjustment	353	146	160
Weighted Average Number of Shares Outstanding, Diluted	89,643	89,627	89,645

Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 170	$ 139
Utility plant	86	95
Non-utility property	33	35
Asset Retirement Obligation	289	269	$ 291	$ 279
Asset Retirement Obligation, Current	32	31
Asset Retirement Obligations, Noncurrent	257	238
Asset Retirement Obligation, Cash Paid to Settle	$ (27)	$ (18)	$ (18)

Leases Maturities of Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Year Two	$ 3
Lessee, Operating Lease, Liability, Payments, Due Year Three	1
Lessee, Operating Lease, Liability, Payments, Due Year Four	1
Lessee, Operating Lease, Liability, Payments, Due Year Five	1
Lessee, Operating Lease, Liability, Payments, Due after Year Five	42
Lessee, Operating Lease, Liability, Payments, Due	52
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(30)
Operating Lease, Liability	22	$ 26
Finance Lease, Liability, Payments, Due Year One	20
Finance Lease, Liability, Payments, Due Year Two	20
Finance Lease, Liability, Payments, Due Year Three	27
Finance Lease, Liability, Payments, Due Year Four	27
Finance Lease, Liability, Payments, Due Year Five	27
Finance Lease, Liability, Payments, Due after Year Five	382
Finance Lease, Liability, Payment, Due	503
Finance Lease, Liability, Undiscounted Excess Amount	(189)
Finance Lease, Liability	314	$ 293
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 4

Leases Supplemental Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 22	$ 25
Operating Lease, Liability, Current	4	4
Operating Lease, Liability, Noncurrent	18	22
Operating Lease, Liability	22	26
Finance Lease, Right-of-Use Asset	305	291
Finance Lease, Liability, Current	20	20
Finance Lease, Liability, Noncurrent	294	273
Finance Lease, Liability	$ 314	$ 293

Revenue Recogniton Revenue Recognition (Policies)	12 Months Ended
Revenue Recogniton Revenue Recognition (Policies)	Dec. 31, 2022
Revenue Recognition [Abstract]
Revenue from Contract with Customer [Policy Text Block]	PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Revenue, Transaction Price Measurement, Tax Exclusion [Policy Text Block]	Pursuant to regulation by the OPUC, PGE is mandated to maintain several tariff schedules to collect funds from customers for programs that benefit the general public, such as conservation, low-income housing, energy efficiency, renewable energy programs, and privilege taxes. For such programs, PGE generally collects the funds and remits the amounts to third party agencies that administer the programs. In these arrangements, PGE is considered to be an agent, as PGE’s performance obligation is to facilitate a transaction between customers and the administrators of these programs. Therefore, such amounts are presented on a net basis and do not appear in Revenues, net within the consolidated statements of income.
Utility, Revenue and Expense Recognition, Policy [Policy Text Block]	PGE’s Wholesale revenues are primarily short-term electricity sales to utilities and power marketers that consist of single performance obligations that are satisfied as energy is transferred to the counterparty. The Company may choose to net certain purchase and sale transactions in which it would simultaneously receive and deliver physical power with the same counterparty; in such cases, only the net amount of those purchases or sales required to meet retail and wholesale obligations will be physically settled and recorded in Wholesale revenues.

- Definition

Disclosure of accounting policy for revenue from contract with customer.

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+ Details

Long-Debt Lesse, Operating Lease, Liability Maturity (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt Disclosure [Abstract]
Leveraged Leases, Balance Sheet, Investment in Leveraged Leases	$ 88
Unrecorded Unconditional Purchase Obligation, Imputed Interest	(61)
Leveraged Leases, Balance Sheet, Investment in Leveraged Leases, Net	27
Finance Lease, Liability, Payments, Due in Rolling Year Two	2
Finance Lease, Liability, Payments, Due in Rolling Year Three	5
Finance Lease, Liability, Payments, Due in Rolling Year Four	5
Finance Lease, Liability, Payments, Due in Rolling Year Five	5
Finance Lease, Liability, Payments, Due in Rolling after Year Five	69
Finance Lease, Liability, Payments, Due in Next Rolling 12 Months	$ 2

Commitments and Guarantees (Tables)

12 Months Ended

Dec. 31, 2022

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure [Table Text Block]

As of December 31, 2022, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):


	Payments Due
	2023		2024		2025		2026		2027		Thereafter		Total
Capital and other purchase commitments	$	239	$	70	$	36	$	5	$	2	$	43	$	395
Purchased power and fuel:
Electricity purchases	457		449		428		303		309		3,653		5,599
Capacity contracts	17		17		20		5		5		69		133
Public utility districts	12		12		11		10		9		23		77
Natural gas	158		43		38		37		30		202		508
Coal and transportation	27		27		27		—		—		—		81
Total	$	910	$	618	$	560	$	360	$	355	$	3,990	$	6,793

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

PGE has long-term power purchase agreements with certain public utility districts (PUDs) in the state of Washington:

•Grant County PUD for the Priest Rapids and Wanapum Hydroelectric Projects, and

•Douglas County PUD for the Wells Hydroelectric Project.

Selected information regarding these projects is summarized as follows (dollars in millions):


	Capacity Charges and Revenue Bonds as of December 31, 2022		PGE’s Average Share as of December 31, 2022			Contract Expiration	Total PGE Contract Costs
			Output		Capacity		2022		2021		2020
					(in MW)
Priest Rapids and Wanapum	$	2,042	8.6	%	163	2052	$	45	$	26	$	25
Wells	421		18.8		113	2028	12		13		23

Employee Benefits (Policies)	12 Months Ended
Employee Benefits (Policies)	Dec. 31, 2022
Employee Benefits [Abstract]
pension and other postretirement benefits valuation methodology [Policy Text Block]	The following discussion provides information regarding the methods used in valuation of the various asset class investments held in the pension and other postretirement benefit plan trusts. Money market funds—PGE invests in money market funds that seek to maintain a stable NAV. These funds invest in high-quality, short-term, diversified money market instruments, short-term treasury bills, federal agency securities, or certificates of deposit. Some of the money market funds held in the trusts are classified as Level 1 instruments as pricing inputs are based on unadjusted prices in an active market. The remaining money market funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Equity securities—Equity mutual fund and common stock securities are classified as Level 1 securities as pricing inputs are based on unadjusted prices in an active market. Principal markets for equity prices include published exchanges such as NASDAQ and NYSE. Mutual fund assets included in separately managed accounts are classified as Level 2 securities due to pricing inputs that are directly or indirectly observable in the marketplace. Debt Securities—Debt security investment funds are classified as Level 2 securities as pricing for underlying securities are determined by evaluating pricing data, such as broker quotes for similar securities, adjusted for observable differences. Significant inputs used in valuation models generally include benchmark yield and issuer spreads. The external credit rating, coupon rate, and maturity of each security are considered in the valuation, if applicable. Collective trust funds—Domestic and international mutual fund assets and debt security assets, including municipal debt and corporate credit securities, mortgage-backed securities, and asset back securities assets, are included in commingled trusts or separately managed accounts. The Company believes the redemption value of the collective trust funds are likely to be the fair value, which is represented by the net asset value as a practical expedient. The funds are valued at NAV as a practical expedient and are not classified in the fair value hierarchy. Private equity funds—PGE invests in a combination of primary and secondary fund-of-funds, which hold ownership positions in privately held companies across the major domestic and international private equity sectors, including but not limited to, partnerships, joint ventures, venture capital, buyout, and special situations. Private equity investments are valued at NAV as a practical expedient and are not classified in the fair value hierarchy.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the obligations of the non-qualified benefit plans recognized in net income and the unfunded position.The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate.
Pension and Other Postretirement Plans, Nonpension Benefits, Policy [Policy Text Block]	The assets of these plans are held in voluntary employees’ beneficiary association trusts and are comprised of money market funds, equity securities, common and collective trust funds, partnerships/joint ventures, and registered investment companies, all of which are recorded at fair value. Postretirement health and life insurance benefit plan calculations include several assumptions that are reviewed annually by PGE and updated as appropriate, with measurement dates of December 31.
Non-qualified benefit [Policy Text Block]	Non-Qualified Benefit Plan—The NQBP in the following tables include obligations for a Supplemental Executive Retirement Plan and a directors pension plan, both of which were closed to new participants in 1997. The NQBP also includes pension make-up benefits for employees that participate in the Management Deferred Compensation Plan (MDCP). Investments in the NQBP trust, consisting of trust-owned life insurance policies and marketable securities, provide partial funding for the future requirements of these plans. The assets of such trust are included in the accompanying tables for informational purposes only and are not considered segregated and restricted under current accounting standards. The investments in marketable securities, consisting of money market, bonds, and equity mutual funds, are classified as equity or trading debt securities and recorded at fair value. The measurement date for the NQBP is December 31. For further information regarding these trust investments, see Note 5, Fair Value of Financial Instruments. Other NQBP—In addition to the NQBP discussed above, PGE provides certain employees and outside directors with deferred compensation plans, whereby participants may defer a portion of their earned compensation. PGE holds investments in a NQBP trust that are intended to be a funding source for these plans.

Future year net unrealized gain/loss recorded at balance sheet date expected to become realized (Details) $ in Millions	Dec. 31, 2022 USD ($)
Electricity [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	$ (19)
Other Commitment, Due in Second Year	10
Other Commitment, Due in Third Year	21
Other Commitment, Due in Fourth Year	(3)
Other Commitment, Due in Fifth Year	(3)
Other Commitment, Due after Fifth Year	(16)
Total	(10)
Natural Gas [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	(177)
Other Commitment, Due in Second Year	8
Other Commitment, Due in Third Year	2
Other Commitment, Due in Fourth Year	(3)
Other Commitment, Due in Fifth Year	0
Other Commitment, Due after Fifth Year	0
Total	(184)
Unrealized Gain Loss On Derivatives [Member]
Commodity contracts:
Other Commitment, Due in Next Twelve Months	(196)
Other Commitment, Due in Second Year	2
Other Commitment, Due in Third Year	19
Other Commitment, Due in Fourth Year	0
Other Commitment, Due in Fifth Year	(3)
Other Commitment, Due after Fifth Year	(16)
Total	$ (194)

Equity-Based Plans	12 Months Ended
Equity-Based Plans	Dec. 31, 2022
Equity Based Plans [Abstract]
Stock Purchase Plan [Text Block]	EQUITY-BASED PLANS Equity Forward Sale Agreement On October 25, 2022, PGE entered into an equity forward sale agreement (EFSA) in connection with a public offering of 10,100,000 shares of its common stock. Effective October 28, 2022, pursuant to the terms of the EFSA, the forward counterparties borrowed 11,615,000 shares of PGE’s common stock, including 1,515,000 shares in connection with the underwriters’ exercise of their option to purchase additional shares, from third parties in the open market and sold the shares to a group of underwriters for $43.00 per share, less an underwriting discount equal to $1.23625 per share. PGE will not receive any proceeds from the sale of common stock until the EFSA is settled, and at that time PGE will record the proceeds, if any, in equity. Under the terms of the EFSA, PGE may elect to settle the equity forward transactions by means of physical, cash or net share settlement, in whole or in part, at any time on or prior to October 25, 2024, except in specified circumstances or events that would require physical settlement. To the extent that the transactions are physically settled, PGE would be required to issue and deliver shares of PGE common stock to the forward counterparty at the then applicable forward sale price. The forward sale price was initially determined to be $43.00 per share at the time the EFSA was entered into, and the amount of cash to be received by PGE upon physical settlement of the EFSA is subject to certain adjustments in accordance with the terms of the EFSA. PGE concluded that the EFSA was an equity instrument and that it qualified for an exception from derivative accounting because the EFSA was indexed to its own stock. PGE anticipates settling the EFSA through physical settlement on or before October 25, 2024. At December 31, 2022, the Company could have physically settled the EFSA by delivering 11,615,000 shares to the forward counterparty in exchange for cash of $483 million. Prior to settlement, the potentially issuable shares pursuant to the EFSA will be reflected in PGE’s diluted earnings per share calculations using the treasury stock method. Under this method, the number of shares of PGE’s common stock used in calculating diluted earnings per share for a reporting period would be increased by the number of shares, if any, that would be issued upon physical settlement of the EFSA less the number of shares that could be purchased by PGE in the market with the proceeds received from issuance (based on the average market price during that reporting period). Share dilution occurs when the average market price of PGE’s stock during the reporting period is higher than the average forward sale price during the reporting period. As of December 31, 2022, 201,003 incremental shares were included in the calculation of diluted EPS related to the securities under the EFSA. For additional information concerning the Company’s diluted earnings per share, see Note 15, Earnings Per Share. Employee Stock Purchase Plan PGE has an employee stock purchase plan (ESPP) under which a total of 625,000 shares of the Company’s common stock may be issued. The ESPP permits all eligible employees to purchase shares of PGE common stock through regular payroll deductions, which are limited to 10% of base pay. Each year, employees may purchase up to a maximum of $25,000 in common stock or 1,500 shares (based on fair value on the purchase date), whichever is less. Two six-month offering periods occur annually, January 1 through June 30 and July 1 through December 31, during which eligible employees may contribute toward the purchase of shares of PGE common stock. Purchases occur the last day of the offering period, at a price equal to 95% of the fair value of the stock on the purchase date. As of December 31, 2022, there were 177,145 shares available for future issuance pursuant to the ESPP. Dividend Reinvestment and Direct Stock Purchase Plan PGE has a Dividend Reinvestment and Direct Stock Purchase Plan (DRIP), under which a total of 2,500,000 shares of the Company’s common stock may be issued. Under the DRIP, investors may elect to buy shares of the Company’s common stock or elect to reinvest cash dividends in additional shares of the Company’s common stock. As of December 31, 2022, there were 2,458,622 shares available for future issuance pursuant to the DRIP.

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Revenues, net	$ 2,636	$ 2,425	$ 2,151
Alternative revenue programs, net of amortization	11	(29)	(6)
Total Revenues	2,647	2,396	2,145
Operating expenses:
Purchased power and fuel	988	822	708
Generation, transmission and distribution	348	310	293
Administrative and other	340	336	283
Depreciation and amortization	417	404	454
Taxes other than income taxes	157	146	138
Total operating expenses	2,250	2,018	1,876
Income from operations	397	378	269
Interest expense, net	156	137	136
Other income:
Allowance for equity funds used during construction	14	17	16
Miscellaneous income, net	17	9	6
Other income, net	31	26	22
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	272	267	155
Income tax expense	39	23	0
Net income	$ 233	$ 244	$ 155
Weighted-average shares outstanding (in thousands):
Basic	89,290	89,481	89,485
Diluted	89,643	89,627	89,645
Earnings per share:
Basic	$ 2.61	$ 2.72	$ 1.73
Diluted	$ 2.60	$ 2.72	$ 1.72

Net volumes related to price risk management activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2022 CAD ($) MWh MMBTU	Dec. 31, 2021 CAD ($) MWh MMBTU
Price Risk Management [Abstract]
Electricity \| MWh	6	4
Natural gas \| MMBTU	211	181
Foreign currency exchange \| $	$ 10	$ 19

Credit Facilities (Details) $ in Millions	12 Months Ended
Credit Facilities (Details) $ in Millions	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Line of Credit Facility [Line Items]
Maximum borrowing capacity	$ 750
Debt Instrument, Covenant Description	65.00%
Ratio of Indebtedness to Net Capital	0.569
Commercial Paper, Maximum Term	270 days
Commercial Paper	$ 0
FERC Authorized Short-term Debt, effective through February 6, 2014	900
Line of Credit Facility, Amount Outstanding	0
Line of Credit Facility, Remaining Borrowing Capacity	650
letter of credit facility	220
Line of Credit Facility, Current Borrowing Capacity	650
Letters of Credit Outstanding, Amount	$ 97	$ 18

Asset Retirement Obligations (Policies)	12 Months Ended
Asset Retirement Obligations (Policies)	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation [Policy Text Block]	Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred.The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, with such depreciation included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is included in Depreciation and amortization expense in the Company’s consolidated statements of income.Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Net realized losses	$ (2)	$ 5
Long-term Debt, Fair Value	2,984	3,831
Long-term Debt	3,659	3,299
Unamortized Debt Issuance Expense	13	14
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Notes Payable to Banks [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Long-term Debt	$ 3,646	$ 3,285

- Definition

Amount, excluding unamortized premium (discount) and debt issuance cost, of long-term debt. Excludes lease obligation.

+ References + Details

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2022

Earnings Per Share [Abstract]

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

The reconciliations of the denominators of the basic and diluted earnings per share computations are as follows (in thousands):


	Years Ended December 31,
	2022	2021	2020


Weighted average common shares outstanding—basic	89,290	89,481	89,485
Dilutive potential common shares	353	146	160
Weighted average common shares outstanding—diluted	89,643	89,627	89,645

Stock-based Compensation Expense

12 Months Ended

Dec. 31, 2022

Share-Based Payment Arrangement [Abstract]

Share-based Payment Arrangement [Text Block]

STOCK-BASED COMPENSATION EXPENSE


	Units	Weighted Average Grant Date Fair Value
Nonvested units as of December 31, 2019	463,390	$	43.52
Granted	202,883	56.45
Forfeited	(17,341)	50.27
Vested	(170,536)	45.67
Nonvested units as of December 31, 2020	478,396	48.00
Granted	318,844	43.01
Forfeited	(9,754)	48.35
Vested	(212,676)	40.33
Nonvested units as of December 31, 2021	574,810	48.07
Granted	271,696	51.29
Forfeited	(76,913)	49.48
Vested	(190,132)	49.11
Nonvested units as of December 31, 2022	579,461	49.23

A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 2,082,469 shares remain available for future issuance as of December 31, 2022.

Outstanding RSUs provide for the payment of one Dividend Equivalent Right (DER) for each stock unit. Each DER represents an amount equal to dividends paid to shareholders on a share of PGE’s common stock and vests on the same schedule as the related RSU. The DERs are settled in shares of PGE common stock valued either at the closing stock price on the vesting date (for performance-based RSUs) or dividend payment date (for all other grants).

Time-based RSUs generally vest over a period of up to three years from the grant date. The fair value of time-based RSUs is measured based on the closing price of PGE common stock on the date of grant and charged to compensation expense on a straight-line basis over the requisite service period for the entire award. The total value of time-based RSUs vested was $5 million for the year ended December 31, 2022, $3 million for 2021, and $1 million for 2020.

Performance-based RSUs vest based on the extent to which performance goals are met at the end of a three-year performance period, subject to adjustment by the Compensation, Culture and Talent Committee of PGE’s Board of Directors. The number of RSUs that may vest under the grants is based on three equally-weighted metrics: i) actual return on equity relative to allowed return on equity; ii) average EPS growth; and iii) average megawatts of forecast energy from clean or certain low-carbon emitting resources added to PGE’s energy supply portfolio—and relative

total shareholder return (TSR) as a modifier to the total of the three equally-weighted metrics. Based on the attainment of the goals, the number of RSUs that vest can range from zero to 200% of the RSUs granted.

For return on equity, average EPS growth and carbon reduction metrics of the performance-based RSUs, fair value is measured based on the NYSE closing price of PGE common stock on the date of grant. For the TSR portion of the performance-based RSUs, fair value is determined using a Monte Carlo simulation with the following weighted average assumptions:


	2022					2021					2020
Risk-free interest rate				1.7	%				0.2	%				1.4	%

Expected term (in years)				2.9					2.9					2.9
Volatility	26.4	%	-	37.9	%	26.1	%	-	37.9	%	13.5	%	-	97.3	%

There is no expected dividend yield used in the valuation, as it is assumed that all dividends distributed during the performance period are reinvested in the Company’s underlying stock. The fair value of performance-based RSUs is charged to compensation expense on a straight-line basis over the requisite service period for the entire award based on the number of shares expected to vest. Stock-based compensation expense was calculated assuming the attainment of performance goals that would allow the weighted average vesting of 118.7%, 88.6%, and 110.6% of awarded performance-based RSUs for the respective 2022, 2021, and 2020 grants, with an estimated 5% forfeiture rate.

The total value of performance-based RSUs vested was $6 million for the year ended December 31, 2022, $7 million for 2021, and $9 million for 2020.

Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $15 million for the year ended December 31, 2022, $14 million for 2021, and $11 million in 2020. Such amounts differ from those reported in the consolidated statements of shareholders’ equity for stock-based compensation due primarily to the impact from the income tax payments made on behalf of employees. The Company withholds a portion of the vested shares for the payment of income taxes on behalf of the employees. Not included in Administrative and other expenses in the consolidated statements of income, is the net impact from these income tax payments, partially offset by the issuance of DERs, resulting in a charge to shareholders’ equity of $4 million in 2022, $1 million in 2021, and $2 million in 2020.

As of December 31, 2022, unrecognized stock-based compensation expense was $13 million, which is expected to be recognized over a weighted average period of one to three years. No stock-based compensation costs have been capitalized.

Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2022

Line of Credit Facility [Abstract]

Schedule of Short-term Debt [Table Text Block]

Short-term borrowings under these credit facilities, and related interest rates, are reflected in the following table (dollars in millions).


	Year Ended December 31,
	2022			2021			2020
Average daily amount of short-term debt outstanding	$	2		$	139		$	131
Weighted daily average interest rate *	3.4		%	0.9		%	1.5		%
Maximum amount outstanding during the year	$	135		$	230		$	225

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

Employee Benefits Assets and Liabilities associated with Non-qualified benefit plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Document Period End Date	Dec. 31, 2022
Non-qualified benefit plan trust	$ 38	$ 45
Non-qualified benefit plan liabilities	83	95
OtherPostretirementDefinedBenefitPlanLiabilityCurrent	2	2
Other Postretirement Benefit Plans [Domain]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	0	0
Defined Benefit Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	19	24
Non-qualified benefit plan liabilities	67	70
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	19	21
Non-qualified benefit plan liabilities	$ 16	$ 25

Summary of Significant Accounting Policies (Policies)	12 Months Ended
Summary of Significant Accounting Policies (Policies)	Dec. 31, 2022
Summary of Significant Accounting Policies [Abstract]
Cash and Cash Equivalents, Policy [Policy Text Block]	Highly liquid investments with maturities of three months or less at the date of acquisition are classified as cash equivalents,
Accounts Receivable [Policy Text Block]	Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and State (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning 8 business days after the invoice due date. Accounts that are inactivated due to nonpayment are charged-off in the period in which the receivable is deemed uncollectible, but no sooner than 45 business days after the due date of the final invoice. During 2020, 2021, and much of 2022, the Company took steps to support customers during the COVID-19 pandemic, including suspending late fees and developing time payment arrangements. COVID-19 protections ended in September 2022. Provisions for uncollectible accounts receivable and unbilled revenues related to retail sales are charged to Administrative and other expense and are recorded in the same period as the related revenues, with an offsetting credit to the allowance for uncollectible accounts. Such estimates for credit losses are based on management’s assessment of the current and forecasted probability of collection, aging of accounts receivable, bad debt write-offs experience, actual customer billings, economic conditions, and other factors that help determine credit loss estimates for accounts receivable and unbilled revenues. For more information on PGE’s provision for uncollectible accounts receivable and unbilled revenues see “Accounts Receivable, Net” in Note 4, Balance Sheet Components. A portion of PGE’s provision for uncollectible accounts receivable and unbilled revenues is deferred as a regulatory asset, for more information see “COVID-19” in Note 7, Regulatory Assets and Liabilities. Provisions for uncollectible accounts receivable related to wholesale sales are charged to Purchased power and fuel expense and are recorded periodically based on a review of counterparty non-performance risk and contractual right of offset when applicable.
Derivatives, Policy [Policy Text Block]	PGE engages in price risk management activities, utilizing financial instruments such as forward, future, swap, and option contracts for electricity, natural gas, and foreign currency. These instruments are measured at fair value and recorded on the consolidated balance sheets as assets or liabilities from price risk management activities. Changes in fair value are recognized in the consolidated statements of income, offset by the effects of regulatory accounting when it is expected that the gain or loss upon settlement will be reflected in future retail rates. Certain electricity forward contracts that were entered into in anticipation of serving the Company’s regulated retail load may meet the requirements for treatment under the normal purchases and normal sales scope exception. Such contracts are not recorded at fair value and are recognized under accrual accounting. Price risk management activities are utilized as economic hedges to protect against variability in expected future cash flows due to associated price risk and to manage exposure to volatility in net variable power costs (NVPC). In accordance with ratemaking and cost recovery processes authorized by the OPUC, PGE recognizes a regulatory asset or liability to defer unrealized losses or gains, respectively, on derivative instruments until settlement. At the time of settlement, the Company recognizes a realized gain or loss on the derivative instrument. Physically settled electricity and natural gas sale and purchase transactions are recorded in Revenues, net and Purchased power and fuel expense, respectively, upon settlement, while transactions that are not physically settled (financial transactions) are recorded on a net basis in Purchased power and fuel expense upon financial settlement.Pursuant to transactions entered into in connection with PGE’s price risk management activities, the Company may be required to provide collateral to certain counterparties. The collateral requirements are based on the contract terms and commodity prices and can vary period to period.
Cash and Cash Equivalents, Restricted Cash and Cash Equivalents, Policy [Policy Text Block]	Cash deposits provided as collateral are included within Other current assets in the consolidated balance sheets
Off-Balance-Sheet Credit Exposure, Policy [Policy Text Block]	Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheets
Inventory, Policy [Policy Text Block]	PGE’s inventories, which are recorded at average cost, consist primarily of materials and supplies for use in operations, maintenance, and capital activities, as well as fuel, which includes natural gas, coal, and oil for use in the Company’s generating plants. Periodically, the Company assesses inventory for purposes of determining that inventories are recorded at the lower of average cost or net realizable value.
Property, Plant and Equipment, Policy [Policy Text Block]	Electric utility plant is capitalized at original cost, which includes direct labor, materials and supplies, and contractor costs, as well as indirect costs such as engineering, supervision, employee benefits, and an allowance for funds used during construction (AFUDC). Plant replacements are capitalized, with minor items charged to expense as incurred. Periodic major maintenance inspections and overhauls at PGE’s generating plants are charged to expense as incurred, subject to regulatory accounting as applicable. Costs to purchase or develop software applications for internal use only are capitalized and amortized over the estimated useful life of the software. Costs of obtaining FERC licenses for the Company’s hydroelectric projects are capitalized and amortized over the related license period.During the period of construction, costs expected to be included in the final value of the constructed asset, and depreciated once the asset is complete and placed in service, are classified as Construction work-in-progress in Electric utility plant on the consolidated balance sheets. If the project becomes probable of being abandoned, such costs are expensed in the period such determination is made.
Allowance for Funds Used During Construction, Policy [Policy Text Block]	PGE records AFUDC, which is intended to represent the Company’s cost of funds used for construction purposes, based on the rate granted in the latest general rate case for equity funds and the cost of actual borrowings for debt funds. In 2020, the FERC issued a waiver that allowed jurisdictional utilities to apply an alternative AFUDC calculation formula that excluded the actual outstanding short-term debt balance and replaced it with the simple average of the actual 2019 short-term debt balance. PGE adopted the waiver in the second quarter of 2020. The purpose of the waiver, which ultimately expired March 31, 2022, was to allow relief from the detrimental impacts of issuing short-term debt on the allowance for equity funds used during construction in response to COVID-19. AFUDC is capitalized as part of the cost of plant and credited to the consolidated statements of income.
Regulatory Depreciation and Amortization, Policy [Policy Text Block]	Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage.
Depreciation Lives [Policy Text Block]	Thermal generation plants are depreciated using a life-span methodology which ensures that plant investment is recovered by the estimated retirement dates, which range from 2025 to 2061. Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives,
Plant Retirement and Abandonment, Policy [Policy Text Block]	When property is retired and removed from service, the original cost of the depreciable property units, net of any related salvage value, is charged to accumulated depreciation. Cost of removal expenditures are recorded against AROs or to accumulated asset retirement removal costs, if applicable, and included in Regulatory liabilities.
Goodwill and Intangible Assets, Intangible Assets, Policy [Policy Text Block]	Intangible plant consists primarily of computer software development costs, which are amortized over either five or ten years, and hydro licensing costs, which are amortized over the applicable license term, which range from 30 to 50 years.
Marketable Securities, Policy [Policy Text Block]	All of PGE’s investments in marketable securities included in NDT and NQBP trust on the consolidated balance sheets, are classified as equity or trading debt securities. These securities are classified as noncurrent because they are not available for use in operations. Such securities are stated at fair value based on quoted market prices. Realized and unrealized gains and losses on the NQBP trust assets are included in Other income, net. Realized and unrealized gains and losses on the NDT fund assets are recorded as regulatory liabilities or assets, respectively, for future ratemaking treatment. The cost of securities sold in the NDT and the NQBP are based on the first in first out method.
Public Utilities, Policy [Policy Text Block]	PGE applies regulatory accounting, which results in the creation of regulatory assets and regulatory liabilities. Regulatory assets represent: i) probable future revenue associated with certain actual or estimated costs that are expected to be recovered from customers through the ratemaking process; or ii) probable future collections from customers resulting from revenue accrued for completed alternative revenue programs, provided certain criteria are met. Regulatory liabilities represent probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process. Regulatory accounting is appropriate as long as: i) prices are established by, or subject to, approval by independent third-party regulators; ii) prices are designed to recover the specific enterprise’s cost-of-service; and iii) in view of demand for service, it is reasonable to assume that prices set at levels that will recover costs can be charged to and collected from customers. Once the regulatory asset or liability is reflected in prices, the respective regulatory asset or liability is amortized to the appropriate line item in the consolidated statement of income over the period in which it is included in prices.Circumstances that could result in the discontinuance of regulatory accounting include: i) increased competition that restricts PGE’s ability to establish prices to recover specific costs; and ii) a significant change in the manner in which prices are set by regulators from cost-based regulation to another form of regulation. The Company periodically reviews the criteria of regulatory accounting to ensure that its continued application is appropriate.
Power Cost [Policy Text Block]	PGE is subject to a Power Cost Adjustment Mechanism (PCAM), as approved by the OPUC. Pursuant to the PCAM, future customer prices can be adjusted to reflect a portion of the difference between: i) NVPC forecast each year and included in customer prices (baseline NVPC); and ii) actual NVPC for the year. NVPC consists of the cost of power purchased and fuel used to generate electricity to meet PGE’s retail load requirements, as well as the cost of settled electric and natural gas financial contracts, all of which is classified as Purchased power and fuel in the Company’s consolidated statements of income, and is net of wholesale sales, which are classified as Revenues, net in the consolidated statements of income. The Company is subject to a portion of the business risk or benefit associated with the difference between actual and baseline NVPC by application of an asymmetrical deadband, which ranges from $15 million below to $30 million above baseline NVPC. To the extent actual NVPC, subject to certain adjustments, is outside the deadband range, the PCAM provides for 90% of the excess variance to be collected from, or refunded to, customers. Pursuant to a regulated earnings test, a refund will occur only to the extent that it results in PGE’s actual regulated return on equity (ROE) for the given year being no less than 1% above the Company’s latest authorized ROE, while a collection will occur only to the extent that it results in PGE’s actual regulated ROE for that year being no greater than 1% below the Company’s authorized ROE.
Asset Retirement Obligation [Policy Text Block]	Legal obligations related to the future retirement of tangible long-lived assets are classified as AROs on PGE’s consolidated balance sheets. An ARO is recognized in the period in which the legal obligation is incurred, and when the fair value of the liability can be reasonably estimated. Due to the long lead time involved until decommissioning activities occur, the Company uses present value techniques. The present value of estimated future decommissioning costs is capitalized and included in Electric utility plant, net on the consolidated balance sheets with a corresponding offset to ARO. For revisions to AROs in which the related asset is no longer in service, the corresponding offset is recorded as a Regulatory asset on the consolidated balance sheets, except for those AROs related to non-utility assets which is charged to Depreciation and amortization on the consolidated statements of income. Such estimates are revised periodically, with actual settlements charged to the ARO as incurred.The estimated capitalized costs of AROs are depreciated over the estimated life of the related asset, with such depreciation included in Depreciation and amortization in the consolidated statements of income. Changes in the ARO resulting from the passage of time (accretion) is based on the original discount rate and recognized as an increase in the carrying amount of the liability and as a charge to accretion expense, which is included in Depreciation and amortization expense in the Company’s consolidated statements of income.Pursuant to regulation, the amortization of utility plant AROs is included in depreciation expense and in customer prices. Any differences in the timing of recognition of costs for financial reporting and ratemaking purposes are deferred as a regulatory asset or regulatory liability.
Commitments and Contingencies, Policy [Policy Text Block]	Contingencies are evaluated using the best information available at the time the consolidated financial statements are prepared. Legal costs incurred in connection with loss contingencies are expensed as incurred. Loss contingencies, including environmental contingencies, are accrued, and disclosed if material, when it is probable that an asset has been impaired, or a liability incurred, as of the financial statement date and the amount of the loss can be reasonably estimated. If a reasonable estimate of probable loss cannot be determined, a range of loss may be established, in which case the minimum amount in the range is accrued, unless some other amount within the range appears to be a better estimate. A loss contingency will also be disclosed when it is reasonably possible that a liability has been incurred if the estimate or range of potential loss is material. If a probable or reasonably possible loss cannot be determined, then the Company: i) discloses an estimate of such loss or the range of such loss, if the Company is able to determine such an estimate; or ii) discloses that an estimate cannot be made and the reasons why the estimate cannot be made. If an asset has been impaired or a liability incurred after the financial statement date, but prior to the issuance of the financial statements, the loss contingency is disclosed, if material, and the amount of any estimated loss is recorded in either the current or the subsequent reporting period, depending on the nature of the underlying event. Gain contingencies are recognized when realized and are disclosed when material. For additional information concerning the Company’s contingencies, see Note 19, Contingencies. 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.PGE evaluates, on a quarterly basis, developments in such matters that could affect the amount of any accrual, as well as the likelihood of developments that would make a loss contingency both probable and reasonably estimable. The assessment as to whether a loss is probable or reasonably possible, and as to whether such loss or a range of such loss is estimable, often involves a series of complex judgments about future events. Management is often unable to estimate a reasonably possible loss, or a range of loss, particularly in cases in which: i) the damages sought are indeterminate or the basis for the damages claimed is not clear; ii) the proceedings are in the early stages; iii) discovery is not complete; iv) the matters involve novel or unsettled legal theories; v) significant facts are in dispute; vi) a large number of parties are represented (including circumstances in which it is uncertain how liability, if any, would be shared among multiple defendants); or vii) a wide range of potential outcomes exist. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution, including any possible loss, fine, penalty, or business impact.
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	Accumulated other comprehensive loss (AOCL) presented on the consolidated balance sheets is comprised of the difference between the obligations of the non-qualified benefit plans recognized in net income and the unfunded position.The assets of the pension plan are held in a trust and are comprised of equity and debt instruments, all of which are recorded at fair value. Pension plan calculations include several assumptions that are reviewed annually and updated as appropriate.
Revenue [Policy Text Block]	Revenue is recognized when obligations under the terms of a contract with customers are satisfied. Generally, this satisfaction of performance obligations and transfer of control occurs and revenues are recognized as electricity is delivered to customers, including any services provided.
Franchise Tax [Policy Text Block]	Franchise taxes, which are collected from customers and remitted to taxing authorities, are recorded on a gross basis in PGE’s consolidated statements of income. Amounts collected from customers are included in Revenues, net and amounts due to taxing authorities are included in Taxes other than income taxes
Trade and Other Accounts Receivable, Unbilled Receivables, Policy [Policy Text Block]	Retail revenue is billed based on monthly meter readings taken at various cycle dates throughout the month. At the end of each month, PGE estimates the revenue earned from energy deliveries that remained unbilled to customers. The unbilled revenues estimate, which is included in Accounts receivable, net in the Company’s consolidated balance sheets, is calculated based on actual net retail system load each month, the number of days from the last meter read date through the last day of the month, and current customer prices. As a rate-regulated utility, PGE, in certain situations, recognizes revenue to be billed to customers in future periods or defers the recognition of certain revenues to the period in which the related costs are incurred or approved by the OPUC for amortization.
Share-based Payment Arrangement [Policy Text Block]	The measurement and recognition of compensation expense for all share-based payment awards, including restricted stock units, is based on the estimated fair value of the awards. The fair value of the portion of the award that is ultimately expected to vest is recognized as expense over the requisite vesting period. PGE attributes the value of stock-based compensation to expense on a straight-line basis.
Income Tax, Policy [Policy Text Block]	Income taxes are accounted for under the asset and liability method, which requires the recognition of deferred tax assets and liabilities for the expected future tax consequences of temporary differences between financial statement carrying amounts and tax bases of assets and liabilities. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities of a change in tax rates is recognized in income in current and future periods that includes the enactment date. Any valuation allowance would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized in future tax returns.Because PGE is a rate-regulated enterprise, changes in certain deferred tax assets and liabilities are required to be passed on to customers through future prices and are charged or credited directly to a regulatory asset or regulatory liability.
Income Tax Uncertainties, Policy [Policy Text Block]	Unrecognized tax benefits represent management’s expected treatment of a tax position taken in a filed tax return or planned to be taken in a future tax return, that has not been reflected in measuring income tax expense for financial reporting purposes. Until such positions are no longer considered uncertain, PGE would not recognize the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheets.
Interest and Penalties Related to Income Taxes [Policy Text Block]	PGE records any interest and penalties related to income tax deficiencies in Interest expense and Other income, net, respectively, in the consolidated statements of income.

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current assets:
Cash and cash equivalents	$ 165	$ 52
Accounts receivable, net	398	329
Inventories, at average cost:
Materials and supplies	63	51
Fuel	32	27
Regulatory assets--current	54	24
Other current assets	498	205
Total current assets	1,210	688
Electric utility plant:
In service	12,421	11,838
Accumulated depreciation and amortization	(4,423)	(4,146)
In service, net	7,998	7,692
Public Utilities, Property, Plant and Equipment, Net	8,465	8,005
Construction work-in-progress	467	313
Regulatory assets--noncurrent	473	533
Nuclear decommissioning trust	39	47
Non-qualified benefit plan trust	38	45
Other noncurrent assets	234	176
Total assets	10,459	9,494
Current liabilities:
Accounts payable	457	244
Liabilities from price risk management activities-current	118	47
Current portion of long-term debt	260	0
Current portion of long-term debt	20	20
Accrued expenses and other current liabilities	641	457
Total current liabilities	1,496	768
Long-term debt, net of current portion	3,386	3,285
Regulatory liabilities--noncurrent	1,389	1,360
Deferred income taxes	439	413
Unfunded status of pension and postretirement plans	170	206
Liabilities from price risk management activities--noncurrent	75	90
Asset retirement obligations	257	238
Non-qualified benefit plan liabilities	83	95
Finance lease obligations, net of current portion	294	273
Other noncurrent liabilities	91	59
Total liabilities	7,680	6,787
Commitments and Contingencies (see notes)
Shareholders’ equity:
Preferred stock, no par value, 30,000,000 shares authorized; none issued and outstanding	0	0
Common stock, no par value, 160,000,000 shares authorized; 89,283,353 and 89,410,612 shares issued and outstanding as of December 31, 2022 and 2021, respectively	1,249	1,241
Accumulated other comprehensive loss	(4)	(10)
Retained earnings	1,534	1,476
Total shareholders' equity	2,779	2,707
Total liabilities and shareholders' equity	$ 10,459	$ 9,494
Preferred Stock, Shares Outstanding	0	0
Preferred Stock, Shares Issued	0	0
Preferred Stock, Shares Authorized	30,000,000	30,000,000
Preferred Stock, No Par Value	$ 0	$ 0
Common Stock, Shares, Outstanding	89,283,353	89,410,612
Common Stock, Shares, Issued	89,283,353	89,410,612
Common Stock, No Par Value	$ 0	$ 0
Common Stock, Shares Authorized	160,000,000	160,000,000

Net realized and unrealized gains and losses on derivative transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Commodity contracts: [Abstract]
Electricity	$ (187)	$ (38)	$ 160
Natural Gas	(388)	(177)	(34)
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency	$ 1	$ 0	$ (1)

Leases Lease Obligations (Tables)

12 Months Ended

Dec. 31, 2022

Leases [Abstract]

Lease, Cost [Table Text Block]

The components of lease cost were as follows (in millions):


	2022		2021

Operating lease cost	$	4	$	8
Finance lease cost:
Amortization of right-of-use assets	$	14	$	7
Interest on lease liabilities	15		11
Total finance lease cost	$	29	$	18

Variable lease cost	$	31	$	24

Lease term and discount rates were as follows:


	December 31, 2022		December 31, 2021
Weighted Average Remaining Lease Term (in years)
Operating leases	44		40
Finance leases	22		23
Weighted Average Discount Rate
Operating leases	3.9	%	3.8	%
Finance leases	4.9	%	5.0	%

Lessee, Operating Leases

Supplemental information related to amounts and presentation of leases in the consolidated balance sheets is presented below (in millions):


	Balance Sheet Classification	As of December 31,
		2022		2021
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	22	$	25

Current liabilities	Accrued expenses and other current liabilities	$	4	$	4
Noncurrent liabilities	Other noncurrent liabilities	18		22
Total operating lease liabilities *		$	22	$	26
Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	305	$	291

Current liabilities	Current portion of finance lease obligations	$	20	$	20
Noncurrent liabilities	Finance lease obligations, net of current portion	294		273
Total finance lease liabilities *		$	314	$	293

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

As of December 31, 2022, maturities of lease liabilities were as follows (in millions):


	Operating Leases		Finance Leases

2023	$	4	$	20
2024	3		20
2025	1		27
2026	1		27
2027	1		27
Thereafter	42		382
Total lease payments	52		503
Less imputed interest	(30)		(189)
Total	$	22	$	314

Schedule of Cash Flow, Supplemental Disclosures [Table Text Block]

Supplemental cash flow information related to leases for the years indicated was as follows (in millions):


	2022		2021		2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	4	$	8	$	8
Operating cash flows from finance leases	15		11		10
Financing cash flows from finance leases	7		6		$	6
Right-of-use assets obtained in leasing arrangements:
Operating leases	$	—	$	(12)	$	—
Finance leases	29		153		—

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2022

Regulatory Assets [Line Items]

Schedule of Regulatory Liabilities [Table Text Block]

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


	Remaining Amortization Period	As of December 31,
		2022						2021
		Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	1	$	1	$	55
Pension and other postretirement plans	(3)	—		95		95		131


Debt issuance costs	2049	—		21		21		23
Trojan decommissioning activities	2059	—		133		133		90
February 2021 ice storm and damage	(4)	74		—		74		67
Power cost adjustment mechanism	(5)	28		—		28		29
2020 Labor Day wildfire	(4)	31		—		31		45
COVID-19	(6)	22		—		22		36
Wildfire mitigation	(6)	28		—		28		—
Other	Various	70		24		94		81
Total regulatory assets		$	253	$	274	$	527	$	557
Regulatory liabilities:
Asset retirement removal costs	(7)	$	1,136	$	—	$	1,136	$	1,047
Deferred income taxes	(8)	194		—		194		208

Asset retirement obligations	(7)	7		—		7		43

Price risk management	(2)	—		195		195		55
Other	Various	67		24		91		113
Total regulatory liabilities		$	1,404	$	219	$	1,623	$	1,466

(3)Recovery expected over the average service life of employees.

(4)Amortization will occur over a 7-year period starting January 1, 2023.

(5)Amortization will occur over a 2-year period starting January 1, 2023.

(6)Amortization period not yet determined.

(7)Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base.

(8)Refund expected as the balance is reversed using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base.

Schedule of Regulatory Assets [Table Text Block]

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


	Remaining Amortization Period	As of December 31,
		2022						2021
		Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	1	$	1	$	55
Pension and other postretirement plans	(3)	—		95		95		131


Debt issuance costs	2049	—		21		21		23
Trojan decommissioning activities	2059	—		133		133		90
February 2021 ice storm and damage	(4)	74		—		74		67
Power cost adjustment mechanism	(5)	28		—		28		29
2020 Labor Day wildfire	(4)	31		—		31		45
COVID-19	(6)	22		—		22		36
Wildfire mitigation	(6)	28		—		28		—
Other	Various	70		24		94		81
Total regulatory assets		$	253	$	274	$	527	$	557
Regulatory liabilities:
Asset retirement removal costs	(7)	$	1,136	$	—	$	1,136	$	1,047
Deferred income taxes	(8)	194		—		194		208

Asset retirement obligations	(7)	7		—		7		43

Price risk management	(2)	—		195		195		55
Other	Various	67		24		91		113
Total regulatory liabilities		$	1,404	$	219	$	1,623	$	1,466

(3)Recovery expected over the average service life of employees.

(4)Amortization will occur over a 7-year period starting January 1, 2023.

(5)Amortization will occur over a 2-year period starting January 1, 2023.

(6)Amortization period not yet determined.

(7)Recovery or refund expected over the estimated lives of the underlying assets and treated as a reduction to rate base.

(8)Refund expected as the balance is reversed using the average rate assumption method over the average life of the underlying assets and treated as a reduction to rate base.

Basis of Presentation (Details) $ in Millions	12 Months Ended
Basis of Presentation (Details) $ in Millions	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2022 mi² shares retail_customers
Basis of Presentation [Abstract]
Service Area Sq Miles \| mi²			4,000,000
Incorporated Cities			51
Number of Retail Customers \| retail_customers			926,000
Service area population			1,900,000
Entity Number of Employees			2,873
Number of Union Employees			673
Number of Union Employees Subject to Agreement A			610
Number of Union Employees Subject to Agreement B			63
Debt extinguishment costs \| $		$ 2
Contribution to pension and other postretirement plans \| $	$ 2	$ 2

Employee Benefits Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Plan [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	$ 547	$ 800	$ 753
Pension Plan [Member] \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	6
Pension Plan [Member] \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	525	764
Pension Plan [Member] \| Private equity funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	2	5
Pension Plan [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	16	25
Pension Plan [Member] \| Fair Value, Inputs, Level 1 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	16	25
Pension Plan [Member] \| Fair Value, Inputs, Level 1 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	16	25
Pension Plan [Member] \| Fair Value, Inputs, Level 2 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plan [Member] \| Fair Value, Inputs, Level 2 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plan [Member] \| Fair Value, Inputs, Level 3 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plan [Member] \| Fair Value, Inputs, Level 3 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Pension Plan [Member] \| Other
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	531	775
Pension Plan [Member] \| Other \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	6
Pension Plan [Member] \| Other \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	525	764
Pension Plan [Member] \| Other \| Private equity funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	2	5
Other Postretirement Benefit Plans [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	21	37	$ 35
Other Postretirement Benefit Plans [Member] \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	6
Other Postretirement Benefit Plans [Member] \| Money Market Funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	3
Other Postretirement Benefit Plans [Member] \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	3	8
Other Postretirement Benefit Plans [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	2	4
Other Postretirement Benefit Plans [Member] \| Defined Benefit Plan, Equity Securities, Non-US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	3	10
Other Postretirement Benefit Plans [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	6
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	7	13
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member] \| Money Market Funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	3
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member] \| Defined Benefit Plan, Equity Securities, Non-US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	3	10
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	6	10
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member] \| Money Market Funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	2	4
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member] \| Defined Benefit Plan, Equity Securities, Non-US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	6
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member] \| Money Market Funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member] \| Defined Benefit Plan, Equity Securities, Non-US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 3 [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	0	0
Other Postretirement Benefit Plans [Member] \| Other
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	8	14
Other Postretirement Benefit Plans [Member] \| Other \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	6
Other Postretirement Benefit Plans [Member] \| Other \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	$ 3	$ 8