0001193125-26-052750 | 10-K | XBRL Viewer | Portland General Electric CO OR

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Subsequent Events (Details) - Subsequent Event - PacifiCorp $ in Millions	Feb. 15, 2026 USD ($) Customers
Subsequent Event [Line Items]
Asset acquisition, date of agreement	Feb. 15, 2026
Number of customers acquired \| Customers	140,000
Purchase price	$ 1,900
Bridge facility from bank	1,900
Expects equity commitments to finance acquisition	600
Termination fee	$ 35

Balance Sheet Components - Schedule of Other Current Assets and Accrued Expenses and Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Other current assets:
Prepaid expenses	$ 96	$ 81
Margin deposits	116	125
Assets from price risk management activities	32	32
Other current assets	244	238
Accrued expenses and other current liabilities:
Regulatory liabilities - current	73	53
Accrued employee compensation and benefits	87	80
Accrued dividends payable	63	57
Accrued interest payable	53	49
Accrued taxes payable	38	36
Margin deposits from wholesale counterparties	21	5
Other	143	130
Accrued expenses and other current liabilities	$ 478	$ 410

Leases (Notes)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Leases

NOTE 17: LEASES

PGE determines if an arrangement is a lease at commencement 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, 2025 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 PPAs that rely on identified plant. Variable payments are generally related to gas storage and PPAs 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):


	2025		2024
Operating lease cost	$	26	$	2
Finance lease cost:
Amortization of right-of-use assets	$	14	$	14
Interest on lease liabilities		14		14
Total finance lease cost	$	28	$	28

Variable lease cost	$	22	$	28

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


		As of December 31,
	Balance Sheet Classification	2025		2024
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	303	$	312

Current liabilities	Accrued expenses and other current liabilities	$	26	$	26
Noncurrent liabilities	Other noncurrent liabilities		277		286
Total operating lease liabilities *		$	303	$	312
Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	262	$	276

Current liabilities	Current portion of finance lease obligations	$	27	$	27
Noncurrent liabilities	Finance lease obligations, net of current portion		263		276
Total finance lease liabilities *		$	290	$	303

* Included in lease liabilities are $577 million and $599 million related to purchased power and storage contracts for the years ended December 31, 2025 and 2024, respectively. These agreements include hydro and natural gas generation PPAs, gas storage, and battery storage, all of which are included within the Company’s AUT and PCAM regulatory mechanisms.

Lease term and discount rates were as follows:


	December 31, 2025			December 31, 2024
Weighted Average Remaining Lease Term (in years)
Operating leases		21			22
Finance leases		19			20
Weighted Average Discount Rate
Operating leases		5.8	%		5.8	%
Finance leases		4.8	%		4.8	%

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, 2025, maturities of lease liabilities were as follows (in millions):


	Operating Leases						Finance Leases
	PPA*			Other			PPA*			Other
2026	$	25		$	1		$	27		$	—
2027		25			1			27			—
2028		25			1			26			—
2029		25			1			26			—
2030		25			1			26			—
Thereafter		349			39			304			—
Total lease payments		474			44			436			—
Less imputed interest		(187	)		(28	)		(146	)		—
Total	$	287		$	16		$	290		$	—

* These agreements include hydro and natural gas generation PPAs, gas storage, and battery storage contracts, all of which are included within the Company’s AUT and PCAM regulatory mechanisms.

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


	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used in operating leases	$	26	$	3	$	4
Operating cash flows used in finance leases		14		14		15
Financing cash flows used in finance leases		14		6		6
Right-of-use assets obtained in leasing arrangements:
Operating leases	$	—	$	295	$	—

Battery storage agreements—PGE has entered into three battery storage PPAs subsequent to December 31, 2025 that are expected to be accounted for as leases upon commencement. These projects are summarized as follows:

•

on January 9, 2026 PGE entered into an agreement with an expected lease commencement date in December 2027 and a term of 20 years, pending OPUC approval of a waiver filing. The expected total fixed contract consideration will approximate $612 million over the lease term;

•

on February 15, 2026, PGE entered into an agreement with an expected lease commencement date in December 2027 and a term of 30 years, subject to approvals. The expected total fixed contract consideration will approximate $331 million over the lease term; and

•

on February 15, 2026, PGE entered into an agreement with an expected lease commencement date in June 2028 and a term of 20 years, pending OPUC approval of a waiver filing. The expected total fixed contract consideration will approximate $636 million over the lease term.

Insider Trading Policies and Procedures	12 Months Ended
Insider Trading Policies and Procedures	Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]
Insider Trading Policies and Procedures Adopted	true

Contingencies (Details) $ in Millions	1 Months Ended	12 Months Ended
Contingencies (Details) $ in Millions	Sep. 30, 2025 USD ($)	Dec. 31, 2025 USD ($) Party
Loss Contingencies [Line Items]
Number of potentially responsible parties \| Party		100
Investigation-related costs		$ 115
Undiscounted estimated total cost		1,700
Long-term operation and maintenance costs		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]
Remediation construction costs		$ 1,200
Storm and Severe Winter Weather [Member]
Loss Contingencies [Line Items]
Remediation construction costs	$ 375

Basis of Presentation (Details) Population in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) mi² RetailCustomers Population Employee	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Basis of Presentation [Abstract]
Service area sq miles \| mi²	4,000
Incorporated cities	51
Number of retail customers \| RetailCustomers	960,000
Service area population \| Population	2
Entity number of employees	2,877
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest \| $	$ 11	$ 15	$ 13
Number of union employees	666
Number of union employees subject to agreement A	602
Number of union employees subject to agreement B	64
Reclassification of amounts from other net to contribution to pension and other postretirement plans \| $		$ 19	$ 14

Cover Page - USD ($)

12 Months Ended

Dec. 31, 2025

Feb. 10, 2026

Jun. 30, 2025

Cover [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2025

Document Transition Report

false

Entity File Number

001-05532-99

Entity Registrant Name

PORTLAND GENERAL ELECTRIC COMPANY

Entity Incorporation, State or Country Code

Entity Tax Identification Number

93-0256820

Entity Address, Address Line One

121 SW Salmon Street

Entity Address, City or Town

Portland

Entity Address, State or Province

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

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

Document Financial Statement Error Correction [Flag]

false

Entity Shell Company

false

Entity Public Float

$ 4,436,840,693

Entity Common Stock, Shares Outstanding

115,561,705

Documents Incorporated by Reference [Text Block]

Documents Incorporated by Reference


Part III, Items 10 - 14	Portions of Portland General Electric Company’s definitive proxy statement for its 2026 Annual Meeting of Shareholders, intended to be filed not later than 120 days after the close of its fiscal year.

Entity Central Index Key

0000784977

Amendment Flag

false

Document Fiscal Year Focus

2025

Document Fiscal Period Focus

Current Fiscal Year End Date

--12-31

Auditor Name

Deloitte & Touche LLP

Auditor Firm ID

Auditor Location

Portland, Oregon

Auditor Opinion [Text Block]

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Portland General Electric Company and subsidiaries (the “Company”) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, shareholders’ equity, and cash flows, for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “financial statements”). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control — Integrated Framework (2013) issued by COSO.

Employee Benefits - Schedule of Allocation of Plan Assets (Details)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Dec. 31, 2025
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%	55.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	55.00%	53.00%
Defined Benefit Pension Plan [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	45.00%	45.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	45.00%	47.00%
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	39.00%	38.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	40.00%	40.00%
Other Postretirement Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	61.00%	62.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	60.00%	60.00%
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	1.00%	2.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	1.00%	1.00%
Non Qualified Benefit Plans [Member] \| Debt Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	2.00%	5.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	2.00%	6.00%
Non Qualified Benefit Plans [Member] \| Other Contract [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	97.00%	93.00%
Defined Benefit Plan, Plan Assets, Actual Allocation, Percentage	97.00%	93.00%

Contingencies (Policies)

12 Months Ended

Dec. 31, 2025

Contingencies [Abstract]

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.

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.

Segment Information (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

The table below provides information about the Company’s single business segment, including significant segment expenses, and includes reconciliation to Consolidated Net Income (dollars in millions):


	Years Ended December 31,
	2025		2024		2023
Total revenues	$	3,576	$	3,440	$	2,923
Operating expenses:
Purchased power and fuel		1,411		1,418		1,190
Operating and maintenance expense:
Generation, transmission and distribution		450		436		374
Administrative and other		392		403		341
Total operating and maintenance expense		842		839		715
Depreciation and amortization		578		496		458
Taxes other than income taxes		190		175		164
Total operating expenses		3,021		2,928		2,527
Income from operations		555		512		396
Interest expense, net:
Interest expense		243		226		186
Allowance for borrowed funds used during construction		11		15		13
Total interest expense, net		232		211		173
Other income, net:		36		49		50
Income before income taxes		359		350		273
Income tax expense		53		37		45
Consolidated Net income	$	306	$	313	$	228

Certain additional financial information relating to the Company’s single business segment was as follows (dollars in millions):


	Years Ended December 31,
	2025			2024			2023
Total assets	$	13,230		$	12,544		$	11,208
Capital expenditures		(1,189	)		(1,268	)		(1,358	)
Equity method investments		19			13			9

Segment Information - Certain Additional Financial Information Relating to Single Business Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting [Abstract]
Assets	$ 13,230	$ 12,544	$ 11,208
Capital expenditures	(1,189)	(1,268)	(1,358)
Equity method investments	$ 19	$ 13	$ 9

- Definition

Amount of asset recognized for present right to economic benefit.

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-Paragraph 1A
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-Publisher FASB
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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Reference 32: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

- Definition

This item represents the carrying amount on the entity's balance sheet of its investment in common stock of an equity method investee. This is not an indicator of the fair value of the investment, rather it is the initial cost adjusted for the entity's share of earnings and losses of the investee, adjusted for any distributions (dividends) and other than temporary impairment (OTTI) losses recognized.

+ References + Details

Long-term Debt and Other Financing Arrangements - Long-term Debt Schedule of Long Term Debt Instruments (Details) - USD ($) $ in Millions	Dec. 31, 2025	Oct. 27, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.60% in 2025 and 4.52% in 2024, due at various dates through 2059.	$ 4,560		$ 4,250
Unsecured term bank loan at December 31, 2025	0		170
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033	119		119
Total long-term debt	4,679	$ 68	4,539
Less: Unamortized debt expense	(17)		(15)
Less: current portion of long-term debt	0		(170)
Long-term debt, net of current portion	$ 4,662		$ 4,354
First mortgage Bonds - minimum rate	1.82%
First Mortgage Bonds - maximum rate	6.88%
Debt, Weighted Average Interest Rate	4.60%		4.52%
Pollution Control Revenue Bonds - Interest rate	2.13%		2.38%

Balance Sheet Components - Schedule of Public Utility Property, Plant, and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Generation	$ 5,649	$ 5,510
Transmission	1,626	1,420
Distribution	6,189	5,714
General	931	1,025
Energy storage	613	222
Intangible	988	972
Total in service	15,996	14,863
Accumulated depreciation and amortization	(5,419)	(5,085)
Total in service, net	10,577	9,778
Construction work-in-progress	416	567
Electric utility plant, net	$ 10,993	$ 10,345

Leases (Policies)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Leases

PGE does not record leases with a term of 12-months or less in the consolidated balance sheets.

Jointly-owned Plant - Schedule of Jointly-owned Plant (Details) $ in Millions	Dec. 31, 2025 USD ($)
Jointly Owned Utility Plant Interests [Line Items]
Plant In-service	$ 828
Accumulated Depreciation	627
Construction Work In Progress	$ 14
Colstrip [Member]
Jointly Owned Utility Plant Interests [Line Items]
PGE Share	20.00%
Plant In-service	$ 512
Accumulated Depreciation	501
Construction Work In Progress	$ 3
Pelton/Round Butte [Member]
Jointly Owned Utility Plant Interests [Line Items]
PGE Share	50.01%
Plant In-service	$ 242
Accumulated Depreciation	81
Construction Work In Progress	10
Colstrip-Transmission [Member]
Jointly Owned Utility Plant Interests [Line Items]
Plant In-service	74
Accumulated Depreciation	45
Construction Work In Progress	$ 1

Stock-based Compensation - Schedule of Fair Value Determined Using a Monte Carlo Simulation (Details)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Risk-free interest rate	4.40%	4.30%	4.20%
Expected term (in years)	2 years 10 months 24 days	2 years 10 months 24 days	2 years 10 months 24 days
Volatility - Minimum	15.50%	12.40%	21.80%
Volatility - Maximum	65.80%	53.20%	31.50%

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (f)(2)
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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Reference 7: http://www.xbrl.org/2003/role/disclosureRef
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Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Name Accounting Standards Codification
-Section 35
-Paragraph 1D
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480483/718-10-35-1D

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147480483/718-10-35-3

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 2
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 718
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-Section 50
-Paragraph 2
-Subparagraph (a)(3)
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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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Reference 15: http://www.xbrl.org/2003/role/disclosureRef
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Reference 16: http://www.xbrl.org/2003/role/disclosureRef
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Reference 17: http://www.xbrl.org/2003/role/disclosureRef
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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
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Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
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Reference 24: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
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Reference 26: http://www.xbrl.org/2003/role/disclosureRef
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Reference 27: http://www.xbrl.org/2003/role/disclosureRef
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Reference 28: http://www.xbrl.org/2003/role/disclosureRef
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Reference 29: http://www.xbrl.org/2003/role/disclosureRef
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Reference 30: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Balance Sheet Components - (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Balance Sheet Components [Abstract]
Unbilled revenues	$ 180	$ 177
Allowance for uncollectible accounts	$ 13	$ 12

Leases - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating Lease, Payments	$ 26	$ 3	$ 4
Finance Lease, Interest Payment on Liability	14	14	15
Finance Lease, Principal Payments	14	6	6
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	0	295	$ 0
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Current	26	26
Operating Lease, Liability, Noncurrent	$ 277	$ 286

Balance Sheet Components

12 Months Ended

Dec. 31, 2025

Balance Sheet Components [Abstract]

Balance Sheet Components

NOTE 4: BALANCE SHEET COMPONENTS

Accounts Receivable, Net

Accounts receivable, net includes $180 million and $177 million of unbilled revenues as of December 31, 2025 and 2024, respectively. Accounts receivable is net of an allowance for uncollectible accounts of $13 million as of December 31, 2025 and $12 million as of December 31, 2024. The following is the activity in the allowance for uncollectible accounts (in millions):


	Years Ended December 31,
	2025			2024			2023
Balance as of beginning of year	$	12		$	9		$	12
Increase/(decrease) in provision		12			11			5
Amounts written off, less recoveries		(11	)		(8	)		(8	)
Balance as of end of year	$	13		$	12		$	9

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,
	2025		2024
Other current assets:
Prepaid expenses	$	96	$	81
Margin deposits		116		125
Assets from price risk management activities		32		32
	$	244	$	238
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	73	$	53
Accrued employee compensation and benefits		87		80
Accrued dividends payable		63		57
Accrued interest payable		53		49
Accrued taxes payable		38		36
Margin deposits from wholesale counterparties		21		5
Other		143		130
	$	478	$	410

Electric Utility Plant, Net

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


	As of December 31,
	2025			2024
Electric utility plant (1):
Generation	$	5,649		$	5,510
Transmission (2)		1,626			1,420
Distribution (2)		6,189			5,714
General		931			1,025
Energy storage		613			222
Intangible		988			972
Total in service		15,996			14,863
Accumulated depreciation and amortization		(5,419	)		(5,085	)
Total in service, net		10,577			9,778
Construction work-in-progress		416			567
Electric utility plant, net	$	10,993		$	10,345

(1) On January 1, 2025, FERC Order 898 reclassified certain assets between primary functions for ratemaking purposes. In 2025 and going forward, tangible assets are classified consistent with the FERC's updated functional classification. Reclassifications were completed as of January 1, 2025 of $22 million of Generation, $21 million of Transmission, $87 million of Distribution, $(132) million of General, and $2 million of Energy storage plant.

(2) On July 2, 2025, the FERC approved PGE's request to classify the functional asset classification of certain 57kV facilities from Distribution to Transmission to align classification with the primary function of these assets. As a result, PGE reclassified $84 million of Electric utility plant in-service assets from Distribution to Transmission.

Risk Management - Schedule of PGE's Net Volumes related to Assets and Liabilities from Price Risk Management Activities (Details) MWh in Millions, MMBTU in Millions, $ in Millions	Dec. 31, 2025 CAD ($) MMBTU MWh	Dec. 31, 2024 CAD ($) MMBTU MWh
Price Risk Management [Abstract]
Electricity \| MWh	1	2
Natural gas \| MMBTU	224	199
Foreign currency exchange \| $	$ 9	$ 34

Fair Value of FInancial Instruments

12 Months Ended

Dec. 31, 2025

Fair Value of Financial Instruments Note [Abstract]

Fair Value of FInancial Instruments

NOTE 5: FAIR VALUE OF FINANCIAL INSTRUMENTS

PGE determines the fair value of financial instruments, both assets and liabilities recognized and not recognized in the Company’s consolidated balance sheets, for which it is practicable to estimate fair value 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, 2025 and 2024, 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, 2025
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	59	$	—	$	—	$	—	$	59
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		14		11		—		—		25
Corporate credit		—		10		—		—		10
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		1		—		—		—		1
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		7		7
Price risk management activities: (1) (4)
Electricity		—		29		1		—		30
Natural gas		—		3		—		—		3
	$	74	$	53	$	1	$	14	$	142
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	13	$	37	$	—	$	50
Natural gas		—		160		4		—		164
	$	—	$	173	$	41	$	—	$	214

(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 $35 million, which are recorded at cash surrender value.

(4)

For further information regarding price risk management derivatives, see Note 6, Risk Management.


	December 31, 2024
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	12	$	—	$	—	$	—	$	12
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		10		6		—		—		16
Corporate credit		—		7		—		—		7
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		2		—		—		—		2
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		4		4
Price risk management activities: (1) (4)
Electricity		—		18		1		—		19
Natural gas		—		15		—		—		15
	$	24	$	46	$	1	$	11	$	82
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	25	$	31	$	—	$	56
Natural gas		—		159		4		—		163
	$	—	$	184	$	35	$	—	$	219

(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 $32 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, NQBP, and Paid Leave Oregon 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.

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 money market funds in the NDT and Paid Leave Oregon Trust are 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, 2025:
Electricity physical forwards	$	—	$	37	Discounted cash flow	Electricity forward price (per MWh)	$	22.99	$	94.65	$	59.28
Natural gas financial swaps		—		4	Discounted cash flow	Natural gas forward price (per Dth)		1.67		2.76		2.15
Electricity financial futures		1		—	Discounted cash flow	Electricity forward price (per MWh)		31.00		84.00		52.13
	$	1	$	41

As of December 31, 2024:
Electricity physical forwards	$	—	$	28	Discounted cash flow	Electricity forward price (per MWh)	$	14.00	$	99.68	$	59.43
Natural gas financial swaps		—		4	Discounted cash flow	Natural gas forward price (per Dth)		1.86		6.53		2.68
Electricity financial futures		1		3	Discounted cash flow	Electricity forward price (per MWh)		27.00		110.00		70.55
	$	1	$	35

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,
	2025			2024
Net liabilities from price risk management activities as of beginning of year	$	34		$	45
Net realized and unrealized losses *		22			25
Net transfers from Level 3 to Level 2		(16	)		(36	)
Net liabilities from price risk management activities as of end of year	$	40		$	34
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	27		$	30

* Includes $5 million in net realized gains in both 2025 and 2024.

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. 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 out of Level 3 at the end of the reporting period for all of its derivative instruments.

During the years ended December 31, 2025 and 2024, there were no transfers into Level 3 from Level 2. Transfers from Level 3 are reflected in the table above.

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, 2025, the carrying amount of PGE’s long-term debt was $4,662 million, net of $17 million of unamortized debt expense, and its estimated aggregate fair value was $4,311 million. As of December 31, 2024, the carrying amount of PGE’s long-term debt was $4,524 million, net of $15 million of unamortized debt expense, with an estimated aggregate fair value of $3,963 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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 2
-Subparagraph (bbb)(1)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 820
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-Paragraph 107
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-URI https://asc.fasb.org/1943274/2147482078/820-10-55-107

Reference 3: http://www.xbrl.org/2003/role/exampleRef
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+ Details

Insider Trading Arrangements

3 Months Ended

Dec. 31, 2025

Trading Arrangements, by Individual

Material Terms of Trading Arrangement

Rule 10b5-1 Trading Arrangements

PGE has adopted an insider trading policy that governs the purchase, sale, and/or other dispositions of Company securities by its directors, officers, and employees that it believes is reasonably designed to promote compliance with insider trading laws, rules, and regulations and New York Stock Exchange listing standards. A copy of the Insider Trading Policy is included as Exhibit 19.1 to this report.

During the three months ended December 31, 2025, the following directors or officers (as defined in Rule 16a-1(f) of the Exchange Act) adopted or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(c) of Regulation S-K:


Name (Title)	Action Taken (Date of Action)	Type of Trading Arrangement	Duration of Trading Arrangement	Aggregate Number of Securities to be Purchased or Sold
Benjamin Felton (Executive Vice President Chief Operating Officer)	Adoption (November 5, 2025)	Rule 10b5-1 trading arrangement	Until February 26, 2027, or such earlier date upon which all transactions are completed or expire without execution	Up to 9,938 shares of common stock

Name

Benjamin Felton

Title

Executive Vice President Chief Operating Officer

Rule 10b5-1 Arrangement Adopted

true

Adoption Date

November 5, 2025

Expiration Date

February 26, 2027

Aggregate Available

9,938

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

NOTE 12: INCOME TAXES

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


	Years Ended December 31,
	2025			2024			2023
Current:
Federal	$	3		$	2		$	11
State and local		13			12			26
		16			14			37
Deferred:
Federal		19			(2	)		4
State and local		26			25			4
		45			23			8
Investment Tax Credits		(8	)		—			—
Income tax expense	$	53		$	37		$	45

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,
	2025					2024					2023
Income before income taxes	$	359				$	350				$	273

Federal statutory tax rate		76		21.0	%		74		21.0	%		57		21.0	%
State and local taxes, net of federal tax benefit (1)		30		8.4			28		8.0			25		9.0
Federal tax credits (2):
Energy-related tax credits		(48	)	(13.3	)		(58	)	(16.6	)		(27	)	(10.0	)
Research and development tax credits		(1	)	(0.3	)		(2	)	(0.6	)		(2	)	(0.7	)
Other credits		—		—			—		—			—		(0.1	)
Nontaxable or Nondeductible Items:
Executive Compensation (3)		4		1.1			4		1.4			1		0.5
Other		—		—			1		0.2			—		—
Changes in Unrecognized Tax Benefits		—		—			1		0.2			1		0.3
Effect of ratemaking on income tax accounting (4)		(8	)	(2.1	)		(11	)	(2.9	)		(10	)	(3.6	)
Effective tax rate	$	53		14.8	%	$	37		10.7	%	$	45		16.4	%

(1)

State taxes in Oregon make up the majority (greater than 50 percent) of the tax effect in this category.

(2)

Federal tax credits consist primarily of production tax credits (PTCs) earned from Company-owned wind-powered generating facilities as well as amortization of investment tax credits (ITCs). PTCs are earned based on a per-kilowatt hour rate, and as a result, the annual amount of PTCs earned will vary based on weather conditions and availability of the facilities. PTCs are generated for 10 years from the corresponding facilities’ in-service dates. PGE’s PTC generation will end at various dates through 2034. The generation of PTCs from Tucannon River Wind Farm ended in 2024. ITCs are generated on qualifying renewable energy and infrastructure projects placed in service during 2023, 2024, and 2025. In accordance with the deferral method of accounting, ITCs are recorded as a deferred credit when generated and amortized as a reduction of income tax expense over the estimated useful life of the related properties. These energy-related tax credits are presented net of any transfer discounts. Federal tax credits also include all other federal tax credits and related

deferrals. The tax credit deferrals are established to provide the benefit back to customers over a period agreed upon with the OPUC.

(3)

Under IRC Section 162(m), the tax deduction for compensation paid to certain executive officers is limited to $1 million per year.

(4)

The effect of ratemaking on income tax accounting primarily reflects excess deferred income taxes related to remeasurement under the Tax Cuts and Jobs Act. The majority of excess deferred income tax is subject to Internal Revenue Service normalization rules and will be reversed over the remaining regulatory life of the assets using the average rate assumption method.

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


	As of December 31,
	2025		2024
Deferred income tax assets:
Employee benefits	$	79	$	89
Regulatory liabilities		21		28
Tax credits, net of transfer discount		61		69
Deferred investment tax credits		73		14
Price risk management		50		51
Total deferred income tax assets		284		251
Deferred income tax liabilities:
Depreciation and amortization		711		633
Regulatory assets		156		169
Other		18		13
Total deferred income tax liabilities		885		815
Deferred income tax liability, net	$	601	$	564

As of December 31, 2025, PGE has federal credit carryforwards of $69 million. These credits primarily consist of PTCs, which will expire at various dates through 2045. In determining the need for a valuation allowance, PGE considered anticipated proceeds from the sale of tax credits. However, PGE believes it is more likely than not that its deferred income tax assets as of December 31, 2025 and 2024 will be realized. Accordingly, no material valuation allowance has been recorded. As of December 31, 2025, and 2024, PGE had no material unrecognized tax benefits.

On April 17, 2024, PGE received approval from the OPUC to transfer 2024 and 2025 PTCs and record any difference between the full value and the discounted value as a deferred regulatory asset. On August 20, 2025 and December 15, 2025, PGE received approval from the OPUC to transfer 2025 ITCs and return the net proceeds from the sale to PGE customers. PGE transferred tax credits, net of discounts, of $179 million and $112 million for cash proceeds in 2025 and 2024, respectively. The 2025 proceeds included $37 million from PTC sales and $142 million from ITC sales, net of discounts.

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 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.

Supplemental cash flow information related to cash paid for income taxes consists of the following (in millions):


	Years Ended December 31,
	2025			2024			2023
Cash paid (received) for income taxes, net:
Federal
Federal income taxes paid	$	4		$	4		$	10
Tax credit sales		(179	)		(112	)		(23	)
State and local
Oregon		12			17			21
Other		1			1			4

- Definition

The entire disclosure for income tax.

+ References

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+ Details

Long-term Debt and Other Financing Arrangements - Long-term Debt Schedule of Maturities of Long term debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Oct. 27, 2025	Dec. 31, 2024
Long-Term Debt, Unclassified [Abstract]
2026	$ 0
2027	160
2028	100
2029	200
2030	325
Thereafter	3,894
Total long-term debt	$ 4,679	$ 68	$ 4,539

- Definition

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

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-URI https://asc.fasb.org/1943274/2147482949/835-30-55-8

Reference 6: http://fasb.org/us-gaap/role/ref/legacyRef
-Topic 942
-SubTopic 210
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-03(16))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478546/942-210-S99-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69C
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69C

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1D
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-1D

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 944
-SubTopic 210
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.7-03(a)(16)(a)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478777/944-210-S99-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (b)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481139/470-20-50-4

+ Details

Leases - Maturities of Lease Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Lessee, Lease, Description [Line Items]
Operating Leases, Total	$ 303	$ 312
Finance Leases, Total lease payments	80
Finance Leases, Less imputed interest	(49)
Finance Lease, Total	290	$ 303
PPA [Member]
Lessee, Lease, Description [Line Items]
Operating Leases, 2026	25
Operating Leases, 2027	25
Operating Leases, 2028	25
Operating Leases, 2029	25
Operating Leases, 2030	25
Operating Leases, Thereafter	349
Operating Leases, Total lease payments	474
Operating Leases, Less imputed interest	(187)
Operating Leases, Total	287
Finance Leases, 2026	27
Finance Leases, 2027	27
Finance Leases, 2028	26
Finance Leases, 2029	26
Finance Leases, 2030	26
Finance Leases, Thereafter	304
Finance Leases, Total lease payments	436
Finance Leases, Less imputed interest	(146)
Finance Lease, Total	290
Other [Member]
Lessee, Lease, Description [Line Items]
Operating Leases, 2026	1
Operating Leases, 2027	1
Operating Leases, 2028	1
Operating Leases, 2029	1
Operating Leases, 2030	1
Operating Leases, Thereafter	39
Operating Leases, Total lease payments	44
Operating Leases, Less imputed interest	(28)
Operating Leases, Total	16
Finance Leases, 2026	0
Finance Leases, 2027	0
Finance Leases, 2028	0
Finance Leases, 2029	0
Finance Leases, 2030	0
Finance Leases, Thereafter	0
Finance Leases, Total lease payments	0
Finance Leases, Less imputed interest	0
Finance Lease, Total	$ 0

Jointly-owned Plant - Schedule of Jointly-owned Plant (Parenthetical) (Details)	Dec. 31, 2025
Colstrip-Transmission Facility One [Member]
Jointly Owned Utility Plant Interests [Line Items]
PGE Share	14.00%
Colstrip-Transmission Facility Two [Member]
Jointly Owned Utility Plant Interests [Line Items]
PGE Share	16.00%

Leases - Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
Leases - Lease Cost (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Operating Lease, Cost	$ 26	$ 2
Finance Lease, Right-of-Use Asset, Amortization	14	14
Finance Lease, Interest Expense	14	14
Total finance lease cost	28	28
Variable Lease, Cost	$ 22	$ 28

Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

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


	Years Ended December 31,
	2025		2024		2023
Weighted average common shares outstanding—basic		110,471		103,946		97,760
Dilutive potential common shares		268		213		192
Weighted average common shares outstanding—diluted		110,739		104,159		97,952

Employee Benefits (Policies)	12 Months Ended
Employee Benefits (Policies)	Dec. 31, 2025
Employee Benefits [Abstract]
Pension and Other Postretirement Plans, Pensions, Policy [Policy Text Block]	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 NQBP 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.
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 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-backed securities, are included in commingled trusts or separately managed accounts. 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.

Balance Sheet Components - Schedule of Allowance for Uncollectible Accounts Activity (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Balance as of beginning of year	$ 12	$ 9	$ 12
Increase/(decrease) in provision	12	11	5
Amounts written off, less recoveries	(11)	(8)	(8)
Balance as of end of year	$ 13	$ 12	$ 9

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2025	Dec. 31, 2024
Statement of Financial Position [Abstract]
Preferred stock, no par value	$ 0	$ 0
Preferred stock, shares authorized	30,000,000	30,000,000
Preferred stock, outstanding	0	0
Preferred stock, issued	0	0
Common stock, no par value	$ 0	$ 0
Common stock, shares authorized	160,000,000	160,000,000
Common stock, shares outstanding	115,559,079	109,342,251
Common stock, shares issued	115,559,079	109,342,251

Employee Benefits - Schedule of Expected Benefit Payments (Details) $ in Millions	Dec. 31, 2025 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	$ 50
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	50
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	50
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	51
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	49
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	236
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Benefit Payments in Year One	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Two	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Three	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	44
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	43
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	219
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	4
Defined Benefit Plan, Expected Future Benefit Payments in Year Four	5
Defined Benefit Plan, Expected Future Benefit Payments in Year Five	4
Defined Benefit Plan, Expected Future Benefit Payments in Five Fiscal Years Thereafter	11
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	$ 6

Leases (Details) $ in Millions	12 Months Ended
Leases (Details) $ in Millions	Dec. 31, 2025 USD ($) Period	Feb. 15, 2026 USD ($)	Jan. 09, 2026 USD ($)	Dec. 31, 2024 USD ($)
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Related to Power Purchase Agreements	$ 577			$ 599
Finance lease renewal term	10 years
Finance leases number of renewal periods \| Period	5
Subsequent Event [Member] \| PPA [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Related to Power Purchase Agreements		$ 331	$ 612
Lease term, purchased power agreement		30 years	20 years
Subsequent Event [Member] \| OPUC [Member] \| PPA [Member]
Lessee, Lease, Description [Line Items]
Operating Lease, Liability, Related to Power Purchase Agreements		$ 636
Lease term, purchased power agreement		20 years

Stock-based Compensation - Summary of RSU Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award, Options, Grants in Period, Net of Forfeitures [Abstract]
Outstanding, Units	796,793	645,697	579,461
Outstanding, Weighted Average Grant Date Fair Value	$ 44.78	$ 47.57	$ 49.23
Granted, Units	582,444	478,509	421,788
Granted, Weighted Average Grant Date Fair Value	$ 41.68	$ 41.02	$ 47.82
Forfeited, Units	(39,944)	(20,774)	(57,566)
Forfeited, Weighted Average Grant Date Fair Value	$ 42.48	$ 45.32	$ 48.03
Vested, Units	(364,659)	(306,639)	(297,986)
Vested, Weighted Average Grant Date Fair Value	$ 47.31	$ 44.76	$ 52.45
Outstanding, Units	974,634	796,793	645,697
Outstanding, Weighted Average Grant Date Fair Value	$ 42.58	$ 44.78	$ 47.57

Subsequent Events

12 Months Ended

Dec. 31, 2025

Subsequent Events [Abstract]

Subsequent Events

NOTE 21: SUBSEQUENT EVENTS

On February 15, 2026, PGE, through a newly formed, wholly owned subsidiary, entered into an Asset Purchase and Service Area Transfer Agreement (the “Agreement”) with PacifiCorp, an indirect subsidiary of Berkshire Hathaway Energy Company, to acquire select portions of PacifiCorp’s Washington state regulated utility retail business. Under the Agreement, PGE would acquire certain assets and liabilities related to generation, transmission, and distribution business to serve the related service area comprised of approximately 140,000 customers. The stated purchase price is $1.9 billion in cash, subject to customary adjustments, including adjustments for net working capital, regulatory assets and liabilities, assumed liabilities, and capital expenditures at closing.

The acquisition is supported by a fully committed bridge facility with Barclays Bank PLC and JPMorgan Chase Bank, N.A. for $1.9 billion. The Company expects to permanently finance the transaction through a balanced mix of debt, equity, and its minority investment partner, Manulife Infrastructure Fund III L.P. and its affiliates including John Hancock Life Insurance Company (USA) (“Manulife”). In connection with the financing plan, PGE expects equity commitments from Manulife to finance up to $600 million of the purchase. Assuming the closing of the transactions contemplated by the Agreement and the consummation of the financing transactions, Manulife will be the Company's joint venture partner in the business. PGE would remain majority owner and sole operator.

The Agreement also provides for certain termination rights, and under certain specified circumstances, the Company may be required to pay PacifiCorp a termination fee of $35 million. The transaction is expected to consummate twelve months after submission of regulatory filings, subject to customary closing conditions and regulatory approvals, including under the Hart-Scott-Rodino Act, Section 203 of the Federal Power Act from the FERC, the Washington Utilities and Transportation Commission (“WUTC”), the OPUC, the Idaho Public Utilities Commission (“IPUC”), the Public Service Commission of Utah (“UPSC”), the Public Utilities Commission of the State of California (“CPUC”) and the Public Service Commission of Wyoming (“WPSC”), and certain other federal and state regulatory approvals.

The transaction is expected to be accounted for as a business combination pursuant to ASC 805, Business Combinations, using the acquisition method of accounting and in which PGE would record the fair value of the assets acquired and liabilities assumed as of the acquisition date. To the extent that the consideration transferred is greater than the fair value of the net assets acquired, goodwill will be recorded.

Through December 31, 2025 and the date of filing, fees incurred as a part of the acquisition have been immaterial.

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Parenthetical) (Details)	12 Months Ended
	Dec. 31, 2025 USD ($)
Maximum [Member]
Income Tax Examination [Line Items]
Tax deduction for compensation paid to certain executive officers	$ 1,000,000
State Taxes [Member] \| Minimum [Member]
Income Tax Examination [Line Items]
Percentage of tax effects	50.00%

Commitments and Guarantees (Policies)	12 Months Ended
Commitments and Guarantees (Policies)	Dec. 31, 2025
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.

Employee Benefits - Schedule of Defined Benefit Plan Disclosures (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Classification in consolidated balance sheet:
Noncurrent asset	$ (36)	$ (34)
Pension Plans, Defined Benefit [Member]
Benefit obligation:
As of January 1	589	612	$ 690
Fair value of plan assets:
Service cost	10	10	10
Interest cost on benefit obligation	32	33	37
Actuarial (gain) loss	7	(40)
Benefit payments	(29)	(78)
Defined Benefit Plan, Plan Assets, Administration Expense	(3)	(3)
Defined Benefit Plan, Plan Assets, Payment for Settlement	(40)
As of January 1	492	484	530
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(97)	(128)
Net actuarial loss (gain) included in comprehensive income	(16)	(20)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(4)	0	0
Defined Benefit Plan, Amortization of Gain (Loss)	0	0	$ 0
Total Amounts included in comprehensive income	(20)	(20)
Defined Benefit Plan, Accumulated Benefit Obligation	551	574
Actual return on plan assets	58	19
Company contributions	22	16
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	0
Noncurrent liability	(97)	(128)
Amounts included in AOCL:
Net actuarial loss	65	85
Prior service cost	(1)	(1)
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 64	$ 84
Assumptions used:
Discount rate used to calculate benefit obligation	5.70%	5.13%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.14%	4.08%	4.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	6.88%	6.88%
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	$ 23	$ (20)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	$ (1)
Pension Plans, Defined Benefit [Member] \| Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets:
As of January 1	13	13
Other Postretirement Benefit Plans [Member]
Benefit obligation:
As of January 1	38	37	35
Fair value of plan assets:
Service cost	1	1	1
Interest cost on benefit obligation	2	2	2
Actuarial (gain) loss	0	1
Benefit payments	(2)	(3)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
Defined Benefit Plan, Benefit Obligation, Special and Contractual Termination Benefits		1
As of January 1	28	25	23
Defined Benefit Plan, Funded (Unfunded) Status of Plan	(10)	(12)
Net actuarial loss (gain) included in comprehensive income	2	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	1
Defined Benefit Plan, Amortization of Gain (Loss)	0	0	$ 1
Total Amounts included in comprehensive income	2	0
Actual return on plan assets	3	2
Company contributions	2	3
Classification in consolidated balance sheet:
Noncurrent asset	0	0
Current liability	0	(1)
Noncurrent liability	(10)	(11)
Amounts included in AOCL:
Net actuarial loss	(5)	(3)
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ (5)	$ (3)
Assumptions used:
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.03%	4.02%	4.06%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets	4.78%	4.73%
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	$ 2	$ 1
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	$ 0
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member]
Fair value of plan assets:
As of January 1	5	4
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member]
Fair value of plan assets:
As of January 1	7	6
Non Qualified Benefit Plans [Member]
Benefit obligation:
As of January 1	15	16	18
Fair value of plan assets:
Service cost	0	0	0
Interest cost on benefit obligation	1	0	1
Actuarial (gain) loss	(1)	0
Benefit payments	(3)	(2)
Defined Benefit Plan, Plan Assets, Administration Expense	0	0
As of January 1	15	16	17
Defined Benefit Plan, Funded (Unfunded) Status of Plan	0	0
Net actuarial loss (gain) included in comprehensive income	1	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	0
Defined Benefit Plan, Amortization of Gain (Loss)	(1)	(1)	$ (1)
Total Amounts included in comprehensive income	0	(1)
Defined Benefit Plan, Accumulated Benefit Obligation	15	16
Actual return on plan assets	(1)	(1)
Company contributions	3	2
Classification in consolidated balance sheet:
Noncurrent asset	(15)	(16)
Current liability	(2)	(2)
Noncurrent liability	(13)	(14)
Amounts included in AOCL:
Net actuarial loss	6	6
Prior service cost	0	0
Other Comprehensive Income (Loss), Pension and Other Postretirement Benefit Plans, Adjustment, Net of Tax	$ 6	$ 6
Assumptions used:
Discount rate used to calculate benefit obligation	5.70%	5.13%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.96%	3.98%	4.01%
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		$ 0	$ 0

Regulatory Assets and Liabilities - Schedule of Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Regulatory Assets [Line Items]
Regulatory Assets	$ 787	$ 837
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	468
Regulatory Liabilities	1,564	1,493
Remaining Amounts of Regulatory Liabilites for which No Interst Accrues During Recovery Period is Provided	11
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	1,245	1,199
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	228	179
Revenue Subject to Refund [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Regulatory Liabilities	22	40
Other Regulatory Liabilities [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	11
Regulatory Liabilities	69	75
Regulatory Assets Earning a Rate of Return at the Approved Rate	58
Other Regulatory Assets Earning a Return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	74
Earning a return [Member]
Regulatory Assets [Line Items]
Regulatory Assets	319
Regulatory Liabilities	1,553
Deferred Derivative Gain (Loss) [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	185
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	181
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets	0	84
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	64
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	161	161
Other Regulatory Assets (Liabilities) [Member]
Regulatory Assets [Line Items]
Regulatory Assets	136
February 2021 Ice Storm And Damage Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	46	58
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
January 2024 Ice Storm and Damage [Member]
Regulatory Assets [Line Items]
Regulatory Assets	48	46
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Reliability Contingency Event [Member]
Regulatory Assets [Line Items]
Regulatory Assets	90	90
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
2020 Labor Day Wildfire Deferral [Member]
Regulatory Assets [Line Items]
Regulatory Assets	19	24
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Wildfire Mitigation [Member]
Regulatory Assets [Line Items]
Regulatory Assets	42	43
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	0
Other Regulatory Assets [Member]
Regulatory Assets [Line Items]
Regulatory Assets		$ 146
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 62

Leases - Lease Term and Discount Rate (Details)	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	21 years	22 years
Finance Lease, Weighted Average Remaining Lease Term	19 years	20 years
Operating Lease, Weighted Average Discount Rate, Percent	5.80%	5.80%
Finance Lease, Weighted Average Discount Rate, Percent	4.80%	4.80%

Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Regulatory Assets and Liabilities Disclosure [Abstract]

Schedule of Regulatory Assets

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


		As of December 31,
		2025						2024
	Remaining Amortization Period	Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	181	$	181	$	185
Pension plans	(3)		—		64		64		84
Trojan decommissioning activities	2059		—		161		161		161
February 2021 ice storm and damage	2029		46		—		46		58
January 2024 storm and damage	(4)		48		—		48		46
Reliability contingency events	(4)		90		—		90		90
2020 Labor Day wildfire	2029		19		—		19		24
Wildfire mitigation	(5)		42		—		42		43
Other	Various		74		62		136		146
Total regulatory assets		$	319	$	468	$	787	$	837
Regulatory liabilities:
Asset retirement removal costs	(6)	$	1,245	$	—	$	1,245	$	1,199
Deferred income taxes	(7)		228		—		228		179
Clearwater RAC	(8)		22		—		22		40
Other	Various		58		11		69		75
Total regulatory liabilities		$	1,553	$	11	$	1,564	$	1,493

(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 period has yet to be decided.

(5)

The current portion of the balance is expected to amortize by May 31, 2026. The non-current portion of the balance relates to incremental amounts deferred between January 1, 2024 and December 31, 2025 and are not yet approved for amortization.

(6)

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

(7)

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.

(8)

Amortization began on March 1, 2025.

Schedule of Regulatory Liabilities

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


		As of December 31,
		2025						2024
	Remaining Amortization Period	Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	181	$	181	$	185
Pension plans	(3)		—		64		64		84
Trojan decommissioning activities	2059		—		161		161		161
February 2021 ice storm and damage	2029		46		—		46		58
January 2024 storm and damage	(4)		48		—		48		46
Reliability contingency events	(4)		90		—		90		90
2020 Labor Day wildfire	2029		19		—		19		24
Wildfire mitigation	(5)		42		—		42		43
Other	Various		74		62		136		146
Total regulatory assets		$	319	$	468	$	787	$	837
Regulatory liabilities:
Asset retirement removal costs	(6)	$	1,245	$	—	$	1,245	$	1,199
Deferred income taxes	(7)		228		—		228		179
Clearwater RAC	(8)		22		—		22		40
Other	Various		58		11		69		75
Total regulatory liabilities		$	1,553	$	11	$	1,564	$	1,493

(1)

(2)

(3)

Recovery expected over the average service life of employees.

(4)

Amortization period has yet to be decided.

(5)

(6)

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

(7)

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.

(8)

Amortization began on March 1, 2025.

Segment Information - Schedule of Segment Reporting Information, by Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting [Abstract]
Revenues	$ 3,576	$ 3,440	$ 2,923
Operating expenses:
Purchased power and fuel	1,411	1,418	1,190
Operating and maintenance expense:
Generation, transmission and distribution	450	436	374
Administrative and other	392	403	341
Total operating and maintenance expense	842	839	715
Depreciation and amortization	578	496	458
Taxes other than income taxes	190	175	164
Total operating expenses	3,021	2,928	2,527
Income from operations	555	512	396
Interest expense, net:
Interest expense	243	226	186
Allowance for borrowed funds used during construction	11	15	13
Total interest expense, net	232	211	173
Other income, net:
Other income, net	36	49	50
Income (Loss) from Continuing Operations before Income Taxes, Noncontrolling Interest, Total	359	350	273
Income tax expense	53	37	45
Net income	$ 306	$ 313	$ 228

Stock-based Compensation (Details) - USD ($)	12 Months Ended
Stock-based Compensation (Details) - USD ($)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Stock-based compensation	$ 16,000,000	$ 24,000,000	$ 17,000,000
Shares of common stock registered for issuance	4,687,500
Number of remaining shares available for future issuance	779,123
Total value of performance-based RSUs vested	$ 8,000,000	6,000,000	7,000,000
Charge to shareholders' equity	4,000,000	$ 4,000,000	$ 4,000,000
Unrecognized stock-based compensation expense	$ 9,000,000
Stock-based compensation attainment of performance goals that allows vesting	98.40%	115.07%	81.65%
Stock-based compensation, forfeiture rate	5.00%
Stock-based compensation costs capitalized	$ 0
Performance based stock award percentage - minimum	0.00%
Performance based stock award percentage - maximum	200.00%
Total value of time-based RSUs vested	$ 10,000,000	$ 8,000,000	$ 9,000,000

Risk Management - Schedule of PGE's Assets and Liabilities from Price Risk Management Activities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current Assets, Commodity Contracts:
Electricity	$ 29	$ 18
Natural Gas	3	14
Total current derivative assets	32	32
Noncurrent Assets, Commodity Contracts: [Abstract]
Commodity Contract Asset, Noncurrent, Electricity	1	1
Commodity Contract Asset, Noncurrent, Natural Gas	0	1
Derivative Asset, Noncurrent	1	2
Total derivative assets	33	34
Current Liabilities, Commodity Contracts: [Abstract]
Electricity	19	32
Natural Gas	139	115
Total current derivative liabilities	158	147
Noncurrent Liabilities, Commodity Contracts: [Abstract]
Electricity	31	24
Natural Gas	25	48
Total noncurrent derivative liabilities	56	72
Total derivative liabilities	$ 214	$ 219

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash flows from operating activities:
Net income	$ 306	$ 313	$ 228
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	578	496	458
Deferred income taxes	37	23	8
Allowance for equity funds used during construction	(18)	(23)	(19)
Pension and other postretirement benefits	12	6	5
Alternative revenue programs	(21)	40	(11)
Stock-based compensation	16	24	17
Regulatory assets	24	(126)	20
Regulatory liabilities	(21)	(20)	24
Tax credit sales	179	112	24
Other non-cash income and expenses, net	64	57	40
Changes in working capital:
Accounts receivable and unbilled revenues	(16)	(66)	(29)
Margin deposits	9	(33)	24
Accounts payable and accrued liabilities	44	47	(166)
Margin deposits from wholesale counterparties	16	0	(135)
Other working capital items, net	(10)	(12)	(20)
Contribution to pension and other postretirement plans	(24)	(19)	(14)
Contribution to non-qualified employee benefit trust	(10)	(10)	(7)
Asset Retirement Obligation, Cash Paid to Settle	(13)	(16)	(25)
Other, net	(34)	(15)	(2)
Net cash provided by operating activities	1,118	778	420
Cash flows from investing activities:
Capital expenditures	(1,189)	(1,268)	(1,358)
Purchases of nuclear decommissioning trust securities	(9)	(8)	(1)
Sales of nuclear decommissioning trust securities	4	2	1
Other, net	(2)	(23)	0
Net cash used in investing activities	(1,196)	(1,297)	(1,358)
Cash flows from financing activities:
Proceeds from issuance of long-term debt	310	670	600
Payments on long-term debt	(170)	(130)	(260)
Proceeds from issuances of common stock, net of issuance costs	250	346	485
Issuance (maturities) of commercial paper, net	0	(146)	146
Dividends paid	(225)	(200)	(179)
Other	(23)	(14)	(14)
Net cash provided by financing activities	142	526	778
Change in cash and cash equivalents	64	7	(160)
Cash and cash equivalents, beginning of year	12	5	165
Cash and cash equivalents, end of year	76	12	5
Supplemental disclosures of cash flow information:
Cash paid for interest, net of amounts capitalized	198	174	136
Income taxes, net	(162)	(90)	12
Non-cash investing and financing activities:
Accrued capital additions	126	184	212
Accrued dividends payable	63	57	51
Federal [Member]
Adjustments to reconcile net income to net cash provided by operating activities:
Tax credit sales	$ 179	$ 112	$ 23

Stock-based Compensation (Tables)

12 Months Ended

Dec. 31, 2025

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

Summary of RSU Activity

Pursuant to the Portland General Electric Company Stock Incentive Plan as amended and restated effective April 21, 2023 (the Plan), the Company may grant a variety of equity-based awards, including 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, 2022		579,461		$	49.23
Granted		421,788			47.82
Forfeited		(57,566	)		48.03
Vested		(297,986	)		52.45
Nonvested units as of December 31, 2023		645,697			47.57
Granted		478,509			41.02
Forfeited		(20,774	)		45.32
Vested		(306,639	)		44.76
Nonvested units as of December 31, 2024		796,793			44.78
Granted		582,444			41.68
Forfeited		(39,944	)		42.48
Vested		(364,659	)		47.31
Nonvested units as of December 31, 2025		974,634			42.58

Schedule of Fair Value Determined Using a Monte Carlo Simulation

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


	2025							2024						2023
Risk-free interest rate						4.4	%					4.3	%					4.2	%
Expected term (in years)					2.9							2.9						2.9
Volatility		15.5	%	—		65.8	%		12.4	%	—	53.2	%		21.8	%	—	31.5	%

Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2025

Regulatory Assets and Liabilities Disclosure [Abstract]

Regulatory Assets and Liabilities

NOTE 7: REGULATORY ASSETS AND LIABILITIES

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

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


		As of December 31,
		2025						2024
	Remaining Amortization Period	Earning a Return (1)		Not Earning a Return		Total		Total
Regulatory assets:
Price risk management	(2)	$	—	$	181	$	181	$	185
Pension plans	(3)		—		64		64		84
Trojan decommissioning activities	2059		—		161		161		161
February 2021 ice storm and damage	2029		46		—		46		58
January 2024 storm and damage	(4)		48		—		48		46
Reliability contingency events	(4)		90		—		90		90
2020 Labor Day wildfire	2029		19		—		19		24
Wildfire mitigation	(5)		42		—		42		43
Other	Various		74		62		136		146
Total regulatory assets		$	319	$	468	$	787	$	837
Regulatory liabilities:
Asset retirement removal costs	(6)	$	1,245	$	—	$	1,245	$	1,199
Deferred income taxes	(7)		228		—		228		179
Clearwater RAC	(8)		22		—		22		40
Other	Various		58		11		69		75
Total regulatory liabilities		$	1,553	$	11	$	1,564	$	1,493

(1)

(2)

(3)

Recovery expected over the average service life of employees.

(4)

Amortization period has yet to be decided.

(5)

(6)

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

(7)

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.

(8)

Amortization began on March 1, 2025.

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.

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. For additional information concerning Trojan decommissioning activities, see Note 8, Asset Retirement Obligations.

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.

January 2024 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 storm that ultimately led Oregon’s Governor to declare a state of emergency in January 2024. The declared state of emergency allows PGE to seek recovery of incremental storm expenses through the OPUC pre-authorized emergency deferral mechanism, subject to the application of an earnings test. On February 9, 2024, PGE filed a Notice of Deferral with the OPUC, under Docket UM 2190, related to the emergency restoration costs for the January storm, and through December 31, 2025 the Company has deferred $48 million, including interest, under the deferral. PGE believes the amounts deferred as of December 31, 2025 are probable of recovery under the emergency deferral mechanism, and no earnings test adjustment is necessary as PGE's 2024 regulated return on equity did not exceed the OPUC's authorized rate. The OPUC has significant discretion in making the final determination of recovery and their conclusion of overall prudence, including application of the earnings test, 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.

Reliability contingency events represents costs deferred under the reliability contingency event (RCE) mechanism, which allows PGE to defer and recover 80% of prudent costs for RCEs above amounts forecasted in the Company’s AUT, without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. As of December 31, 2025, PGE’s deferred balance related to RCEs was $90 million, which includes $88 million related to RCEs deferred in 2024 and $2 million related to RCEs deferred in 2025. PGE files the results of the PCAM annually with the OPUC no later than July 1, initiating a regulatory review process that typically results in a final determination and order from the OPUC by the end of the year of filing, with any resulting refund or collection impacting customer prices effective in the following year. RCE costs incurred in 2024 and in 2025 will be included in the PCAM for 2024 and 2025. The Company filed the PCAM for 2024 on July 1, 2025, and the proceeding is on-going with a Commission decision anticipated in the first quarter of 2026. The Company expects to file the PCAM for 2025 no later than July 1, 2026. PGE believes the deferred amounts as of December 31, 2025 are probable of recovery. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence 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.

2020 Labor Day wildfire represents 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.

Wildfire mitigation represents incremental costs and investments made by PGE related to intensifying efforts on its system to mitigate the risk of wildfire and improve resiliency to wildfire damage under Oregon Senate Bill 762, enacted in 2021. These efforts include enhanced tree and brush clearing, hardening and undergrounding equipment, and making emergency plans in close partnership with various land and emergency management agencies to further expand the use of a public safety power shutoff, when the risk warrants. In December 2025, PGE submitted its 2026-2028 risk-based Wildfire Mitigation Plan. This plan is subject to annual updates, as well as the OPUC's approval.

As of December 31, 2025 and December 31, 2024, PGE’s deferred balance related to wildfire mitigation was $42 million and $43 million, respectively. The 2025 balance is comprised of:

•

2024 AAC - Beginning January 1, 2024, and in conjunction with the Company’s 2024 GRC proceeding, PGE removed the $24 million of wildfire mitigation operations and maintenance (O&M) expense recovery from base rates, with the intent of recovering the current year forecasted O&M expense within the automatic adjustment clause (AAC) in a separate tariff. On February 16, 2024, PGE submitted an advice filing to the OPUC to update the tariff to reflect prospective wildfire mitigation costs for 2024, which included $45 million of O&M expense and $4 million for the revenue requirement of capital placed in service. On July 23, 2024, the OPUC reached a decision that allowed PGE to begin collecting $24 million of O&M expense and $4 million for the revenue requirement of capital placed in service. Collection will occur over a nine-month period, which began August 1, 2024. Although the approved amount of collections in 2024 is less than actual costs, PGE does not believe it is precluded from deferring such costs and believes they are prudently incurred and probable of recovery. Any differences between actual expense and customer collections will be recorded as regulatory assets or liabilities within the AAC balancing account, which will be subject to a prudency review, but will not be subject to an earnings test. As of December 31, 2025, there was $23 million deferred as a regulatory asset in the balancing account related to 2024. PGE submitted an additional filing to seek recovery of the remaining O&M expense on October 17, 2025. On February 13, 2026, PGE filed a Stipulation reflecting an all-party settlement that, if approved by the OPUC, would allow PGE recovery of its deferred amounts related to 2024 O&M. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence 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.

•

2025 AAC - In conjunction with PGE’s filed 2025 Wildfire Mitigation Plan, PGE submitted a series of advice filings in 2025 with the intent of recovering the $56 million related to O&M and $12 million related to the capital revenue requirement in a two-phased approach. The first phase, which includes $24 million of O&M to be collected over a twelve-month period, was approved by the OPUC in February 2025, with a tariff effective date of March 1, 2025. The second phase, which was approved by the OPUC in May 2025, will be collected over a twelve-month period beginning June 1, 2025, and includes $12 million of O&M and the entire $12 million related to capital revenue requirement. Although the OPUC has only approved a portion of PGE’s 2025 wildfire mitigation O&M, PGE does not believe it is precluded from deferring such costs. Any differences between actual expense and customer collections will be recorded as regulatory assets or liabilities within the AAC balancing account, which will be subject to a prudence review, but will not be subject to an earnings test. As of December 31, 2025, there was $19 million deferred as a regulatory asset in the balancing account related to 2025. PGE submitted an additional filing to seek recovery of the remaining 2025 forecasted O&M expense on October 17, 2025. The OPUC has significant discretion in making the final determination of recovery. The OPUC’s conclusion of overall prudence 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.

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.

Clearwater RAC represents all costs and benefits associated with the Clearwater wind facility. Under the RAC, during 2023, the Company submitted a filing for Clearwater proposing to defer the revenue requirement, net of net variable power cost (NVPC) benefits, from the in-service date of January 2024 until Clearwater was reflected in customer prices, which was March 1, 2025. For the year ended December 31, 2024, PGE deferred the revenue requirement, net of NVPC benefits resulting in a net regulatory liability of $40 million, which began amortizing as a refund to customers on March 1, 2025 over a twelve-month period, as approved in OPUC Order 25-075 issued February 21, 2025. For the period of January 1, 2025 through December 31, 2025, PGE deferred an additional net $13 million regulatory liability, which remains subject to a future regulatory review, representing the deferred revenue requirement that PGE believes is probable of recovery, net of NVPC that is probable of refund to customers under the RAC for that period. The OPUC has significant discretion on overall prudence and in making the final determination of recovery or refund. Any cost disallowance or increased refunds would be recognized as a charge to earnings.

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Current assets:
Cash and cash equivalents	$ 76	$ 12
Accounts receivable, net	460	456
Inventories, at average cost:
Materials and supplies	99	92
Fuel	25	22
Regulatory assets-current	168	205
Other current assets	244	238
Total current assets	1,072	1,025
Electric utility plant:
In service	15,996	14,863
Accumulated depreciation and amortization	(5,419)	(5,085)
Total in service, net	10,577	9,778
Construction work-in-progress	416	567
Electric utility plant, net	10,993	10,345
Regulatory assets - noncurrent	619	632
Nuclear decommissioning trust	42	30
Non-qualified benefit plan trust	36	34
Other noncurrent assets	468	478
Total assets	13,230	12,544
Current liabilities:
Accounts payable	330	365
Liabilities from price risk management activities - current	158	147
Current portion of long-term debt	0	170
Current portion of finance lease obligations	27	27
Accrued expenses and other current liabilities	478	410
Total current liabilities	993	1,119
Long-term debt, net of current portion	4,662	4,354
Regulatory liabilities-noncurrent	1,490	1,440
Deferred income taxes	601	564
Deferred investment tax credits	194	61
Unfunded status of pension and postretirement plans	107	140
Liabilities from price risk management activities-noncurrent	56	72
Asset retirement obligations	299	292
Non-qualified benefit plan liabilities	70	74
Finance lease obligations, net of current portion	263	276
Other noncurrent liabilities	362	358
Total liabilities	9,097	8,750
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; 115,559,079 and 109,342,251 shares issued and outstanding as of December 31, 2025 and 2024, respectively	2,382	2,118
Accumulated other comprehensive loss	(4)	(4)
Retained earnings	1,755	1,680
Total shareholders' equity	4,133	3,794
Total liabilities and shareholders' equity	$ 13,230	$ 12,544

Revenue Recognition (Policies)	12 Months Ended
Revenue Recognition (Policies)	Dec. 31, 2025
Revenue Recognition [Abstract]
Revenue from Contract with Customer	PGE applies the invoice method to measure its progress towards satisfactorily completing its performance obligations.
Revenue, Transaction Price Measurement, Tax Exclusion	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	PGE’s Wholesale revenues consist primarily of 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.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-17

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 19
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-19

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-18

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 18
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-18

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-20

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-20

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-20

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 20
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-20

Reference 9: http://www.xbrl.org/2003/role/exampleRef
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (e)
-SubTopic 10
-Topic 235
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147483426/235-10-50-4

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2025

Summary of Significant Accounting Policies [Abstract]

Summary of Significant Accounting Policies

NOTE 2: 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 $59 million as of December 31, 2025 and $12 million as of December 31, 2024 included within Cash and cash equivalents in the consolidated balance sheets.

Accounts Receivable

Accounts receivable are recorded at invoiced amounts based on prices that are subject to federal (FERC) and State (OPUC) regulations. Balances do not bear interest; however, late fees are assessed beginning eight calendar 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 53 business days after the due date of the final invoice.

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.

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. The balance of provisions for uncollectible accounts receivable was immaterial and there have been no material write-offs of accounts receivable related to wholesale sales in 2025, 2024, or 2023.

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 prices. 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, 2025 and $125 million as of December 31, 2024. Letters of credit provided as collateral are not recorded on the Company’s consolidated balance sheets and there were $123 million and $18 million as of December 31, 2025 and 2024, 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 allocable overheads such as engineering, supervision, employee benefits, certain administrative costs directly related to construction, 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 performed under long-term service agreements 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 related to recently completed plant that are 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 (GRC) for equity funds and the cost of actual borrowings for debt funds. 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 6.7% in 2025, 6.7% in 2024, and 6.5% in 2023. AFUDC from borrowed funds, reflected as a reduction to Interest expense, net, was $11 million in 2025, $15 million in 2024, and $13 million in 2023. AFUDC from equity funds, included in Other income, net, was $18 million in 2025, $23 million in 2024, and $19 million in 2023.

Depreciation and Amortization

Depreciation is computed using the straight-line method, based upon original cost, and includes an estimate for cost of removal and expected salvage. Depreciation expense as a percent of the related average depreciable plant in service was 3.6% in 2025, and 3.5% in 2024 and 3.4% in 2023. 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.

Generation plants are depreciated using a life-span methodology, which is designed to recover the plant investment by the estimated retirement dates, which range from 2035 to 2064. Depreciation is provided on PGE’s other classes of plant in service over their estimated average service lives, which are as follows (in years):


Transmission			58
Distribution			50
Energy Storage			16
General			17

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 three, 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 $622 million and $611 million as of December 31, 2025 and 2024, respectively, with amortization expense of $76 million in 2025, $72 million in 2024, and $61 million in 2023. Future estimated amortization expense as of December 31, 2025 is as follows: $79 million in 2026; $73 million in 2027; $49 million in 2028; $29 million in 2029; and $17 million in 2030.

Marketable Securities

Nuclear decommissioning trust

The Nuclear decommissioning trust (NDT) 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 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

PGE’s non-qualified benefit plans (NQBP) reflects assets held in trust to cover the obligations of PGE’s 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 assets 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.

Other Investments

PGE has investments in non-marketable equity securities for which the Company does not have controlling financial interest however, based on PGE’s ownership interest, are accounted for under the equity method of accounting. These investments are accounted for at cost, adjusted for the Company’s proportionate share of the investee’s earnings or losses, distributions received, and impairments, if any.

As of December 31, 2025 and 2024, equity method investments were $19 million and $13 million, respectively, recorded in Other noncurrent assets on the Company’s consolidated balance sheets. For the years ended December 31, 2025, 2024, and 2023, the Company's share of net earnings or losses from equity method

investments were immaterial. PGE’s share of earnings or losses are recorded as Miscellaneous income, net within Other income, net on the Company’s consolidated statements of income.

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: i) probable future reductions in revenue associated with amounts that are expected to be credited to customers through the ratemaking process; or ii) current collections for future expected costs. 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 verify 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 includes 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 9.34% for 2025 and 9.5% for 2024.

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, 2025, PGE’s actual NVPC was $6 million below baseline NVPC, which is within the established deadband range. Accordingly, there is no estimated refund

to customers under the PCAM for 2025. For the year ended December 31, 2024, actual NVPC was below baseline NVPC by $78 million, which was outside the established deadband range. Pursuant to the PCAM and related earnings test, because PGE’s preliminary regulatory ROE was below 10.5%, there was no estimated refund to customers under the PCAM for 2024.

The Company also has a reliability contingency event (RCE) mechanism, which operates under the PCAM tariff. This mechanism was approved by the OPUC as part of the 2024 GRC proceedings. The RCE mechanism allows PGE to defer and recover 80% of prudent costs for RCEs above amounts forecasted in the Company’s Annual Power Cost Update Tariff (AUT), without application of an earnings test, with the remaining 20% flowing through operating expenses and subject to the existing PCAM. This mechanism expired at the end of 2025.

For additional information concerning PCAM, see Note 7, Regulatory Assets and Liabilities.

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 customer prices is recorded as a regulatory asset or liability in the Company’s consolidated balance sheets. As of December 31, 2025, PGE had a net regulatory asset related to Utility plant AROs in the amount of $6 million and a net regulatory asset related to Trojan decommissioning ARO activities of $161 million. As of December 31, 2024, 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 $161 million. For additional information concerning the Company’s regulatory assets and liabilities related to AROs, see Note 7, Regulatory Assets and Liabilities.

Contingencies

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 NQBP 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 $70 million in 2025, $63 million in 2024, and $56 million in 2023.

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 and Renewable Adjustment Clause (RAC) are considered earned under alternative revenue programs, as these amounts represent contracts 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. Under the RAC, in 2024 and 2025, the Company has deferred amounts related to the Clearwater Wind Development (Clearwater). For further information, see “Clearwater RAC” within Note 7, Regulatory Assets and Liabilities.

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, 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. Amounts deferred in 2022 continued to be amortized through the end of 2024.

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.

Time-based and performance-based restricted stock unit (RSU) grant agreements provide that, if a grantee satisfies the “rule of 75” upon termination of employment for reasons other than cause, then: i) in the case of time-based RSUs, all unvested awards will vest; and ii) in the case of performance-based RSUs, the grantee will be eligible for full vesting, based on performance results, notwithstanding early termination. For purposes of these provisions, a recipient satisfies the rule of 75 if the recipient has no less than 5 years of service and the recipient’s age plus years of service is at least 75. PGE accelerates recognition of compensation cost to the date the rule of 75 is met if the date is earlier than the vesting date of the award.

For additional information concerning the Company’s Stock-Based Compensation, see Note 14, Stock-Based Compensation.

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. Investment Tax Credits (ITC) are deferred and amortized as a reduction of income tax expense over the estimated useful lives of the related properties. The weighted average life of the related properties is 16 years as of December 31, 2025. Any valuation allowance would be established to reduce deferred tax assets to the “more likely than not” amount expected to be realized upon transfer or in future tax returns. Valuation allowances related to a discount incurred on transfer transactions that are recorded to deferred tax expense are currently recoverable through a regulatory asset.

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 $228 million and $179 million as of December 31, 2025 and 2024, 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.

The Inflation Reduction Act of 2022 (IRA) was signed into law on August 16, 2022. The IRA provides an election to transfer (i.e., sell) certain tax credits to unrelated third parties in exchange for cash consideration. PGE has elected an accounting policy to account for the transfer of Federal production tax credits (PTCs) and ITCs, including discounts, within the scope of Accounting Standards Codification 740 – Income Taxes. Tax credit sales are classified as an operating activity in the consolidated statements of cash flows, and included in Cash paid for income taxes, net within the supplemental disclosures of cash flow information. Derecognition of the transferred deferred tax asset occurs when the buyer obtains control of the tax credit.

Recent Accounting Pronouncements

In November 2024, the FASB issued ASU 2024-03 Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. ASU 2024-03 requires additional disclosure, in the notes to financial statements, of specified information about certain costs and expenses. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2027. Early adoption is permitted. PGE is assessing the impact of adoption on the consolidated financial statements and does not plan to early adopt the standard.

In December 2025, the FASB issued ASU 2025-10 Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities. ASU 2025-10 adds guidance to ASC 832 on the recognition, measurement, and presentation of government grants. For calendar year-end entities, the update will be effective for annual periods beginning on January 1, 2029. Early adoption is permitted. PGE is assessing the impact of adoption on the consolidated financial statements and does not plan to early adopt the standard.

Recently Adopted Accounting Pronouncements

For the year ended December 31, 2025, PGE adopted ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. ASU 2023-09 amends Topic 740 to require entities to annually disaggregate the income tax rate reconciliation into prescribed categories, as well as to disclose income taxes paid disaggregated by jurisdiction. Because PGE elected to apply the guidance retrospectively, items for prior periods were reclassified to conform with current year presentation. As the standard relates only to disclosures, the adoption did not have a material impact on PGE’s results of operation, financial position, or cash flows. For new required disclosures and further information, see Note 12, Income Taxes.

Risk Management

12 Months Ended

Dec. 31, 2025

Price Risk Management [Abstract]

Risk Management

NOTE 6: 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, and secure reasonably priced power for, 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 and sells environmental credits in the wholesale marketplace. 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. 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,
	2025		2024
Current assets:
Commodity contracts:
Electricity	$	29	$	18
Natural gas		3		14
Total current derivative assets(1)		32		32
Noncurrent assets:
Commodity contracts:
Electricity		1		1
Natural gas		—		1
Total noncurrent derivative assets(1)		1		2
Total derivative assets(2)	$	33	$	34
Current liabilities:
Commodity contracts:
Electricity	$	19	$	32
Natural gas		139		115
Total current derivative liabilities		158		147
Noncurrent liabilities:
Commodity contracts:
Electricity		31		24
Natural gas		25		48
Total noncurrent derivative liabilities		56		72
Total derivative liabilities(2)	$	214	$	219

(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, 2025 and 2024, 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 December 31, 2035, were as follows (in millions):


	As of December 31,
	2025			2024
Commodity contracts:
Electricity		1	MWh		2	MWh
Natural gas		224	Dth		199	Dth
Foreign currency contracts	$	9	Canadian	$	34	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, 2025, gross amounts included as Price risk management liabilities subject to master netting agreements were $41 million, all of which was for natural gas, for which PGE has posted $14 million collateral. As of December 31, 2024, gross amounts included as Price risk management liabilities subject to master netting agreements were $41 million, entirely for natural gas, for which PGE had posted $16 million collateral.

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,
	2025			2024			2023
Commodity contracts:
Electricity	$	(26	)	$	(17	)	$	(130	)
Natural Gas		206			30			357
Foreign currency contracts		(1	)		(1	)		(1	)

Net unrealized and certain net realized losses (gains) presented in the table above are offset within the consolidated statements of income by the effects of regulatory accounting. Of the net amounts recognized in Net income, net gains of $24 million, net gains of $5 million, and net losses of $403 million for the years ended December 31, 2025, 2024, and 2023, respectively, have been offset.

Assuming no changes in market prices and interest rates, the following table presents the years in which the net unrealized losses recorded as of December 31, 2025 related to PGE’s derivative activities would become realized as a result of the settlement of the underlying derivative instrument (in millions):


	2026			2027		2028		2029		2030		Thereafter		Total
Commodity contracts:
Electricity	$	(9	)	$	2	$	4	$	3	$	3	$	17	$	20
Natural gas		136			20		3		2		—		—		161
Net unrealized loss	$	127		$	22	$	7	$	5	$	3	$	17	$	181

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, 2025 was $208 million. The Company has posted $72 million in collateral, consisting of $59 million of cash and $13 million of letters of credit. If the credit-risk-related contingent features underlying these agreements were triggered as of December 31, 2025, the cash requirement to either post as collateral or settle the instruments immediately would have been $146 million. As of December 31, 2025, 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, 2025, PGE received from counterparties $26 million in collateral, consisting of $5 million of letters of credit and $21 million of cash. 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.

- Definition

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

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+ Details

Contingencies

12 Months Ended

Dec. 31, 2025

Contingencies [Abstract]

Contingencies

NOTE 19: 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.

EPA Investigation of Portland Harbor

An investigation by the United States Environmental Protection Agency (EPA) that began in 1997 of a segment of the Willamette River known as Portland Harbor revealed significant contamination of river sediments. The EPA subsequently included Portland Harbor on the National Priority List pursuant to the federal Comprehensive Environmental Response, Compensation, and Liability Act as a federal Superfund site. 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 the EPA’s cost estimates are understated, and PGE estimates undiscounted total remediation costs for Portland Harbor per the ROD could range from $1.9 billion to $3.5 billion. The EPA acknowledged the estimated costs were based on data that was outdated and that pre-remedial design sampling was necessary to gather updated baseline data to better refine the remedial design and estimated cost.

A small group of PRPs performed pre-remedial design sampling to update baseline data and submitted the data in an updated evaluation report to the EPA for review. The evaluation report concluded that the conditions of Portland Harbor have improved substantially with the passage of time. In response, the EPA indicated that while it would use the data to inform implementation of the ROD, the EPA’s conclusions remained materially unchanged. With the completion of pre-remedial design sampling, Portland Harbor is now in the remedial design phase, which consists of additional technical information and data collection to be used to design the expected remedial actions. Certain PRPs, not including PGE, have entered into consent agreements to perform remedial design and the EPA has indicated it will take the initial lead to perform remedial design on the remaining areas. The Company anticipates that remedial design costs will ultimately be allocated to PRPs as a part of the allocation process for remediation costs of the EPA’s preferred remedy. The entirety of Portland Harbor continues 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.

In November 2024, the EPA issued a Special Notice Letter (SNL) to 60 entities, including PGE, with requirements and deadlines that may ultimately lead to litigation, in relation to Portland Harbor. By letter dated May 30, 2025, PGE responded in coordination with other SNL recipients, as recommended by the EPA. Formal negotiations are anticipated to take approximately two years, concluding in fall 2026 and no later than March 2027, according to the EPA.

Based on the above facts and remaining uncertainties in the voluntary allocation process, PGE does not currently have sufficient information to reasonably estimate the amount, or range, of its potential liability or determine an allocation percentage that would represent PGE’s portion of the liability to clean-up Portland Harbor. However, the Company may obtain sufficient information, prior to the final determination of allocation percentages among PRPs, to develop a reasonable estimate, or range, of its potential liability that would require recording of the estimate, or low end of the range. The Company’s liability related to the cost of remediating Portland Harbor could be material to PGE’s financial position.

In cases in which injuries to natural resources have occurred as a result of releases of hazardous substances, federal and state natural resource trustees may seek to recover for damages at such sites, which are referred to as Natural Resource Damages (NRD). The EPA does not manage NRD assessment activities but does provide claims information and coordination support to the NRD trustees. NRD assessment activities are typically conducted by a Council made up of the trustee entities for the site. The Portland Harbor NRD trustees consist of the National Oceanic and Atmospheric Administration, the U.S. Fish and Wildlife Service, the State, 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. PGE’s portion of NRD liabilities related to Portland Harbor are immaterial.

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, the PHERA allows the Company to defer estimated liabilities and recover prudently incurred 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.

Colstrip-Related Matters

The Company has a 20% ownership interest in Colstrip, which is located in the state of Montana and operated by one of the co-owners, Talen Montana, LLC. Various business disagreements have arisen amongst the co-owners regarding interpretation of the Ownership and Operation Agreement and other matters. In 2021, an arbitration process was initiated by co-owner, NorthWestern Corporation, against all other co-owners of Colstrip to address such business disagreements and 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 parties have agreed to stay the arbitration proceedings indefinitely. PGE cannot predict the ultimate outcome of this matter.

Wrongful Death Claims

In September 2025, PGE received a complaint filed in Multnomah County Circuit Court on behalf of the estates of three members of the public and their relatives, with regard to three fatalities that occurred during the January 2024 storm and severe winter weather event. The lawsuit seeks a total of $375 million related to their deaths and surviving family members’ claims. Business entities that own and operate an apartment complex, along with a nearby property owner, are also named as defendants. At this time, as the case is in its early stages, PGE is unable to estimate a range of any reasonably possible loss. The Company denies liability and plans to defend its case.

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

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+ Details

Schedule of Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Trojan decommissioning activities	$ 208	$ 205
Utility plant	75	80
Non-utility property	29	25
Asset Retirement Obligation	312	310	$ 286	$ 289
Asset Retirement Obligation, Current	13	18
Asset Retirement Obligations, Noncurrent	299	292
Asset Retirement Obligation, Cash Paid to Settle	$ (13)	$ (16)	$ (25)

Stock-based Compensation

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Stock-based Compensation

NOTE 14: STOCK-BASED COMPENSATION


	Units			Weighted Average Grant Date Fair Value
Nonvested units as of December 31, 2022		579,461		$	49.23
Granted		421,788			47.82
Forfeited		(57,566	)		48.03
Vested		(297,986	)		52.45
Nonvested units as of December 31, 2023		645,697			47.57
Granted		478,509			41.02
Forfeited		(20,774	)		45.32
Vested		(306,639	)		44.76
Nonvested units as of December 31, 2024		796,793			44.78
Granted		582,444			41.68
Forfeited		(39,944	)		42.48
Vested		(364,659	)		47.31
Nonvested units as of December 31, 2025		974,634			42.58

A total of 4,687,500 shares of common stock were registered for issuance under the Plan, of which 779,123 shares remain available for future issuance as of December 31, 2025.

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 $10 million for the year ended December 31, 2025, $8 million for 2024, and $9 million for 2023.

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 (ROE); 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 for 2023 and 2024 grants. For 2025 grants, ROE is replaced with TSR as one of the three equally-weighted metrics, and there is no modifier. 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:


	2025							2024						2023
Risk-free interest rate						4.4	%					4.3	%					4.2	%
Expected term (in years)					2.9							2.9						2.9
Volatility		15.5	%	—		65.8	%		12.4	%	—	53.2	%		21.8	%	—	31.5	%

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 98.40%, 115.07%, and 81.65% of awarded performance-based RSUs for the respective 2025, 2024, and 2023 grants, with an estimated 5% forfeiture rate on the grant date.

The total value of performance-based RSUs vested was $8 million for the year ended December 31, 2025, $6 million for 2024, and $7 million for 2023.

Stock-based compensation, included in Administrative and other expense in the consolidated statements of income, was $16 million for the year ended December 31, 2025, $24 million for 2024, and $17 million in 2023. 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 2025, 2024 and 2023.

As of December 31, 2025, unrecognized stock-based compensation expense was $9 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.

Long-term Debt and Other Financing Arrangements - Long-term Debt Lessee, Operating Lease, Liability Maturity (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Disclosure [Abstract]
2026	$ 5
2027	5
2028	5
2029	5
2030	5
Thereafter	55
Finance Leases, Total lease payments	80
Less: Imputed Interest	(49)
Present value of minimum payments	$ 31

Employee Benefits (Tables)

12 Months Ended

Dec. 31, 2025

Employee Benefits [Abstract]

Summary of Assets and Liabilities associated with Non Qualified Benefit 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):


	2025						2024
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust assets	$	15	$	21	$	36	$	16	$	18	$	34
Non-qualified benefit plan liabilities *		13		57		70		14		60		74

* For the NQBP, excludes the current portion of $2 million in 2025 and in 2024, which are classified in Accrued expenses and other current liabilities in the consolidated balance sheets.

Schedule of Allocation of Plan Assets

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


	As of December 31,
	2025						2024
	Actual			Target *			Actual			Target *
Defined Benefit Pension Plan:
Growth securities		55	%		55	%		53	%		55	%
Liability Hedging Fixed Income securities		45			45			47			45
Total		100			100			100			100
Other Postretirement Benefit Plans:
Equity securities		40	%		39	%		40	%		38	%
Debt securities		60			61			60			62
Total		100			100			100			100
Non-Qualified Benefits Plans:
Equity securities		1	%		1	%		1	%		2	%
Debt securities		2			2			6			5
Insurance contracts		97			97			93			93
Total		100			100			100			100

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

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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, 2025
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	59	$	—	$	—	$	—	$	59
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		14		11		—		—		25
Corporate credit		—		10		—		—		10
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		1		—		—		—		1
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		7		7
Price risk management activities: (1) (4)
Electricity		—		29		1		—		30
Natural gas		—		3		—		—		3
	$	74	$	53	$	1	$	14	$	142
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	13	$	37	$	—	$	50
Natural gas		—		160		4		—		164
	$	—	$	173	$	41	$	—	$	214

(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 $35 million, which are recorded at cash surrender value.

(4)

For further information regarding price risk management derivatives, see Note 6, Risk Management.


	December 31, 2024
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	12	$	—	$	—	$	—	$	12
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		10		6		—		—		16
Corporate credit		—		7		—		—		7
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		2		—		—		—		2
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		4		4
Price risk management activities: (1) (4)
Electricity		—		18		1		—		19
Natural gas		—		15		—		—		15
	$	24	$	46	$	1	$	11	$	82
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	25	$	31	$	—	$	56
Natural gas		—		159		4		—		163
	$	—	$	184	$	35	$	—	$	219

(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 $32 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, 2025:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		5		5
Collective trust funds		—		—		—		473		473
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	479	$	492
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		5		—		—		—		5
Debt securities—Domestic		—		5		—		—		5
Investments measured at NAV:
Money market funds		—		—		—		12		12
Collective trust funds		—		—		—		4		4
	$	5	$	7	$	—	$	16	$	28
As of December 31, 2024:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		30		30
Collective trust funds		—		—		—		440		440
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	471	$	484
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		4		—		—		—		4
Debt securities—Domestic government		—		4		—		—		4
Investments measured at NAV:
Money market funds		—		—		—		11		11
Collective trust funds		—		—		—		4		4
	$	4	$	6	$	—	$	15	$	25

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

Schedule of Defined Benefit Plans Disclosures

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, 2025 and 2024. Information related to the Other NQBP is not included in the following tables (in millions):


	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2025			2024			2025			2024			2025			2024
Benefit obligation:
As of January 1	$	612		$	690		$	37		$	35		$	16		$	18
Service cost		10			10			1			1			—			—
Interest cost		32			33			2			2			1			—
Actuarial (gain) loss		7			(40	)		—			1			1			—
Benefits paid from plan assets		(29	)		(78	)		(2	)		(3	)		(3	)		(2	)
Administrative expenses		(3	)		(3	)		—			—			—			—
Plan settlements		(40	)		—			—			—			—			—
Special/contractual termination benefits		—			—			—			1			—			—
As of December 31	$	589		$	612		$	38		$	37		$	15		$	16
Fair value of plan assets:
As of January 1	$	484		$	530		$	25		$	23		$	16		$	17
Actual return on plan assets		58			19			3			2			(1	)		(1	)
Company contributions		22			16			2			3			3			2
Benefit payments		(29	)		(78	)		(2	)		(3	)		(3	)		(2	)
Administrative expenses		(3	)		(3	)		—			—			—			—
Plan settlements		(40	)		—			—			—			—			—
As of December 31	$	492		$	484		$	28		$	25		$	15		$	16
Unfunded position as of December 31	$	(97	)	$	(128	)	$	(10	)	$	(12	)	$	—		$	—
Accumulated benefit plan obligation as of December 31	$	551		$	574		N/A			N/A			$	15		$	16
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	15		$	16
Current liability		—			—			—			(1	)		(2	)		(2	)
Noncurrent liability		(97	)		(128	)		(10	)		(11	)		(13	)		(14	)
Net asset (liability)	$	(97	)	$	(128	)	$	(10	)	$	(12	)	$	—		$	—
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	(16	)	$	(20	)	$	(2	)	$	—		$	1		$	—
Net settlement (loss)		(4	)		—			—			—			—			—
Amortization of net actuarial gain (loss)		—			—			—			—			(1	)		(1	)
	$	(20	)	$	(20	)	$	(2	)	$	—		$	—		$	(1	)
Amounts included in AOCL: *
Net actuarial loss (gain)	$	65		$	85		$	(5	)	$	(3	)	$	6		$	6
Prior service cost		(1	)		(1	)		—			—			—			—
	$	64		$	84		$	(5	)	$	(3	)	$	6		$	6

* 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 a loss of $7 million and a gain of $40 million, and the changes between actual and expected return on plan assets were a gain of $23 million and a loss of $20 million, for the years ended December 31, 2025 and 2024, respectively.

•

For the other postretirement benefits, actuarial gains and losses due to demographic experience, including assumption changes, were an immaterial loss and a loss of $1 million, and the changes between actual and expected return on plan assets were a gain of $2 million and a gain of $1 million, for the years ended December 31, 2025 and 2024, respectively.

Schedule of Net Benefit Costs

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
	2025			2024			2023			2025			2024			2023			2025		2024		2023
Service cost	$	10		$	10		$	10		$	1		$	1		$	1		$	—	$	—	$	—
Interest cost on benefit obligation		32			33			37			2			2			2			1		—		1
Expected return on plan assets		(36	)		(39	)		(43	)		(1	)		(1	)		(1	)		—		—		—
Amortization of prior service credit		—			—			(1	)		—			—			—			—		—		—
Amortization of net actuarial loss (gain)		—			—			—			—			—			(1	)		1		1		1
Settlement loss (gain)		4			—			—			—			—			(1	)		—		—		—
Net periodic benefit cost	$	10		$	4		$	3		$	2		$	2		$	—		$	2	$	1	$	2

Summary of Assumptions

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
	2025			2024			2025			2024			2025			2024
Assumptions used to determine benefit obligations:
Discount rate		5.56	%		5.70	%		5.29	%		5.59	%		5.56	%		5.70	%
								6.11	%		6.11	%
Rate of compensation increase		4.14	%		4.08	%		4.03	%		4.02	%		3.96	%		3.98	%
Assumptions used to determine net periodic benefit cost:
Discount rate		5.70	%		5.13	%		5.59	%		5.18	%		5.70	%		5.13	%
								6.11	%		5.57	%
Rate of compensation increase		4.08	%		4.19	%		4.02	%		4.06	%		3.98	%		4.01	%
Long-term rate of return on plan assets		6.88	%		6.88	%		4.78	%		4.73	%	N/A			N/A

Schedule of Expected Benefit Payments

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
	2026		2027		2028		2029		2030		2031 - 2035
Defined benefit pension plan	$	44	$	44	$	44	$	44	$	43	$	219
Other postretirement benefits		4		4		4		5		4		11
Non-qualified benefit plans		2		2		2		2		2		6
Total	$	50	$	50	$	50	$	51	$	49	$	236

Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2025

Summary of Significant Accounting Policies [Abstract]

Estimated Average Service Lives

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


Transmission			58
Distribution			50
Energy Storage			16
General			17

Risk Management (Policies)	12 Months Ended
Risk Management (Policies)	Dec. 31, 2025
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.

Employee Benefits (Details) - USD ($) $ in Millions	12 Months Ended
Employee Benefits (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Pension and Other Postretirement Benefits Cost (Reversal of Cost)	$ 12	$ 6	$ 5
Payment for Pension Benefits	22	16	0
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	27
Settlement loss on defined benefit pension plan	$ (4)
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Settlement Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other Nonoperating Income (Expense)
401k Plan Company contributions	$ 42	37	31
Company match pre 2009 hire	7.00%
Company match post 2008 hire	7.00%
Company contribution percentage to 401k for post 2008 hires	6.00%
Company contribution percent to 401k for bargaining employees	1.00%
401k Plan Company contributions	$ 42	37	31
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	0	0	1
Actuarial gain (loss)	0	(1)
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	2	1
Actuarial loss (gain)	0	(1)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	(4)	0	0
Actuarial gain (loss)	(7)	40
Defined Benefit Plan, Benefit Obligation, Changes Between Actual and Expected Return on Plan Assets, Gains	23	(20)
Actuarial loss (gain)	(7)	40
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 gain (loss)	1	0
Actuarial loss (gain)	$ 1	$ 0

Long-term Debt and Other Financing Arrangements (Tables)

12 Months Ended

Dec. 31, 2025

Long-Term Debt, Unclassified [Abstract]

Schedule of Long-term Debt

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


	As of December 31,
	2025			2024
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.60% in 2025 and 4.52% in 2024, due at various dates through 2059.	$	4,560		$	4,250
Unsecured term bank loan		—			170
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033		119			119
Total long-term debt		4,679			4,539
Less: Unamortized debt expense		(17	)		(15	)
Less: Current portion of long-term debt		—			(170	)
Long-term debt, net of current portion	$	4,662		$	4,354

Schedule of Future Minimum Principal Payments on Long-term Debt

As of December 31, 2025, the future minimum principal payments on long-term debt are as follows (in millions):


Years ending December 31:
2026	$	—
2027		160
2028		100
2029		200
2030		325
Thereafter		3,894
	$	4,679

Schedule of Future Minimum Payments on Financing Arrangement

As of December 31, 2025, the future minimum payments on the financing arrangement are as follows (in millions):


Years ending December 31:
2026	$	5
2027		5
2028		5
2029		5
2030		5
Thereafter		55
Total Payments		80
Less: Imputed Interest		(49	)
Present value of minimum payments	$	31

- 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
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(22))
-SubTopic 10
-Topic 210
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Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147477314/942-235-S99-2

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 4
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-4

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.12-04(a))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-3

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 69B
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69B

Reference 6: http://www.xbrl.org/2003/role/exampleRef
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-Name Accounting Standards Codification
-Section 55
-Paragraph 69E
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-URI https://asc.fasb.org/1943274/2147481568/470-20-55-69E

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
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-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482925/835-30-45-2

Reference 8: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
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-Section 50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481112/505-10-50-3

Reference 9: http://fasb.org/us-gaap/role/ref/legacyRef
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-Topic 942
-SubTopic 470
-Section 50
-Paragraph 3
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-URI https://asc.fasb.org/1943274/2147477734/942-470-50-3

Reference 10: http://fasb.org/us-gaap/role/ref/legacyRef
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-URI https://asc.fasb.org/1943274/2147481112/505-10-50-8

Reference 11: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 12: http://fasb.org/us-gaap/role/ref/legacyRef
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-Section 50
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-URI https://asc.fasb.org/1943274/2147481112/505-10-50-7

+ Details

Earnings Per Share

12 Months Ended

Dec. 31, 2025

Earnings Per Share [Abstract]

Earnings Per Share

NOTE 15: EARNINGS PER SHARE

Basic earnings per share are computed based on the weighted average number of common shares outstanding during the year. Diluted earnings per share are computed using the weighted average number of common shares outstanding and the effect of dilutive potential common shares outstanding during the year using the treasury stock method. Potential common shares consist of: 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 at-the-market offering program. See Note 13, Equity-based Plans, for additional information on the at-the-market offering program and the resulting 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,
	2025		2024		2023
Weighted average common shares outstanding—basic		110,471		103,946		97,760
Dilutive potential common shares		268		213		192
Weighted average common shares outstanding—diluted		110,739		104,159		97,952

Schedule of Change in Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligation	$ 310	$ 286	$ 289
Asset Retirement Obligation, Liabilities Incurred	0	0	2
Asset Retirement Obligation, Cash Paid to Settle	(13)	(16)	(25)
Asset Retirement Obligation, Accretion Expense	13	12	11
Asset Retirement Obligation, Revision of Estimate	2	28	9
Asset Retirement Obligation	$ 312	$ 310	$ 286

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

AROs consist of the following (in millions):


	As of December 31,
	2025		2024
Trojan decommissioning activities	$	208	$	205
Utility plant		75		80
Non-utility property		29		25
Total asset retirement obligations		312		310
Less: current portion *		13		18
Noncurrent asset retirement obligations	$	299	$	292

* 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

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


	Years Ended December 31,
	2025			2024			2023
Balance as of beginning of year	$	310		$	286		$	289
Liabilities incurred		—			—			2
Liabilities settled		(13	)		(16	)		(25	)
Accretion expense		13			12			11
Revisions in estimated cash flows		2			28			9
Balance as of end of year	$	312		$	310		$	286

Regulatory Assets and Liabilities - Additional Information (Details) - USD ($) $ in Millions				12 Months Ended
	Jul. 23, 2024	Feb. 16, 2024	Jan. 01, 2024	May 31, 2026	Feb. 28, 2026	Dec. 31, 2025	Dec. 31, 2024
Regulatory Asset [Line Items]
Regulatory Assets						$ 787	$ 837
Deferred regulatory asset in balancing account						19
Regulatory assets - noncurrent						$ 619	632
Percentage of prudently incurred reliability contingency events cost						80.00%
Remaining percentage of flowing through operating expenses						20.00%
RCE deferred						$ 2	88
Regulatory Liabilities						1,564	1,493
Clearwater RAC [Member]
Regulatory Asset [Line Items]
Regulatory Liabilities						22	40
Additional net regulatory liability						13
Wildfire Mitigation [Member]
Regulatory Asset [Line Items]
Regulatory Assets						42	$ 43
Operations and maintenance expense recovery from base rates, removed amount			$ 24
Operations and maintenance expense	$ 24	$ 45				56
Revenue requirement of capital placed in service	$ 4	$ 4
Deferred regulatory asset						23
Capital revenue requirement						12
Wildfire Mitigation [Member] \| Forecast [Member]
Regulatory Asset [Line Items]
Operations and maintenance expense				$ 12	$ 24
Capital revenue requirement				$ 12
StormCosts - Jan 2024 [Member]
Regulatory Asset [Line Items]
Regulatory assets - noncurrent						48
StormCosts - RCE [Member]
Regulatory Asset [Line Items]
Regulatory assets - noncurrent						$ 90

Commitments and Guarantees Schdule of Long term contracts for purchase of electric power (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) MW	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Priest Rapids and Wanapum [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 1,584
PGE Share of Output	8.60%
PGE Share of Capacity \| MW	163
commitment costs	$ 67	$ 75	$ 77
Wells [Member]
Long-term Contract for Purchase of Electric Power [Line Items]
Revenue Bonds issued by the Public Utility Districts	$ 200
PGE Share of Output	3.50%
PGE Share of Capacity \| MW	25
commitment costs	$ 10	$ 11	$ 11

Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
Income Taxes (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Tax Credit Carryforward [Line Items]
Tax credit carryforward, federal	$ 69
Deferred tax assets, valuation allowance	0	$ 0
Other Operating Activities, Cash Flow Statement	179	$ 112
PTC [Member]
Tax Credit Carryforward [Line Items]
Other Operating Activities, Cash Flow Statement	37
ITC [Member]
Tax Credit Carryforward [Line Items]
Other Operating Activities, Cash Flow Statement	$ 142

Jointly-owned Plant

12 Months Ended

Dec. 31, 2025

Jointly-owned Plant [Abstract]

Jointly-owned Plant

NOTE 18: JOINTLY-OWNED PLANT

As of December 31, 2025, 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 - Generation		20	%	1986	$	512	$	501	$	3
Colstrip-Transmission	Various (2)			1986		74		45		1
Pelton/Round Butte		50.01	%	1958 / 1964		242		81		10
Total					$	828	$	627	$	14

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

(2) 14% of the 2,260 MW transmission facilities between the Colstrip switchyard to the Broadview switchyard, near Billings, Montana, and 16% of the 1,930 MW transmission facilities between the Broadview switchyard and the interconnection point with Bonneville Power Administration’s transmission system near Townsend, Montana.

Under the respective joint operating agreements for the 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.

Revenue Recognition - Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Subtotal	$ 3,032	$ 2,839	$ 2,439
Alternative revenue programs, net of amortization	21	(40)	11
Other accrued revenues, net	17	16	(3)
Total retail revenues	3,070	2,815	2,447
Wholesale revenues	418	558	418
Other operating revenues	88	67	58
Total Revenues	3,576	3,440	2,923
Gain on Derivative Instruments, Pretax	203	273	185
Residential [Member]
Disaggregation of Revenue [Line Items]
Subtotal	1,486	1,457	1,263
Commercial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	969	914	800
Industrial [Member]
Disaggregation of Revenue [Line Items]
Subtotal	536	435	349
Direct Access customers [Member]
Disaggregation of Revenue [Line Items]
Subtotal	$ 41	$ 33	$ 27

Long-term Debt and Other Financing Arrangements (Details) - USD ($) $ in Millions						12 Months Ended
	Mar. 31, 2025	Mar. 25, 2025	Dec. 31, 2024	Nov. 14, 2024	Feb. 22, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2000	Oct. 27, 2025
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt						$ 310	$ 670	$ 600
Long-term Debt, Current Maturities			$ 170			0	170
Term loan outstanding			4,539			4,679	4,539			$ 68
Repayments of Long-term Debt	$ 102					170	130	$ 260
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033			119			119	$ 119
First Mortgage Bonds [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt		$ 310
First Mortgage Bonds [Member] \| Due In 2035 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt		$ 60
Debt, interest rate		5.36%
First Mortgage Bonds [Member] \| Due In 2045 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt					$ 50
Debt, interest rate					5.72%
First Mortgage Bonds [Member] \| Due In 2055 [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt					$ 200
Debt, interest rate					5.84%
Term Loan [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Long-term Debt				$ 220
Long term debt, face amount				$ 300
Repayments of Long-term Debt			$ 50
Term Loan [Member] \| SOFR [Member]
Debt Instrument [Line Items]
SOFR Adjustment Rate of basis points				0.10%
SOFR adjustment rate of basis points applicable margin				0.80%
Pollution Control Revenue Refunding Bonds [Member]
Debt Instrument [Line Items]
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033						$ 119
Pollution Control Revenue Refunding Bonds One [Member]
Debt Instrument [Line Items]
Debt, interest rate						2.125%
Pollution Control Revenue Bonds at 2.125%						$ 98
Pollution Control Revenue Refunding Bonds Two [Member]
Debt Instrument [Line Items]
Debt, interest rate						2.375%
Pollution Control Revenue Bonds at 2.375%						$ 21
455 Megawatt (MW) Pelton/Round Butte Hydroelectric Project [Member]
Debt Instrument [Line Items]
Ownership interest acquired						100.00%			66.67%
Additional ownership interest acquired									16.66%
Percentage of Ownership Interest Acquired in Second Option Exercised When Ownership Exceed Fifty Percent									0.02%

Credit Facilities (Details) $ in Millions	12 Months Ended
Credit Facilities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Line of Credit Facility [Line Items]
Line of credit facility, current borrowing capacity	$ 750
Maximum borrowing capacity	$ 850
Debt instrument, covenant description	65.00%
Ratio of indebtedness to net capital	53
Commercial paper, maximum term	270 days
Short-term debt	$ 0
Line of credit facility, amount outstanding	0
Letter of credit facility	320
Letters of credit outstanding, amount	192
Authorized short-term debt	900
Letter of Credit [Member]
Line of Credit Facility [Line Items]
Commercial paper	$ 0

Employee Benefits - Summary of Assets and Liabilities associated with Non Qualified Benefit Plans (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	$ 36	$ 34
Non-qualified benefit plan liabilities	70	74
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	21	18
Non-qualified benefit plan liabilities	57	60
Non Qualified Benefit Plans [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Non-qualified benefit plan trust	15	16
Non-qualified benefit plan liabilities	$ 13	$ 14

Basis of Presentation (Policies)

12 Months Ended

Dec. 31, 2025

Basis of Presentation [Abstract]

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.

Commitments and Guarantees

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Guarantees [Text Block]

NOTE 16: COMMITMENTS AND GUARANTEES

Purchase Commitments

As of December 31, 2025, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):


	Payments Due
	2026		2027		2028		2029		2030		Thereafter		Total
Capital and other purchase commitments	$	414	$	136	$	24	$	13	$	1	$	40	$	628
Purchased power and fuel:
Electricity purchases		504		400		395		389		324		2,888		4,900
Capacity contracts		218		128		129		130		125		618		1,348
Public utility districts		10		9		7		1		1		13		41
Natural gas		88		74		36		30		30		161		419
Coal and transportation		38		38		38		38		—		—		152
Total	$	1,272	$	785	$	629	$	601	$	481	$	3,720	$	7,488

Capital and other purchase commitments—Certain commitments have been made for 2026 and beyond that include those related to hydro licenses, upgrades to generation, distribution, transmission and energy storage facilities, information systems, and system maintenance work. Termination of these agreements could result in cancellation charges.

Subsequent to December 31, 2025, PGE has entered into agreements to construct two solar and battery hybrid projects for a total of 615 MW. These projects are not included in the table above and are summarized as follows:

•

Biglow Optimization—PGE entered into an agreement to construct a 125 MW solar facility and a 125 MW BESS in Sherman County, Oregon. PGE will own the resource with an investment of approximately $540 million, excluding AFUDC. The project has an estimated commercial operation date at the end of 2027.

•

Wheatridge Expansion—PGE and NextEra Energy, Inc. entered into agreements to construct a 240 MW solar facility and a 125 MW BESS facility, located in Morrow County, Oregon. PGE will own 110 MW of solar and 65 MW of BESS production capacity with an investment of approximately $490 million, excluding AFUDC. NextEra Energy, Inc. which operates the facility, owns the remaining 130 MW of solar and 60 MW of BESS production capacity and sells their portion of the output to PGE under a 30-year PPA. The project has an estimated commercial operation date at the end of 2027.

Electricity purchases and Capacity contracts—PGE has PPAs 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.

PGE has evaluated its long-term PPAs under variable interest entity accounting guidance. The Company has concluded that it either has no variable interest in the PPAs or, where variable interests exist, PGE is not the primary beneficiary. As a result, consolidation of these entities is not required. This determination is based on PGE lacking both control over significant activities and obligation to absorb losses or receive benefits from the entities’ performance. PGE's financial exposure in these PPAs is limited to capacity and energy payments, which are recovered through the AUT and are subject to the PCAM as detailed in Note 2.

Public utility districts—PGE has long-term PPAs 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 one of 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 one of the Douglas County agreements, 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,		PGE’s Average Share as of December 31, 2025					Contract	Total PGE Contract Costs
	2025		Output			Capacity		Expiration	2025		2024		2023
						(in MW)
Priest Rapids and Wanapum	$	1,584		8.6	%		163	2052	$	67	$	75	$	77
Wells		200		3.5	%		25	2028		10		11		11

The agreements for Priest Rapids and Wanapum 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 2029.

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. In connection with the agreement to transfer certain tax credits generated in 2023 through 2025, PGE provided indemnification against the buyer’s losses related to a failure to satisfy the PTC and ITC qualification or transferability requirements under the Internal Revenue Code, but not due to the action or legal tax status of the buyer or a change in tax law. As of December 31, 2025, 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.

Employee Benefits

12 Months Ended

Dec. 31, 2025

Employee Benefits [Abstract]

Employee Benefits

NOTE 11: 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.

PGE made $22 million in contributions to the pension plan in 2025, $16 million in 2024, and none in 2023. PGE expects to contribute $27 million to the pension plan in 2026.

PGE executed an annuity contract purchase in January 2025 to settle future benefit obligations for a portion of the defined benefit pension plan. The annuity contract purchase, in combination with elevated lump sum benefit elections throughout 2025, resulted in a $4 million settlement loss, which has been recorded in Miscellaneous income (expense), net on the consolidated statement of income.

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.

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):


	2025						2024
	NQBP		Other NQBP		Total		NQBP		Other NQBP		Total
Non-qualified benefit plan trust assets	$	15	$	21	$	36	$	16	$	18	$	34
Non-qualified benefit plan liabilities *		13		57		70		14		60		74

* For the NQBP, excludes the current portion of $2 million in 2025 and in 2024, 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,
	2025						2024
	Actual			Target *			Actual			Target *
Defined Benefit Pension Plan:
Growth securities		55	%		55	%		53	%		55	%
Liability Hedging Fixed Income securities		45			45			47			45
Total		100			100			100			100
Other Postretirement Benefit Plans:
Equity securities		40	%		39	%		40	%		38	%
Debt securities		60			61			60			62
Total		100			100			100			100
Non-Qualified Benefits Plans:
Equity securities		1	%		1	%		1	%		2	%
Debt securities		2			2			6			5
Insurance contracts		97			97			93			93
Total		100			100			100			100

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, 2025:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		5		5
Collective trust funds		—		—		—		473		473
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	479	$	492
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		5		—		—		—		5
Debt securities—Domestic		—		5		—		—		5
Investments measured at NAV:
Money market funds		—		—		—		12		12
Collective trust funds		—		—		—		4		4
	$	5	$	7	$	—	$	16	$	28
As of December 31, 2024:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		30		30
Collective trust funds		—		—		—		440		440
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	471	$	484
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		4		—		—		—		4
Debt securities—Domestic government		—		4		—		—		4
Investments measured at NAV:
Money market funds		—		—		—		11		11
Collective trust funds		—		—		—		4		4
	$	4	$	6	$	—	$	15	$	25

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 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-backed securities, are included in commingled trusts or separately managed accounts. 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.


	Defined Benefit Pension Plan						Other Postretirement Benefits						Non-Qualified Benefit Plans
	2025			2024			2025			2024			2025			2024
Benefit obligation:
As of January 1	$	612		$	690		$	37		$	35		$	16		$	18
Service cost		10			10			1			1			—			—
Interest cost		32			33			2			2			1			—
Actuarial (gain) loss		7			(40	)		—			1			1			—
Benefits paid from plan assets		(29	)		(78	)		(2	)		(3	)		(3	)		(2	)
Administrative expenses		(3	)		(3	)		—			—			—			—
Plan settlements		(40	)		—			—			—			—			—
Special/contractual termination benefits		—			—			—			1			—			—
As of December 31	$	589		$	612		$	38		$	37		$	15		$	16
Fair value of plan assets:
As of January 1	$	484		$	530		$	25		$	23		$	16		$	17
Actual return on plan assets		58			19			3			2			(1	)		(1	)
Company contributions		22			16			2			3			3			2
Benefit payments		(29	)		(78	)		(2	)		(3	)		(3	)		(2	)
Administrative expenses		(3	)		(3	)		—			—			—			—
Plan settlements		(40	)		—			—			—			—			—
As of December 31	$	492		$	484		$	28		$	25		$	15		$	16
Unfunded position as of December 31	$	(97	)	$	(128	)	$	(10	)	$	(12	)	$	—		$	—
Accumulated benefit plan obligation as of December 31	$	551		$	574		N/A			N/A			$	15		$	16
Classification in consolidated balance sheet:
Noncurrent asset	$	—		$	—		$	—		$	—		$	15		$	16
Current liability		—			—			—			(1	)		(2	)		(2	)
Noncurrent liability		(97	)		(128	)		(10	)		(11	)		(13	)		(14	)
Net asset (liability)	$	(97	)	$	(128	)	$	(10	)	$	(12	)	$	—		$	—
Amounts included in comprehensive income:
Net actuarial loss (gain)	$	(16	)	$	(20	)	$	(2	)	$	—		$	1		$	—
Net settlement (loss)		(4	)		—			—			—			—			—
Amortization of net actuarial gain (loss)		—			—			—			—			(1	)		(1	)
	$	(20	)	$	(20	)	$	(2	)	$	—		$	—		$	(1	)
Amounts included in AOCL: *
Net actuarial loss (gain)	$	65		$	85		$	(5	)	$	(3	)	$	6		$	6
Prior service cost		(1	)		(1	)		—			—			—			—
	$	64		$	84		$	(5	)	$	(3	)	$	6		$	6

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

•

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
	2025			2024			2023			2025			2024			2023			2025		2024		2023
Service cost	$	10		$	10		$	10		$	1		$	1		$	1		$	—	$	—	$	—
Interest cost on benefit obligation		32			33			37			2			2			2			1		—		1
Expected return on plan assets		(36	)		(39	)		(43	)		(1	)		(1	)		(1	)		—		—		—
Amortization of prior service credit		—			—			(1	)		—			—			—			—		—		—
Amortization of net actuarial loss (gain)		—			—			—			—			—			(1	)		1		1		1
Settlement loss (gain)		4			—			—			—			—			(1	)		—		—		—
Net periodic benefit cost	$	10		$	4		$	3		$	2		$	2		$	—		$	2	$	1	$	2

The portion of non-service costs attributable to expense related to the pension and other postretirement benefit plans is classified as Miscellaneous income, net within Other income, net on the Company’s consolidated statements of income. A portion of current period non-service costs attributable to capital projects is recorded as a regulatory asset and amortized to Miscellaneous income, 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
	2025			2024			2025			2024			2025			2024
Assumptions used to determine benefit obligations:
Discount rate		5.56	%		5.70	%		5.29	%		5.59	%		5.56	%		5.70	%
								6.11	%		6.11	%
Rate of compensation increase		4.14	%		4.08	%		4.03	%		4.02	%		3.96	%		3.98	%
Assumptions used to determine net periodic benefit cost:
Discount rate		5.70	%		5.13	%		5.59	%		5.18	%		5.70	%		5.13	%
								6.11	%		5.57	%
Rate of compensation increase		4.08	%		4.19	%		4.02	%		4.06	%		3.98	%		4.01	%
Long-term rate of return on plan assets		6.88	%		6.88	%		4.78	%		4.73	%	N/A			N/A

As of December 31, 2025, there are no liabilities with sensitivity to health care cost trend rates.

The expected rate of return on plan assets each year is based on the approved asset allocation. A forward looking building blocks approach is used with historical returns, capital markets information and survey information used to support the expected rate of return on plan assets assumption. 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.

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
	2026		2027		2028		2029		2030		2031 - 2035
Defined benefit pension plan	$	44	$	44	$	44	$	44	$	43	$	219
Other postretirement benefits		4		4		4		5		4		11
Non-qualified benefit plans		2		2		2		2		2		6
Total	$	50	$	50	$	50	$	51	$	49	$	236

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 7% of the employee’s base pay and also contributes 1% of the employee’s base pay, whether or not the employee contributes to the 401(k) Plan as a profit share.

For the majority of bargaining employees who are subject to the International Brotherhood of Electrical Workers Local 125 agreements the Company adds an additional 1% of the employee’s base salary to their profit share.

For eligible employees who are not covered by PGE’s defined benefit pension plan, the Company matches employee contributions up to 6% of the employee’s base pay, and also contributes up to 7% of the employee’s base pay as a profit share.

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 $42 million in 2025, $37 million in 2024, and $31 million in 2023.

- Definition

The entire disclosure for retirement benefits.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (o)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 60
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480266/715-60-50-3

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480126/715-20-S99-2

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 70
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480794/715-70-50-1

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 17
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480482/715-20-55-17

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(i)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/715/tableOfContent

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 1
-Subparagraph (r)(1)
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 14: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (r)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

+ Details

Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income before income taxes	$ 359	$ 350	$ 273
Federal statutory tax rate	$ 76	$ 74	$ 57
Federal statutory tax rate	21.00%	21.00%	21.00%
State and local taxes, net of federal tax benefit	$ 30	$ 28	$ 25
State and local taxes, net of federal tax benefit	8.40%	8.00%	9.00%
Federal tax credits:
Energy-related tax credits	$ (48)	$ (58)	$ (27)
Energy-related tax credits	(13.30%)	(16.60%)	(10.00%)
Research and development tax credits	$ (1)	$ (2)	$ (2)
Research and development tax credits	(0.30%)	(0.60%)	(0.70%)
Other credits	$ 0	$ 0	$ 0
Other credits	0.00%	0.00%	(0.10%)
Nontaxable or Nondeductible Items:
Executive Compensation	$ 4	$ 4	$ 1
Executive Compensation	1.10%	1.40%	0.50%
Other	$ 0	$ 1	$ 0
Other	0.00%	0.20%	0.00%
Changes in Unrecognized Tax Benefits	$ 0	$ 1	$ 1
Changes in Unrecognized Tax Benefits	0.00%	0.20%	0.30%
Effect of ratemaking on income tax accounting	$ (8)	$ (11)	$ (10)
Effect of ratemaking on income tax accounting	(2.10%)	(2.90%)	(3.60%)
Income tax expense	$ 53	$ 37	$ 45
Effective tax rate	14.80%	10.70%	16.40%

Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation [Line Items]
Asset Retirement Obligation, Revision of Estimate	$ 2	$ 28	$ 9
Asset Retirement Obligation, Accretion Expense	13	12	$ 11
Asset Retirement Obligation, Period Increase (Decrease)	5
Decommissioning Liability, Noncurrent	9
Asset Retirement Obligation, Liabilities Settled	8
Recorded Third-Party Environmental Recoveries, Amount	0	$ 22
Spent Nuclear Fuel Obligation, Noncurrent	2
Utility Plant [Member]
Asset Retirement Obligation [Line Items]
Asset Retirement Obligation, Accretion Expense	$ 3

Employee Benefits - Schedule of Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1	$ 1	$ 1
Interest cost on benefit obligation	2	2	2
Expected return on plan assets	(1)	(1)	(1)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	0
Amortization of net actuarial loss (gain)	0	0	(1)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	0	0	(1)
Net periodic benefit cost	2	2	0
Pension Plans, Defined Benefit [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	10	10	10
Interest cost on benefit obligation	32	33	37
Expected return on plan assets	(36)	(39)	(43)
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)	0	0	1
Amortization of net actuarial loss (gain)	0	0	0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement and Curtailment	4	0	0
Net periodic benefit cost	10	4	3
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0	0
Interest cost on benefit obligation	1	0	1
Expected return on plan assets	0	0	0
Defined Benefit Plan, Amortization of Prior Service Cost (Credit)		0	0
Amortization of net actuarial loss (gain)	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	$ 1	$ 2

Credit Facilities - Schedule of Short-term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Line of Credit Facility [Abstract]
Average daily amount of short-term debt outstanding	$ 21	$ 39	$ 63
Weighted daily average interest rate	4.60%	5.50%	5.50%
Maximum amount outstanding during the year	$ 180	$ 319	$ 225

Equity-Based Plans

12 Months Ended

Dec. 31, 2025

Equity Based Plans [Abstract]

Stock Purchase Plan [Text Block]

NOTE 13: EQUITY-BASED PLANS

At-the-Market Offering Program

In July 2024, PGE entered into an equity distribution agreement under which it could sell up to $400 million of its common stock through at-the-market offering programs. The Company entered into forward sale agreements for 5,756,432 shares and 1,420,049 shares in 2025 and 2024, respectively. In 2024, the Company issued 1,066,549 shares pursuant to the forward sale agreements and received net proceeds of $50 million. During 2025, the Company issued 5,919,618 shares pursuant to the forward sale agreements and received net proceeds of $250 million. The Company could have physically settled the remaining amount by delivering 190,314 shares in exchange for cash of $8 million as of December 31, 2025. Any proceeds from the issuances of common stock will be used for general corporate purposes and investments in renewables and non-emitting dispatchable capacity.

Prior to settlement, the potentially issuable shares pursuant to the agreements will be considered 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 agreements 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 the year ended December 31, 2025, an incremental 5,025 shares were included in the calculation of diluted EPS related to the securities under the agreements. 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 1,125,000 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, 2025, there were 506,969 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, 2025, there were 2,451,588 shares available for future issuance pursuant to the DRIP.

Consolidated Statements of Shareholder's Equity - USD ($) $ in Millions	Total	Common Stock Shares	Common Stock Amount	Accumulated Other Comprehensive Loss	Retained Earnings
Balance, shares at Dec. 31, 2022		89,283,353
Balance at Dec. 31, 2022	$ 2,779		$ 1,249	$ (4)	$ 1,534
Issuances of shares pursuant to equity forward sales agreement, shares		11,615,000
Issuances of shares pursuant to equity forward sales agreement	485		485
Shares issued pursuant to equity-based plans, shares		261,256
Shares issued pursuant to equity-based plans	3		3
Stock-based compensation	13		13	0	0
Dividends declared	(188)		0	0	(188)
Net income	228		0	0	228
Other comprehensive income (loss)	(1)		0	(1)	0
Balance, shares at Dec. 31, 2023		101,159,609
Balance at Dec. 31, 2023	3,319		1,750	(5)	1,574
Issuances of shares pursuant to equity forward sales agreement, shares		7,921,022
Issuances of shares pursuant to equity forward sales agreement	346		346
Shares issued pursuant to equity-based plans, shares		261,620
Shares issued pursuant to equity-based plans	2		2
Stock-based compensation	20		20	0	0
Dividends declared	(207)		0	0	(207)
Net income	313		0	0	313
Other comprehensive income (loss)	1		0	1	0
Balance, shares at Dec. 31, 2024		109,342,251
Balance at Dec. 31, 2024	3,794		2,118	(4)	1,680
Issuances of shares pursuant to equity forward sales agreement, shares		5,919,618
Issuances of shares pursuant to equity forward sales agreement	250		250
Shares issued pursuant to equity-based plans, shares		297,210
Shares issued pursuant to equity-based plans	2		2
Stock-based compensation	12		12	0	0
Dividends declared	(231)		0	0	(231)
Net income	306		0	0	306
Balance, shares at Dec. 31, 2025		115,559,079
Balance at Dec. 31, 2025	$ 4,133		$ 2,382	$ (4)	$ 1,755

Fair Value of FInancial Instruments Schedule of Fair Value (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Cash and Cash Equivalents, Fair Value Disclosure	$ 59	$ 12
Domestic government, Debt securities	25	16
Corporate debt securities held in decommissioning trust assets	10	7
Money market funds	7	7
Debt securities - domestic government	1	2
Electricity	30	19
Natural gas	3	15
Financial Instruments, Owned, at Fair Value	14	11
Assets, Fair Value Disclosure	142	82
Liabilities from price risk management activities: [Abstract]
Electricity	50	56
Natural gas	164	163
Liabilities, Fair Value Disclosure	214	219
Portion at Other than Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	7	4
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	59	12
Domestic government, Debt securities	14	10
Corporate debt securities held in decommissioning trust assets	0	0
Money market funds	0	0
Debt securities - domestic government	1	2
Electricity	0	0
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	74	24
Liabilities from price risk management activities: [Abstract]
Electricity	0	0
Natural gas	0	0
Liabilities, Fair Value Disclosure	0	0
Fair Value, Inputs, Level 1 [Member] \| Portion at Other than Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	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	11	6
Corporate debt securities held in decommissioning trust assets	10	7
Money market funds	0	0
Debt securities - domestic government	0	0
Electricity	29	18
Natural gas	3	15
Financial Instruments, Owned, at Fair Value	53	46
Liabilities from price risk management activities: [Abstract]
Electricity	13	25
Natural gas	160	159
Liabilities, Fair Value Disclosure	173	184
Fair Value, Inputs, Level 2 [Member] \| Portion at Other than Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
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	0
Debt securities - domestic government	0	0
Electricity	1	1
Natural gas	0	0
Financial Instruments, Owned, at Fair Value	1	1
Liabilities from price risk management activities: [Abstract]
Electricity	37	31
Natural gas	4	4
Liabilities, Fair Value Disclosure	41	35
Fair Value, Inputs, Level 3 [Member] \| Portion at Other than Fair Value Measurement
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Money market funds	0	0
Non Qualified Benefit Plans [Member]
Liabilities from price risk management activities: [Abstract]
Insurance contracts, at cash surrender value	$ 35	$ 32

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Net income	$ 306	$ 313	$ 228
Other comprehensive income (loss)- Change in compensation retirement benefits liability and amortization, net of taxes of an immaterial amount in all three years	0	1	(1)
Comprehensive income	$ 306	$ 314	$ 227

- 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

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478671/942-235-S50-1

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-05(b)(2))
-Publisher FASB
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
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-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(i))
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-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(k)(2))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 825
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 28
-Subparagraph (f)
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+ Details

Asset Retirement Obilgations

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

NOTE 8: ASSET RETIREMENT OBLIGATIONS

AROs consist of the following (in millions):


	As of December 31,
	2025		2024
Trojan decommissioning activities	$	208	$	205
Utility plant		75		80
Non-utility property		29		25
Total asset retirement obligations		312		310
Less: current portion *		13		18
Noncurrent asset retirement obligations	$	299	$	292

* 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 2025, the Company recorded an increase in the ARO of $2 million due to an increase in expected annual ISFSI operation costs. The Company also recorded accretion of $9 million and a reduction of $8 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 $10 million in 2025 for costs incurred in 2024 and $22 million in 2024 for costs incurred in 2023 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 2025, utility AROs decreased by $5 million, with the change comprised of accretion of $3 million, and a reduction of $8 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,
	2025			2024			2023
Balance as of beginning of year	$	310		$	286		$	289
Liabilities incurred		—			—			2
Liabilities settled		(13	)		(16	)		(25	)
Accretion expense		13			12			11
Revisions in estimated cash flows		2			28			9
Balance as of end of year	$	312		$	310		$	286

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 NDT 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.

Earnings Per Share Schedule of Earnings per Share, Basic and Diluted (Details) - shares shares in Thousands	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Weighted Average Number of Shares Outstanding, Basic	110,471	103,946	97,760
Weighted Average Number Diluted Shares Outstanding Adjustment	268	213	192
Weighted Average Number of Shares Outstanding, Diluted	110,739	104,159	97,952

Segment Information (Details)	12 Months Ended
Segment Information (Details)	Dec. 31, 2025 Segment
Segment Reporting [Abstract]
Number of operating segments	1
Segment Reporting, CODM, Individual Title and Position or Group Name [Extensible Enumeration]	srt:ChiefExecutiveOfficerMember, srt:PresidentMember
Segment Reporting, CODM, Profit (Loss) Measure, How Used, Description	The Company’s CODM assesses the segment’s performance by using Consolidated Net Income. The CODM uses Consolidated Net Income predominantly as a key input to earnings per share and return on equity, which is an important metric for investors, regulators and is also tied to employee compensation.

Employee Benefits - Schedule of Fair Value, Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Pension Plan [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	$ 492	$ 484	$ 530
Pension Plan [Member] \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	30
Pension Plan [Member] \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	473	440
Pension Plan [Member] \| Private equity funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	1	1
Pension Plan [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	13	13
Pension Plan [Member] \| Fair Value, Inputs, Level 1 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	13	13
Pension Plan [Member] \| Fair Value, Inputs, Level 1 [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	13	13
Pension Plan [Member] \| Other
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	479	471
Pension Plan [Member] \| Other \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	30
Pension Plan [Member] \| Other \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	473	440
Pension Plan [Member] \| Other \| Private equity funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	1	1
Other Postretirement Benefit Plans [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	28	25	$ 23
Other Postretirement Benefit Plans [Member] \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	12	11
Other Postretirement Benefit Plans [Member] \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	4	4
Other Postretirement Benefit Plans [Member] \| Defined Benefit Plan, Equity Securities, US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	2	2
Other Postretirement Benefit Plans [Member] \| Defined Benefit Plan, Equity Securities, Non-US
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	4
Other Postretirement Benefit Plans [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	4
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 1 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	4
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	5	4
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member]
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	7	6
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	2
Other Postretirement Benefit Plans [Member] \| Fair Value, Inputs, Level 2 [Member] \| US Government Agencies Debt Securities
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	5	4
Other Postretirement Benefit Plans [Member] \| Other
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	16	15
Other Postretirement Benefit Plans [Member] \| Other \| Money market funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	12	11
Other Postretirement Benefit Plans [Member] \| Other \| Collective trust funds
Equity securities:
Defined Benefit Plan, Plan Assets, Amount	$ 4	$ 4

Equity-Based Plans (Details) - USD ($)	1 Months Ended	12 Months Ended
Equity-Based Plans (Details) - USD ($)	Jul. 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Net proceeds received		$ 250,000,000	$ 346,000,000	$ 485,000,000
Employee stock purchase plan shares authorized		1,125,000
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		506,969
Dividend Reinvestment and Direct Stock Purchase Plan Shares		2,500,000
Dividend Reinvestment and Direct Stock Purchase Plan, Number of Available Shares		2,451,588
At-the-Market Offering Program [Member]
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
At-the-Market Offering Program, authorized aggregate value	$ 400,000,000
Number of shares issued		5,919,618	1,066,549
Net proceeds received		$ 250,000,000	$ 50,000,000
Number of shares issuable to settled the remaining amount		190,314
Expected proceeds from number of shares issuable to settled the remaining amount		$ 8,000,000
Shares included in the calculation of diluted EPS		5,025
At-the-Market Offering Program [Member] \| Forward Sale Agreements
Share-Based Compensation Arrangement by Share-Based Payment Award [Line Items]
Number of shares issued		5,756,432	1,420,049

Revenue Recognition

12 Months Ended

Dec. 31, 2025

Revenue Recognition [Abstract]

Revenue Recognition

NOTE 3: REVENUE RECOGNITION

Disaggregated Revenue

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


	Year Ended December 31,
	2025		2024			2023
Retail:
Residential	$	1,486	$	1,457		$	1,263
Commercial		969		914			800
Industrial		536		435			349
Direct access customers		41		33			27
Subtotal		3,032		2,839			2,439
Alternative revenue programs, net of amortization		21		(40	)		11
Other accrued revenues, net		17		16			(3	)
Total retail revenues		3,070		2,815			2,447
Wholesale revenues *		418		558			418
Other operating revenues		88		67			58
Total revenues	$	3,576	$	3,440		$	2,923

* Wholesale revenues include $203 million, $273 million, and $185 million related to physical electricity commodity contract derivative settlements for the years ended December 31, 2025, 2024, and 2023, respectively. Price risk management derivative activities are included within Total revenues but do not represent revenues from contracts with customers as defined by GAAP, pursuant to Topic 606. For further information, see Note 6, Risk Management.

Retail Revenues

The Company’s primary revenue source is the sale of electricity to customers at regulated tariff-based prices. Retail customers are classified as residential, commercial, or industrial. Residential customers include single- family housing, multiple family housing (such as apartments, duplexes, and town homes), manufactured homes, and small farms. Residential demand is sensitive to the effects of weather, with demand highest during the winter heating and summer cooling seasons. Commercial customers consist of non-residential customers who accept energy deliveries at voltages equivalent to those delivered to residential customers 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 a less significant 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 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, and secure reasonably priced power for, its retail customers, manage risk, and administer its current long-term wholesale contracts. In addition, the Company performs portfolio management and wholesale market services for third parties in the region and sells environmental credits in the wholesale marketplace. Interconnected transmission systems in the western United States serve utilities with diverse load requirements and allow PGE to purchase and sell electricity within the region depending upon: i) the relative price and availability of power; ii) hydro, solar, and wind conditions; and iii) daily and seasonal retail demand.

PGE’s Wholesale revenues consist primarily of 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.

Arrangements with Multiple Performance Obligations

Certain contracts with customers, primarily wholesale, may include multiple performance obligations. For such arrangements, PGE allocates revenue to each performance obligation based on its relative standalone selling price. The Company generally determines standalone selling prices based on the prices charged to customers.

- 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
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 7
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-7

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 9
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-9

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-10

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 15
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-15

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 6: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 7: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 8: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 12
-Subparagraph (e)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-12

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 606
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 13
-Subparagraph (b)(2)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479806/606-10-50-13

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
-Name Accounting Standards Codification
-Topic 606
-Publisher FASB
-URI https://asc.fasb.org/606/tableOfContent

+ Details

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Statement [Abstract]
Revenues, net	$ 3,555	$ 3,480	$ 2,912
Alternative revenue programs, net of amortization	21	(40)	11
Total Revenues	3,576	3,440	2,923
Operating expenses:
Purchased power and fuel	1,411	1,418	1,190
Generation, transmission and distribution	450	436	374
Administrative and other	392	403	341
Depreciation and amortization	578	496	458
Taxes other than income taxes	190	175	164
Total operating expenses	3,021	2,928	2,527
Income from operations	555	512	396
Interest expense, net	232	211	173
Other income:
Allowance for equity funds used during construction	18	23	19
Miscellaneous income, net	18	26	31
Other income, net	36	49	50
Income before income taxes	359	350	273
Income tax expense	53	37	45
Net income	$ 306	$ 313	$ 228
Weighted-average shares outstanding (in thousands):
Basic	110,471	103,946	97,760
Diluted	110,739	104,159	97,952
Earnings per share:
Basic	$ 2.77	$ 3.02	$ 2.33
Diluted	$ 2.77	$ 3.01	$ 2.33

Fair Value of FInancial Instruments Fair Value Unobservable Input Reconciliation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Net realized and unrealized losses	$ 22	$ 25
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset Transfers Into Level 3	0	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Liability, Transfers Into Level 3	(16)
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3		(36)
Net liabilities from price risk management activities as of end of year	40	34	$ 45
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$ 27	$ 30

- Definition

Line items represent financial concepts included in a table. These concepts are used to disclose reportable information associated with domain members defined in one or many axes to the table.

+ References + Details

Credit Facilities (Tables)

12 Months Ended

Dec. 31, 2025

Line of Credit Facility [Abstract]

Schedule of Short-term Debt

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


	Year Ended December 31,
	2025			2024			2023
Average daily amount of short-term debt outstanding	$	21		$	39		$	63
Weighted daily average interest rate *		4.6	%		5.5	%		5.5	%
Maximum amount outstanding during the year	$	180		$	319		$	225

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

Commitments and Guarantees (Tables)

12 Months Ended

Dec. 31, 2025

Long-term Purchase Commitment [Line Items]

Unrecorded Unconditional Purchase Obligations Disclosure

As of December 31, 2025, PGE’s estimated future minimum payments pursuant to purchase obligations for the following five years and thereafter are as follows (in millions):


	Payments Due
	2026		2027		2028		2029		2030		Thereafter		Total
Capital and other purchase commitments	$	414	$	136	$	24	$	13	$	1	$	40	$	628
Purchased power and fuel:
Electricity purchases		504		400		395		389		324		2,888		4,900
Capacity contracts		218		128		129		130		125		618		1,348
Public utility districts		10		9		7		1		1		13		41
Natural gas		88		74		36		30		30		161		419
Coal and transportation		38		38		38		38		—		—		152
Total	$	1,272	$	785	$	629	$	601	$	481	$	3,720	$	7,488

Schedule of Long-term Contracts for Purchase of Electric Power

PGE has long-term PPAs 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,		PGE’s Average Share as of December 31, 2025					Contract	Total PGE Contract Costs
	2025		Output			Capacity		Expiration	2025		2024		2023
						(in MW)
Priest Rapids and Wanapum	$	1,584		8.6	%		163	2052	$	67	$	75	$	77
Wells		200		3.5	%		25	2028		10		11		11

Commitments and Guarantees (Details) $ in Millions	Jan. 01, 2026 USD ($) MW	Dec. 31, 2025 USD ($)
Unrecorded Unconditional Purchase Obligation [Line Items]
Construction Work In Progress \| $		$ 14
Subsequent Event \| Biglow Optimization
Unrecorded Unconditional Purchase Obligation [Line Items]
Project construction amount \| $	$ 540
Subsequent Event \| Wheatridge Expansion
Unrecorded Unconditional Purchase Obligation [Line Items]
Project construction amount \| $	$ 490
Subsequent Event \| Wheatridge Expansion \| NextEra Energy, Inc.
Unrecorded Unconditional Purchase Obligation [Line Items]
Number of years of PPA agreement	30 years
Solar and Battery Hybrid Projects \| Subsequent Event
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	615
Solar Facility \| Subsequent Event \| Biglow Optimization
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	125
Solar Facility \| Subsequent Event \| Wheatridge Expansion
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	240
Solar Facility \| Subsequent Event \| Wheatridge Expansion \| PGE
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	110
Solar Facility \| Subsequent Event \| Wheatridge Expansion \| NextEra Energy, Inc.
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	130
BESS \| Subsequent Event \| Biglow Optimization
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	125
BESS \| Subsequent Event \| Wheatridge Expansion
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	125
BESS \| Subsequent Event \| Wheatridge Expansion \| PGE
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	65
BESS \| Subsequent Event \| Wheatridge Expansion \| NextEra Energy, Inc.
Unrecorded Unconditional Purchase Obligation [Line Items]
Capacity of projects constructed	60

Risk Management (Details) - USD ($) $ in Millions	12 Months Ended
Risk Management (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Gross amounts included as price risk management liabilities	$ 41	$ 41
Net gain or loss recognized in the statement of income offset by regulatory accounting	24	5	$ (403)
Aggregate fair value of derivative instruments	208
Aggregate fair value in collateral	72
Aggregate fair value in cash	59
Aggregate fair value in letters of credit	13
Collateral aggregate fair value	146
Margin deposit assets	0
Right to reclaim cash collateral	14	16
Cash	21	$ 5
Letters of credit	5
Derivative asset amount offset against collateral	$ 26

Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2025

Fair Value of Financial Instruments [Abstract]

Schedule of Fair Value, Assets and Liabilities Measured on Recurring Basis

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, 2025
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	59	$	—	$	—	$	—	$	59
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		14		11		—		—		25
Corporate credit		—		10		—		—		10
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		1		—		—		—		1
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		7		7
Price risk management activities: (1) (4)
Electricity		—		29		1		—		30
Natural gas		—		3		—		—		3
	$	74	$	53	$	1	$	14	$	142
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	13	$	37	$	—	$	50
Natural gas		—		160		4		—		164
	$	—	$	173	$	41	$	—	$	214

(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 $35 million, which are recorded at cash surrender value.

(4)

For further information regarding price risk management derivatives, see Note 6, Risk Management.


	December 31, 2024
	Level 1		Level 2		Level 3		Other(2)		Total
Assets:
Cash equivalents	$	12	$	—	$	—	$	—	$	12
Nuclear decommissioning trust: (1)
Debt securities:
Domestic government		10		6		—		—		16
Corporate credit		—		7		—		—		7
Money market funds measured at NAV (2)		—		—		—		7		7
Non-qualified benefit plan trust: (3)
Debt securities—domestic government		2		—		—		—		2
Paid Leave Oregon Trust:
Money market funds measured at NAV (2)		—		—		—		4		4
Price risk management activities: (1) (4)
Electricity		—		18		1		—		19
Natural gas		—		15		—		—		15
	$	24	$	46	$	1	$	11	$	82
Liabilities:
Price risk management activities: (1) (4)
Electricity	$	—	$	25	$	31	$	—	$	56
Natural gas		—		159		4		—		163
	$	—	$	184	$	35	$	—	$	219

(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 $32 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, 2025:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		5		5
Collective trust funds		—		—		—		473		473
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	479	$	492
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		5		—		—		—		5
Debt securities—Domestic		—		5		—		—		5
Investments measured at NAV:
Money market funds		—		—		—		12		12
Collective trust funds		—		—		—		4		4
	$	5	$	7	$	—	$	16	$	28
As of December 31, 2024:
Defined Benefit Pension Plan assets:
Equity securities—Domestic	$	13	$	—	$	—	$	—	$	13
Investments measured at NAV:
Money market funds		—		—		—		30		30
Collective trust funds		—		—		—		440		440
Private equity funds		—		—		—		1		1
	$	13	$	—	$	—	$	471	$	484
Other Postretirement Benefit Plans assets:
Equity securities:
Domestic		—		2		—		—		2
International		4		—		—		—		4
Debt securities—Domestic government		—		4		—		—		4
Investments measured at NAV:
Money market funds		—		—		—		11		11
Collective trust funds		—		—		—		4		4
	$	4	$	6	$	—	$	15	$	25

Schedule of Quantitative Information Regarding the Significant Unobservable Inputs Used in Measurement of Level 3 Assets and Liabilities from Price Risk Management Activities

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, 2025:
Electricity physical forwards	$	—	$	37	Discounted cash flow	Electricity forward price (per MWh)	$	22.99	$	94.65	$	59.28
Natural gas financial swaps		—		4	Discounted cash flow	Natural gas forward price (per Dth)		1.67		2.76		2.15
Electricity financial futures		1		—	Discounted cash flow	Electricity forward price (per MWh)		31.00		84.00		52.13
	$	1	$	41

As of December 31, 2024:
Electricity physical forwards	$	—	$	28	Discounted cash flow	Electricity forward price (per MWh)	$	14.00	$	99.68	$	59.43
Natural gas financial swaps		—		4	Discounted cash flow	Natural gas forward price (per Dth)		1.86		6.53		2.68
Electricity financial futures		1		3	Discounted cash flow	Electricity forward price (per MWh)		27.00		110.00		70.55
	$	1	$	35

Schedule of Changes in Fair Value of Net Liabilities from Price Risk Management Activities


	Years Ended December 31,
	2025			2024
Net liabilities from price risk management activities as of beginning of year	$	34		$	45
Net realized and unrealized losses *		22			25
Net transfers from Level 3 to Level 2		(16	)		(36	)
Net liabilities from price risk management activities as of end of year	$	40		$	34
Level 3 net unrealized losses that have been fully offset by the effect of regulatory accounting	$	27		$	30

* Includes $5 million in net realized gains in both 2025 and 2024.

- Definition

Tabular disclosure of the fair value measurement of assets using significant unobservable inputs (Level 3), a reconciliation of the beginning and ending balances, separately presenting changes during the period attributable to the following: (1) total gains or losses for the period (realized and unrealized), segregating those gains or losses included in earnings (or changes in net assets) and gains or losses recognized in other comprehensive income (loss), and a description of where those gains or losses included in earnings (or changes in net assets) are reported in the statement of income (or activities); (2) purchases, sales, issues, and settlements (each type disclosed separately); and (3) transfers in and transfers out of Level 3 (for example, transfers due to changes in the observability of significant inputs), by class of asset.

+ References + Details

Basis of Presentation

12 Months Ended

Dec. 31, 2025

Basis of Presentation [Abstract]

Basis of Presentation

NOTE 1: 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, natural gas, and environmental credits in an effort to meet the needs of, and obtain reasonably-priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. In addition, PGE performs portfolio management and wholesale market sales services for third parties in the region. The Company 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 4,000 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, 2025, PGE served approximately 960,000 retail customers with a service area population of approximately 2 million.

As of December 31, 2025, PGE had 2,877 employees in its workforce, with 666 employees covered under one of two separate agreements with Local Union No. 125 of the International Brotherhood of Electrical Workers. One agreement covers 602 employees and expires February 2028, and the other covers 64 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

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 $19 million and $14 million from Other, net to Contribution to pension and other postretirement plans in the operating activities section of the consolidated statements of cash flows for the years ended December 31, 2024 and 2023, respectively.

Cybersecurity Risk Management, Strategy, and Governance Disclosure	12 Months Ended
	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	ITEM 1C. CYBERSECURITY. PGE considers cybersecurity to be a top enterprise risk in PGE’s enterprise risk management program. The Company manages this risk through established security policies and governance, regular risk assessments, layered technical controls, access management, security awareness training, and resiliency exercises. As a utility with critical infrastructure, both cyber and physical security will continue to be an important consideration for the Company’s future strategy and operations. The Company maintains a cybersecurity program, overseen by a cross-functional executive committee, that uses a risk-based methodology to support the security of its systems. Additional information about cybersecurity risks and the potential impact to the Company can be found in Item 1A.—“Risk Factors.” As of the date of this filing, the Company has not experienced a material cybersecurity incident. Risk Management PGE uses the cybersecurity framework established by the National Institute of Standard and Technology, which provides a comprehensive, risk‑based approach to managing cybersecurity risk across the lifecycle for managing cybersecurity risk. PGE continuously reviews its cybersecurity practices and makes enhancements to address evolving threats, business changes, and regulatory expectations. PGE maintains incident response processes designed to support the timely response, containment, investigation, remediation, and recovery from cybersecurity incidents. These processes are tested through periodic functional and tabletop exercises to enhance preparedness and resiliency. The Company also conducts regular reviews, audits, and independent assessments, including periodic penetration testing, to evaluate the effectiveness of its cybersecurity controls and to support continuous improvement. PGE manages third‑party cybersecurity risk through due diligence prior to onboarding, ongoing risk monitoring, and periodic reassessment based on the criticality of the vendor relationship. Vendors that do not meet the Company’s security requirements may be subject to additional review or may not be engaged. Governance Cybersecurity governance is supported by multiple layers of management oversight and assurance. An enterprise-wide management group operates to evaluate the cybersecurity program’s effectiveness. The Company has an employee who functions as a Chief Security Officer, whose responsibilities include cybersecurity and who has a reporting relationship to senior management. This employee has had a twenty-five year career with the Federal Bureau of Investigation (FBI) prior to joining the Company. She served as the Confidential Advisor to the Director of the FBI, providing strategic advice across all threats allowing her to develop unique and key insights into the global cyber threat landscape, FBI cyber strategy, and cyber operations. Prior to joining the Company, she served as the Special Agent in Charge of the FBI Jacksonville Division where she led all FBI cyber investigations and operations for nation state and criminal actors. PGE has a management-level committee, the Integrated Security Executive Committee (ISEC), which focuses specifically on cybersecurity and security-related risks. The ISEC meets quarterly and reviews risks, processes, and strategies related to cybersecurity. Members of the ISEC include; the Chief Information Officer; the Chief Financial Officer; the Vice President, Utility Operations; the Senior Vice President, Advanced Energy Delivery; the Vice President, People and Culture and Chief Human Resources Officer; the Chief Executive Officer; the Chief Legal and Compliance Officer; and other executives as needed. In addition, as a top enterprise risk, cybersecurity is also reviewed by the Company’s management-level Executive Risk Committee on an annual basis, or more frequently if circumstances warrant. This broader review allows the cybersecurity risk and mitigations to be aligned with other enterprise risks, including identifying areas of overlap. Members of the Executive Risk Committee include: the Chief Executive Officer; the Chief Legal and Compliance Officer; the Chief Financial Officer; the Chief Operating Officer; the Chief Information Officer; the Vice President, Chief Commercial and Customer Officer; the Senior Vice President of Strategy and Advanced Energy Delivery; the Vice President of Power Markets and Grid Operations; and the Senior Director, Treasurer. The Audit and Risk Committee of the Board of Directors has oversight of cybersecurity risk and receives briefings on a quarterly basis. The briefings are provided either by the cybersecurity team, together with a senior member of management, or are presented as part of the Audit and Risk Committee’s regular review of top enterprise risks, in which cybersecurity risk is reviewed annually or more frequently if circumstances warrant. The Audit and Risk Committee briefs the full Board of Directors at each meeting. In addition, the full Board of Directors has participated in cybersecurity exercises. The Audit and Risk Committee is also provided with information about external assessment results and action plans. There is a process in place to notify the Audit and Risk Committee promptly in the event of a material cybersecurity incident. Training and Awareness All employees are required to complete annual physical security and cybersecurity awareness training. The Company conducts ongoing security awareness activities, including cybersecurity training, monthly and targeted phishing campaigns, to reinforce employee vigilance and promote secure behavior. Results from these activities are used to inform continuous improvement efforts. PGE engages with third parties to monitor the PGE external attack surface and conducts ongoing penetration testing. These assessments support a continuous improvement. As a NERC registered entity, PGE is audited by WECC. The FERC will conduct an audit of cybersecurity controls at PGE hydro facilities in 2026.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	All employees are required to complete annual physical security and cybersecurity awareness training. The Company conducts ongoing security awareness activities, including cybersecurity training, monthly and targeted phishing campaigns, to reinforce employee vigilance and promote secure behavior. Results from these activities are used to inform continuous improvement efforts. PGE engages with third parties to monitor the PGE external attack surface and conducts ongoing penetration testing. These assessments support a continuous improvement. As a NERC registered entity, PGE is audited by WECC. The FERC will conduct an audit of cybersecurity controls at PGE hydro facilities in 2026.
Cybersecurity Risk Management Third Party Engaged [Flag]	true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag]	true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag]	false
Cybersecurity Risk Board of Directors Oversight [Text Block]	The Audit and Risk Committee of the Board of Directors has oversight of cybersecurity risk and receives briefings on a quarterly basis. The briefings are provided either by the cybersecurity team, together with a senior member of management, or are presented as part of the Audit and Risk Committee’s regular review of top enterprise risks, in which cybersecurity risk is reviewed annually or more frequently if circumstances warrant. The Audit and Risk Committee briefs the full Board of Directors at each meeting. In addition, the full Board of Directors has participated in cybersecurity exercises. The Audit and Risk Committee is also provided with information about external assessment results and action plans. There is a process in place to notify the Audit and Risk Committee promptly in the event of a material cybersecurity incident.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	The Audit and Risk Committee of the Board of Directors has oversight of cybersecurity risk
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Audit and Risk Committee of the Board of Directors has oversight of cybersecurity risk and receives briefings on a quarterly basis. The briefings are provided either by the cybersecurity team, together with a senior member of management, or are presented as part of the Audit and Risk Committee’s regular review of top enterprise risks, in which cybersecurity risk is reviewed annually or more frequently if circumstances warrant. The Audit and Risk Committee briefs the full Board of Directors at each meeting. In addition, the full Board of Directors has participated in cybersecurity exercises. The Audit and Risk Committee is also provided with information about external assessment results and action plans. There is a process in place to notify the Audit and Risk Committee promptly in the event of a material cybersecurity incident.
Cybersecurity Risk Role of Management [Text Block]	reviews risks, processes, and strategies related to cybersecurity
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Members of the ISEC include; the Chief Information Officer; the Chief Financial Officer; the Vice President, Utility Operations; the Senior Vice President, Advanced Energy Delivery; the Vice President, People and Culture and Chief Human Resources Officer; the Chief Executive Officer; the Chief Legal and Compliance Officer; and other executives as needed.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	This employee has had a twenty-five year career with the Federal Bureau of Investigation (FBI) prior to joining the Company. She served as the Confidential Advisor to the Director of the FBI, providing strategic advice across all threats allowing her to develop unique and key insights into the global cyber threat landscape, FBI cyber strategy, and cyber operations. Prior to joining the Company, she served as the Special Agent in Charge of the FBI Jacksonville Division where she led all FBI cyber investigations and operations for nation state and criminal actors.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	on a quarterly basis. The briefings are provided either by the cybersecurity team, together with a senior member of management, or are presented as part of the Audit and Risk Committee’s regular review of top enterprise risks, in which cybersecurity risk is reviewed annually or more frequently if circumstances warrant. The Audit and Risk Committee briefs the full Board of Directors at each meeting. In addition, the full Board of Directors has participated in cybersecurity exercises. The Audit and Risk Committee is also provided with information about external assessment results and action plans. There is a process in place to notify the Audit and Risk Committee promptly in the event of a material cybersecurity incident.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Risk Management - Schedule of Future Year Net Unrealized Losses related to PGE's Derivative Activities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Commodity contracts:
2026	$ 127
2027	22
2028	7
2029	5
2030	3
Thereafter	17
Total	181
Electricity [Member]
Commodity contracts:
2026	(9)
2027	2
2028	4
2029	3
2030	3
Thereafter	17
Total	20
Natural Gas [Member]
Commodity contracts:
2026	136
2027	20
2028	3
2029	2
2030	0
Thereafter	0
Total	$ 161

Long-term Debt and Other Financing Arrangements

12 Months Ended

Dec. 31, 2025

Long-term Debt Disclosure [Abstract]

Long-term Debt and Other Financing Arrangements

NOTE 10: LONG-TERM DEBT AND OTHER FINANCING ARRANGEMENTS

Long-term debt

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


	As of December 31,
	2025			2024
First Mortgage Bonds, rates range from 1.82% to 6.88%, with a weighted average rate of 4.60% in 2025 and 4.52% in 2024, due at various dates through 2059.	$	4,560		$	4,250
Unsecured term bank loan		—			170
Pollution Control Revenue Bonds, rates at 2.13% and 2.38%, due 2033		119			119
Total long-term debt		4,679			4,539
Less: Unamortized debt expense		(17	)		(15	)
Less: Current portion of long-term debt		—			(170	)
Long-term debt, net of current portion	$	4,662		$	4,354

First Mortgage Bonds—On March 25, 2025, PGE entered into a Bond Purchase Agreement related to the sale of $310 million in FMBs. The Bonds were issued and funded in full on March 25, 2025 and consist of:

•

a series, due in 2035, in the amount of $60 million that will bear interest from its issuance date at an annual rate of 5.36%;

•

a series, due in 2045, in the amount of $50 million that will bear interest from its issuance date at an annual rate of 5.72%; and

•

a series, due in 2055, in the amount of $200 million that will bear interest from its issuance date at an annual rate of 5.84%.

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 November 14, 2024, PGE obtained a 366-day term loan from lenders in the aggregate principal of $300 million under a 366-Day Bridge Credit Agreement. Pursuant to the Agreement, on November 14, 2024, PGE drew a loan from the lenders in the aggregate principal of $220 million. The term loan bore 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 80.0 basis points. The interest rate was subject to adjustment pursuant to the terms of the loan. On December 31, 2024, PGE repaid $50 million of the term loan. On March 31, 2025, the Company repaid another $102 million, and on October 27, 2025 repaid the remaining balance of $68 million, repaying the loan in full.

Pollution Control Revenue Bonds—In March 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 that bear an interest rate of 2.125%, and $21 million aggregate principal 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, 2025, the future minimum principal payments on long-term debt are as follows (in millions):


Years ending December 31:
2026	$	—
2027		160
2028		100
2029		200
2030		325
Thereafter		3,894
	$	4,679

Pelton/Round Butte financing arrangement

Under terms of an 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 which was exercised in 2022. 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 in 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 records the tangible utility asset within Electric utility plant, net on the consolidated balance sheets as if it were the legal owner and recognizes depreciation expense over the estimated useful life. The monthly PPA payments are split between interest expense and a reduction of the principal portion of the financing obligation, which is included in Other noncurrent liabilities. 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.

As of December 31, 2025, the future minimum payments on the financing arrangement are as follows (in millions):


Years ending December 31:
2026	$	5
2027		5
2028		5
2029		5
2030		5
Thereafter		55
Total Payments		80
Less: Imputed Interest		(49	)
Present value of minimum payments	$	31

Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2025

Revenue Recognition [Abstract]

Disaggregation of Revenue

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


	Year Ended December 31,
	2025		2024			2023
Retail:
Residential	$	1,486	$	1,457		$	1,263
Commercial		969		914			800
Industrial		536		435			349
Direct access customers		41		33			27
Subtotal		3,032		2,839			2,439
Alternative revenue programs, net of amortization		21		(40	)		11
Other accrued revenues, net		17		16			(3	)
Total retail revenues		3,070		2,815			2,447
Wholesale revenues *		418		558			418
Other operating revenues		88		67			58
Total revenues	$	3,576	$	3,440		$	2,923

Risk Management (Tables)

12 Months Ended

Dec. 31, 2025

Price Risk Management [Abstract]

Schedule of PGE's Assets and Liabilities from Price Risk Management Activities

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


	As of December 31,
	2025		2024
Current assets:
Commodity contracts:
Electricity	$	29	$	18
Natural gas		3		14
Total current derivative assets(1)		32		32
Noncurrent assets:
Commodity contracts:
Electricity		1		1
Natural gas		—		1
Total noncurrent derivative assets(1)		1		2
Total derivative assets(2)	$	33	$	34
Current liabilities:
Commodity contracts:
Electricity	$	19	$	32
Natural gas		139		115
Total current derivative liabilities		158		147
Noncurrent liabilities:
Commodity contracts:
Electricity		31		24
Natural gas		25		48
Total noncurrent derivative liabilities		56		72
Total derivative liabilities(2)	$	214	$	219

(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, 2025 and 2024, no commodity derivative assets or liabilities were designated as hedging instruments.

Schedule of PGE's Net Volumes related to Assets and Liabilities from Price Risk Management Activities


	As of December 31,
	2025			2024
Commodity contracts:
Electricity		1	MWh		2	MWh
Natural gas		224	Dth		199	Dth
Foreign currency contracts	$	9	Canadian	$	34	Canadian

Schedule of Net Realized and Unrealized Losses (Gains) on Derivative Transactions Not Designated as Hedging Instruments


	Years Ended December 31,
	2025			2024			2023
Commodity contracts:
Electricity	$	(26	)	$	(17	)	$	(130	)
Natural Gas		206			30			357
Foreign currency contracts		(1	)		(1	)		(1	)

Schedule of Future Year Net Unrealized Losses related to PGE's Derivative Activities


	2026			2027		2028		2029		2030		Thereafter		Total
Commodity contracts:
Electricity	$	(9	)	$	2	$	4	$	3	$	3	$	17	$	20
Natural gas		136			20		3		2		—		—		161
Net unrealized loss	$	127		$	22	$	7	$	5	$	3	$	17	$	181

Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Oct. 27, 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Net realized gains	$ 5	$ 5
Long-term Debt, Fair Value	4,311	3,963
Long-term Debt	4,679	4,539	$ 68
Unamortized Debt Issuance Expense	17	15
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	$ 4,662	$ 4,524

- Definition

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

+ References

+ Details

- Definition

The fair value amount of long-term debt whether such amount is presented as a separate caption or as a parenthetical disclosure. Additionally, this element may be used in connection with the fair value disclosures required in the footnote disclosures to the financial statements. The element may be used in both the balance sheet and disclosure in the same submission.

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-Name Accounting Standards Codification
-Section 50
-Paragraph 2
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-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

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+ Details

Employee Benefits - Summary of Assumptions (Details)	12 Months Ended
Employee Benefits - Summary of Assumptions (Details)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.03%	4.02%	4.06%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	4.78%	4.73%
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.56%	5.70%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	4.14%	4.08%	4.19%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.70%	5.13%
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	6.88%	6.88%
Non Qualified Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.56%	5.70%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Rate of Compensation Increase	3.96%	3.98%	4.01%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.70%	5.13%
Maximum [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	6.11%	6.11%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	6.11%	5.57%
Minimum [Member] \| Other Postretirement Benefit Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.29%	5.59%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.59%	5.18%

Consolidated Statements of Shareholder's Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Common Stock, Dividends, Per Share, Declared	$ 2.075	$ 1.975	$ 1.8775

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Deferred income tax assets:
Employee benefits	$ 79	$ 89
Regulatory liabilities	21	28
Tax credits, net of transfer discount	61	69
Deferred investment tax credits	73	14
Price risk management	50	51
Total deferred income tax assets	284	251
Deferred income tax liabilities:
Depreciation and amortization	711	633
Regulatory assets	156	169
Other	18	13
Total deferred income tax liabilities	885	815
Deferred income tax liability, net	$ 601	$ 564

Segment Reporting

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Segment Information

NOTE 20: SEGMENT INFORMATION

PGE is a vertically-integrated electric utility engaged in the generation, transmission, distribution, and retail sale of electricity. The Company participates in wholesale markets by purchasing and selling electricity and natural gas in an effort to meet the needs of, and obtain reasonably-priced power for its retail customers, manage risk, and administer its long-term wholesale contracts. The Company generates revenues and cash flows primarily from the sale and distribution of electricity to retail customers in its service territory in the State of Oregon.

The Company has identified one operating and reportable segment and defines its segment on the basis of the way in which internally reported financial information is regularly reviewed by the chief operating decision maker (CODM) to analyze financial performance, make decisions, and allocate resources. The Company’s CODM is the President and Chief Executive Officer.

The Company’s CODM assesses the segment’s performance by using Consolidated Net Income. The CODM uses Consolidated Net Income predominantly as a key input to earnings per share and return on equity, which is an important metric for investors, regulators and is also tied to employee compensation.


	Years Ended December 31,
	2025		2024		2023
Total revenues	$	3,576	$	3,440	$	2,923
Operating expenses:
Purchased power and fuel		1,411		1,418		1,190
Operating and maintenance expense:
Generation, transmission and distribution		450		436		374
Administrative and other		392		403		341
Total operating and maintenance expense		842		839		715
Depreciation and amortization		578		496		458
Taxes other than income taxes		190		175		164
Total operating expenses		3,021		2,928		2,527
Income from operations		555		512		396
Interest expense, net:
Interest expense		243		226		186
Allowance for borrowed funds used during construction		11		15		13
Total interest expense, net		232		211		173
Other income, net:		36		49		50
Income before income taxes		359		350		273
Income tax expense		53		37		45
Consolidated Net income	$	306	$	313	$	228

Certain additional financial information relating to the Company’s single business segment was as follows (dollars in millions):


	Years Ended December 31,
	2025			2024			2023
Total assets	$	13,230		$	12,544		$	11,208
Capital expenditures		(1,189	)		(1,268	)		(1,358	)
Equity method investments		19			13			9

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

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Reference 18: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
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-Section 50
-Paragraph 22
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482810/280-10-50-22

Reference 19: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 34
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Reference 20: http://www.xbrl.org/2003/role/disclosureRef
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Reference 21: http://www.xbrl.org/2003/role/disclosureRef
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Reference 22: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
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-Paragraph 40
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Reference 23: http://www.xbrl.org/2003/role/disclosureRef
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Reference 24: http://www.xbrl.org/2003/role/disclosureRef
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Reference 25: http://www.xbrl.org/2003/role/disclosureRef
-Topic 280
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-Name Accounting Standards Codification
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-Publisher FASB
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+ Details

Leases - Supplemental Information (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 303	$ 312
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Operating Lease, Liability, Current	$ 26	$ 26
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Current	Other Liabilities, Current
Operating Lease, Liability, Noncurrent	$ 277	$ 286
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Operating Leases, Total	$ 303	$ 312
Finance Lease, Right-of-Use Asset	$ 262	$ 276
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Public Utilities, Property, Plant and Equipment, Net	Public Utilities, Property, Plant and Equipment, Net
Finance Lease, Liability, Current	$ 27	$ 27
Finance Lease, Liability, Noncurrent	263	276
Finance Lease, Total	$ 290	$ 303

Summary of Significant Accounting Policies Estimated Average Service Lives (Details)	12 Months Ended
	Dec. 31, 2025
Generation, excluding thermal:
Transmission	58 years
Distribution	50 years
General	17 years
Public Utilities, Property, Plant and Equipment, Other Property Plant and Equipment, Useful Life	16 years

Income Taxes - Schedule of Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Paid, by Individual Jurisdiction [Line Items]
Federal income taxes paid	$ 4	$ 4	$ 10
Tax credit sales	(179)	(112)	(24)
OREGON
State and local
Cash paid (received) for income taxes, State and local	12	17	21
Federal [Member]
Income Tax Paid, by Individual Jurisdiction [Line Items]
Tax credit sales	(179)	(112)	(23)
Other[Member]
State and local
Cash paid (received) for income taxes, State and local	$ 1	$ 1	$ 4

Jointly-owned Plant (Tables)

12 Months Ended

Dec. 31, 2025

Jointly-owned Plant [Abstract]

Schedule of Jointly Owned Utility Plants

As of December 31, 2025, 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 - Generation		20	%	1986	$	512	$	501	$	3
Colstrip-Transmission	Various (2)			1986		74		45		1
Pelton/Round Butte		50.01	%	1958 / 1964		242		81		10
Total					$	828	$	627	$	14

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

Credit Facilities

12 Months Ended

Dec. 31, 2025

Line of Credit Facility [Abstract]

Credit Facilities

NOTE 9: CREDIT FACILITIES

On September 10, 2025, PGE entered into an amendment of its existing revolving credit facility that extended the scheduled expiration into September 2030. As of December 31, 2025, PGE had a $750 million revolving credit facility that provides the Company the ability to expand to $850 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, 2025, PGE was in compliance with this covenant with a 53.0% debt to total capital ratio.

The Company has a commercial paper program under which it may issue commercial paper for terms of up to 270 days. 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, 2025, PGE had no commercial paper outstanding.

Under the revolving credit facility, as of December 31, 2025, PGE had no borrowings outstanding and there were no letters of credit issued. As a result, the aggregate unused available credit capacity under the revolving credit facility was $750 million.

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 four letter of credit facilities that provide a total capacity of $320 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 $192 million of letters of credit were outstanding as of December 31, 2025. 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, 2028.

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


	Year Ended December 31,
	2025			2024			2023
Average daily amount of short-term debt outstanding	$	21		$	39		$	63
Weighted daily average interest rate *		4.6	%		5.5	%		5.5	%
Maximum amount outstanding during the year	$	180		$	319		$	225

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

Leases (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Lease, Cost

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


	2025		2024
Operating lease cost	$	26	$	2
Finance lease cost:
Amortization of right-of-use assets	$	14	$	14
Interest on lease liabilities		14		14
Total finance lease cost	$	28	$	28

Variable lease cost	$	22	$	28

Lessee, Operating Leases

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


		As of December 31,
	Balance Sheet Classification	2025		2024
Operating Leases:
Operating lease right-of-use assets	Other noncurrent assets	$	303	$	312

Current liabilities	Accrued expenses and other current liabilities	$	26	$	26
Noncurrent liabilities	Other noncurrent liabilities		277		286
Total operating lease liabilities *		$	303	$	312
Finance Leases:
Finance lease right-of-use assets	Electric utility plant, net	$	262	$	276

Current liabilities	Current portion of finance lease obligations	$	27	$	27
Noncurrent liabilities	Finance lease obligations, net of current portion		263		276
Total finance lease liabilities *		$	290	$	303

Schedule of Lease Term and Discount Rates

Lease term and discount rates were as follows:


	December 31, 2025			December 31, 2024
Weighted Average Remaining Lease Term (in years)
Operating leases		21			22
Finance leases		19			20
Weighted Average Discount Rate
Operating leases		5.8	%		5.8	%
Finance leases		4.8	%		4.8	%

Schedule of Future Minimum Lease Payments for Capital Leases

As of December 31, 2025, maturities of lease liabilities were as follows (in millions):


	Operating Leases						Finance Leases
	PPA*			Other			PPA*			Other
2026	$	25		$	1		$	27		$	—
2027		25			1			27			—
2028		25			1			26			—
2029		25			1			26			—
2030		25			1			26			—
Thereafter		349			39			304			—
Total lease payments		474			44			436			—
Less imputed interest		(187	)		(28	)		(146	)		—
Total	$	287		$	16		$	290		$	—

* These agreements include hydro and natural gas generation PPAs, gas storage, and battery storage contracts, all of which are included within the Company’s AUT and PCAM regulatory mechanisms.

Schedule of Supplemental Cash Flow Information

Supplemental cash flow information related to cash paid for income taxes consists of the following (in millions):


	Years Ended December 31,
	2025			2024			2023
Cash paid (received) for income taxes, net:
Federal
Federal income taxes paid	$	4		$	4		$	10
Tax credit sales		(179	)		(112	)		(23	)
State and local
Oregon		12			17			21
Other		1			1			4

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


	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used in operating leases	$	26	$	3	$	4
Operating cash flows used in finance leases		14		14		15
Financing cash flows used in finance leases		14		6		6
Right-of-use assets obtained in leasing arrangements:
Operating leases	$	—	$	295	$	—

Asset Retirement Obligations (Policies)

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

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

Summary of Significant Accounting Policies (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	$ 1,564	$ 1,493
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	468
Other Investments	$ 59	$ 12
Document Period End Date	Dec. 31, 2025
Letters of credit outstanding, amount	$ 192
Public Utilities, Allowance for Funds Used During Construction, Rate	6.70%	6.70%	6.50%
Public Utilities, Allowance for Funds Used During Construction, Capitalized Interest	$ 11	$ 15	$ 13
Public Utilities, Allowance for Funds Used During Construction, Capitalized Cost of Equity	$ 18	$ 23	$ 19
Depreciation expense rate	3.60%	3.50%	3.40%
Amortization of Intangible Assets	$ 76	$ 72	$ 61
Public Utilities, Approved Return on Equity, Percentage	9.34%	9.50%
Regulatory Assets	$ 787	$ 837
Finite-Lived Intangible Assets, Accumulated Amortization	622	611
Future Amortization Expense, Year One	79
Future Amortization Expense, Year Two	73
Future Amortization Expense, Year Three	49
Future Amortization Expense, Year Four	29
Future Amortization Expense, Year Five	17
Power Cost Deadband - Lower Threshold	15
Power Cost Deadband - Upper Threshold	30
Quantifying Misstatement in Current Year Financial Statements, Amount	6,189	5,714
Accumulated depreciation and amortization	5,419	5,085
Deferred Purchased Power Costs	6	78
Excise Taxes Collected	70	63	56
Letters Of Credit Outstanding Amount For Price Risk Management	$ 123	18
Weighted average life of realted properties	16 years
Margin deposits	$ 116	125
Equity method investments	19	13	$ 9
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	161	161
Asset Retirement Obligation Costs [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	6	7
Deferred Income Tax Charge [Member]
Property, Plant and Equipment [Line Items]
Regulatory Liabilities	228	$ 179
Remaining Amounts of Regulatory Assets for which No Return on Investment During Recovery Period is Provided	$ 0

Balance Sheet Components - Schedule of Public Utility Property, Plant, and Equipment (Parenthetical) (Details) - USD ($) $ in Millions	Jul. 02, 2025	Dec. 31, 2025	Jan. 01, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Generation		$ 5,649		$ 5,510
Transmission		1,626		1,420
Distribution		6,189		5,714
General		931		1,025
Energy storage		$ 613		$ 222
Reclassification
Property, Plant and Equipment [Line Items]
Generation			$ 22
Transmission			21
Distribution			87
General			(132)
Energy storage			$ 2
Reclassifications from distribution to transmission	$ 84

Fair Value of Financial Instruments (Policies)

12 Months Ended

Dec. 31, 2025

Fair Value of Financial Instruments [Abstract]

Fair Value of Financial Instruments, Policy [Policy Text Block]

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.

Fair Value Transfer, Policy

Income Taxes - Schedule of Components of Income Tax Expense (Benefit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Current:
Federal	$ 3	$ 2	$ 11
State and local	13	12	26
Current Income Tax Expense (Benefit)	16	14	37
Deferred:
Federal	19	(2)	4
State and local	26	25	4
Deferred income tax expense	45	23	8
Investment Tax Credits	(8)	0	0
Income tax expense	$ 53	$ 37	$ 45

Fair Value of FInancial Instruments Fair Value Options Quantitative Disclosure (Details) $ in Millions	Dec. 31, 2025 USD ($) MWh dth	Dec. 31, 2024 USD ($) Decatherm MWh
Minimum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase, price per unit \| MWh	22.99	14
Natural gas financial swaps, price per unit	1.67	1.86
Electricity financial futures, price per unit \| MWh	31	27
Maximum [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase, price per unit \| MWh	94.65	99.68
Natural gas financial swaps, price per unit	2.76	6.53
Electricity financial futures, price per unit \| MWh	84	110
Weighted Average [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase, price per unit \| MWh	59.28	59.43
Natural gas financial swaps, price per unit	2.15	2.68
Electricity financial futures, price per unit \| MWh	52.13	70.55
Assets [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	$ 0	$ 0
Natural gas financial swaps	0	0
Fnancial swaps - electricity	1	1
Total commodity contracts	1	1
Liabilities [Member]
Fair Value, Option, Quantitative Disclosures [Line Items]
Electricity physical forward purchase	37	28
Natural gas financial swaps	4	4
Fnancial swaps - electricity	0	3
Total commodity contracts	$ 41	$ 35

Risk Management - Schedule of Net Realized and Unrealized Losses (Gains) on Derivative Transactions Not Designated as Hedging Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Commodity contracts: [Abstract]
Electricity	$ (26)	$ (17)	$ (130)
Natural Gas	206	30	357
Realized And Unrealized Losses Net Commodity Contracts, Foreign Currency	$ (1)	$ (1)	$ (1)

Commitments and Guarantees Unrecorded Unconditional Purchase Obligations (Details) $ in Millions	Dec. 31, 2025 USD ($)
Capital Addition Purchase Commitments [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	$ 628
Unrecorded Unconditional Purchase Obligation, Due within One Year	414
Unrecorded Unconditional Purchase Obligation, Due within Two Years	136
Unrecorded Unconditional Purchase Obligation, Due within Three Years	24
Unrecorded Unconditional Purchase Obligation, Due within Four Years	13
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	40
Electricity Purchases [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	4,900
Unrecorded Unconditional Purchase Obligation, Due within One Year	504
Unrecorded Unconditional Purchase Obligation, Due within Two Years	400
Unrecorded Unconditional Purchase Obligation, Due within Three Years	395
Unrecorded Unconditional Purchase Obligation, Due within Four Years	389
Unrecorded Unconditional Purchase Obligation, Due within Five Years	324
Unrecorded Unconditional Purchase Obligation, Due after Five Years	2,888
Electric Transmission [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	1,348
Unrecorded Unconditional Purchase Obligation, Due within One Year	218
Unrecorded Unconditional Purchase Obligation, Due within Two Years	128
Unrecorded Unconditional Purchase Obligation, Due within Three Years	129
Unrecorded Unconditional Purchase Obligation, Due within Four Years	130
Unrecorded Unconditional Purchase Obligation, Due within Five Years	125
Unrecorded Unconditional Purchase Obligation, Due after Five Years	618
Public Utility Districts [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	41
Unrecorded Unconditional Purchase Obligation, Due within One Year	10
Unrecorded Unconditional Purchase Obligation, Due within Two Years	9
Unrecorded Unconditional Purchase Obligation, Due within Three Years	7
Unrecorded Unconditional Purchase Obligation, Due within Four Years	1
Unrecorded Unconditional Purchase Obligation, Due within Five Years	1
Unrecorded Unconditional Purchase Obligation, Due after Five Years	13
Natural gas [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	419
Unrecorded Unconditional Purchase Obligation, Due within One Year	88
Unrecorded Unconditional Purchase Obligation, Due within Two Years	74
Unrecorded Unconditional Purchase Obligation, Due within Three Years	36
Unrecorded Unconditional Purchase Obligation, Due within Four Years	30
Unrecorded Unconditional Purchase Obligation, Due within Five Years	30
Unrecorded Unconditional Purchase Obligation, Due after Five Years	161
Coal and transportationSupply Agreements [Member]
Unrecorded Unconditional Purchase Obligation [Line Items]
Unrecorded Unconditional Purchase Obligation	152
Unrecorded Unconditional Purchase Obligation, Due within One Year	38
Unrecorded Unconditional Purchase Obligation, Due within Two Years	38
Unrecorded Unconditional Purchase Obligation, Due within Three Years	38
Unrecorded Unconditional Purchase Obligation, Due within Four Years	38
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	7,488
Unrecorded Unconditional Purchase Obligation, Due within One Year	1,272
Unrecorded Unconditional Purchase Obligation, Due within Two Years	785
Unrecorded Unconditional Purchase Obligation, Due within Three Years	629
Unrecorded Unconditional Purchase Obligation, Due within Four Years	601
Unrecorded Unconditional Purchase Obligation, Due within Five Years	481
Unrecorded Unconditional Purchase Obligation, Due after Five Years	$ 3,720

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

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


	Years Ended December 31,
	2025			2024			2023
Current:
Federal	$	3		$	2		$	11
State and local		13			12			26
		16			14			37
Deferred:
Federal		19			(2	)		4
State and local		26			25			4
		45			23			8
Investment Tax Credits		(8	)		—			—
Income tax expense	$	53		$	37		$	45

Schedule of Effective Income Tax Rate Reconciliation

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,
	2025					2024					2023
Income before income taxes	$	359				$	350				$	273

Federal statutory tax rate		76		21.0	%		74		21.0	%		57		21.0	%
State and local taxes, net of federal tax benefit (1)		30		8.4			28		8.0			25		9.0
Federal tax credits (2):
Energy-related tax credits		(48	)	(13.3	)		(58	)	(16.6	)		(27	)	(10.0	)
Research and development tax credits		(1	)	(0.3	)		(2	)	(0.6	)		(2	)	(0.7	)
Other credits		—		—			—		—			—		(0.1	)
Nontaxable or Nondeductible Items:
Executive Compensation (3)		4		1.1			4		1.4			1		0.5
Other		—		—			1		0.2			—		—
Changes in Unrecognized Tax Benefits		—		—			1		0.2			1		0.3
Effect of ratemaking on income tax accounting (4)		(8	)	(2.1	)		(11	)	(2.9	)		(10	)	(3.6	)
Effective tax rate	$	53		14.8	%	$	37		10.7	%	$	45		16.4	%

(1)

State taxes in Oregon make up the majority (greater than 50 percent) of the tax effect in this category.

(2)

deferrals. The tax credit deferrals are established to provide the benefit back to customers over a period agreed upon with the OPUC.

(3)

Under IRC Section 162(m), the tax deduction for compensation paid to certain executive officers is limited to $1 million per year.

(4)

Schedule of Deferred Tax Assets and Liabilities

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


	As of December 31,
	2025		2024
Deferred income tax assets:
Employee benefits	$	79	$	89
Regulatory liabilities		21		28
Tax credits, net of transfer discount		61		69
Deferred investment tax credits		73		14
Price risk management		50		51
Total deferred income tax assets		284		251
Deferred income tax liabilities:
Depreciation and amortization		711		633
Regulatory assets		156		169
Other		18		13
Total deferred income tax liabilities		885		815
Deferred income tax liability, net	$	601	$	564

Schedule of Supplemental Cash Flow Information

Supplemental cash flow information related to cash paid for income taxes consists of the following (in millions):


	Years Ended December 31,
	2025			2024			2023
Cash paid (received) for income taxes, net:
Federal
Federal income taxes paid	$	4		$	4		$	10
Tax credit sales		(179	)		(112	)		(23	)
State and local
Oregon		12			17			21
Other		1			1			4

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


	2025		2024		2023
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows used in operating leases	$	26	$	3	$	4
Operating cash flows used in finance leases		14		14		15
Financing cash flows used in finance leases		14		6		6
Right-of-use assets obtained in leasing arrangements:
Operating leases	$	—	$	295	$	—

Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2025

Summary of Significant Accounting Policies [Abstract]

Cash Equivalents

Accounts Receivable

Price Risk Management

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 inthe 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

Depreciation and Amortization


Transmission			58
Distribution			50
Energy Storage			16
General			17

Marketable Securities

Nuclear decommissioning trust

Non-qualified benefit plan trust

Other Investments

investments were immaterial. PGE’s share of earnings or losses are recorded as Miscellaneous income, net within Other income, net on the Company’s consolidated statements of income.

Regulatory Accounting - Regulatory Assets and Liabilities

Regulatory Accounting

Regulatory Assets and Liabilities

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

Regulatory Accounting - Power Cost Adjustment Mechanism

Power Cost Adjustment Mechanism

For additional information concerning PCAM, see Note 7, Regulatory Assets and Liabilities.

Asset Retirement Obligations

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

Contingencies

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.

Accumulated Other Comprehensive Loss

Revenue Recognition

Alternative Revenue Programs

Stock-Based Compensation

For additional information concerning the Company’s Stock-Based Compensation, see Note 14, Stock-Based Compensation.

Income Taxes

the tax benefits resulting from such positions and would report the tax effect as a liability in the Company’s consolidated balance sheets.

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

Recent Accounting Pronouncements

Recently Adopted Accounting Pronouncements

Balance Sheet Components (Tables)

12 Months Ended

Dec. 31, 2025

Balance Sheet Components [Abstract]

Schedule of Allowance for Uncollectible Accounts Activity

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


	Years Ended December 31,
	2025			2024			2023
Balance as of beginning of year	$	12		$	9		$	12
Increase/(decrease) in provision		12			11			5
Amounts written off, less recoveries		(11	)		(8	)		(8	)
Balance as of end of year	$	13		$	12		$	9

Schedule of 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,
	2025		2024
Other current assets:
Prepaid expenses	$	96	$	81
Margin deposits		116		125
Assets from price risk management activities		32		32
	$	244	$	238
Accrued expenses and other current liabilities:
Regulatory liabilities—current	$	73	$	53
Accrued employee compensation and benefits		87		80
Accrued dividends payable		63		57
Accrued interest payable		53		49
Accrued taxes payable		38		36
Margin deposits from wholesale counterparties		21		5
Other		143		130
	$	478	$	410

Schedule of Public Utility Property, Plant, and Equipment

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


	As of December 31,
	2025			2024
Electric utility plant (1):
Generation	$	5,649		$	5,510
Transmission (2)		1,626			1,420
Distribution (2)		6,189			5,714
General		931			1,025
Energy storage		613			222
Intangible		988			972
Total in service		15,996			14,863
Accumulated depreciation and amortization		(5,419	)		(5,085	)
Total in service, net		10,577			9,778
Construction work-in-progress		416			567
Electric utility plant, net	$	10,993		$	10,345