0001868275-26-000032 | 10-K | XBRL Viewer | Constellation Energy Corp

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Supplemental Financial Information - Summary of Taxes Other Than Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Supplemental Financial Information [Abstract]
Property	$ 289	$ 285	$ 253
Gross receipts	163	134	139
Payroll	161	152	142
Other	9	15	19
Taxes other than income taxes	$ 622	$ 586	$ 553

Fair Value of Financial Assets and Liabilities - Narrative (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments without readily determinable fair values	$ 109	$ 150
Forward power basis (in dollars per share)	$ 52.17
Forward gas basis (in dollars per share)	$ 3.52
Private credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	$ 505
Private equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	487
Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Outstanding commitments	$ 576
Minimum \| Private credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	3 years
Minimum \| Private equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	8 years
Minimum \| Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	8 years
Investment, redeemable period for notice	30 days
Maximum \| Private credit
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	5 years
Maximum \| Private equity
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	10 years
Maximum \| Real estate
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investment, term	25 years
Investment, redeemable period for notice	90 days

Supplemental Financial Information - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Inventories, net
Materials and supplies	$ 1,485	$ 1,357
Natural gas, oil, and emission allowances	251	243
Inventories, net	1,736	1,600
Accounts payable and accrued expenses
Accounts payable and accrued expenses	2,813	2,369
Compensation-related accruals	920	907
Taxes accrued	246	232
Other accrued expenses	315	435
Accounts payable and accrued expenses	4,294	3,943
Investments
Equity investments with readily determinable fair values	87	389
Equity investments without readily determinable fair values	109	150
Total	307	640
Nuclear PTCs
Accounts payable and accrued expenses
Estimated nuclear PTCs credits used	375	150
Equity method investments
Investments
Equity method investments	3	2
Employee benefit trusts and investments
Investments
Employee benefit trusts and investments	112	100
Other available for sale debt security investments
Investments
Other available for sale debt security investments	1	1
Constellation Energy Generation, LLC
Inventories, net
Inventories, net	1,736	1,600
Constellation Energy Generation, LLC \| Nonrelated Party
Accounts payable and accrued expenses
Accounts payable and accrued expenses	2,801	2,348
Compensation-related accruals	672	689
Taxes accrued	245	223
Other accrued expenses	315	436
Accounts payable and accrued expenses	4,033	3,696
Commonwealth Edison Co
Investments
Equity investments with readily determinable fair values	$ 82	$ 387

Fair Value of Financial Assets and Liabilities - Fair Value of Financial Liabilities Recorded at Amortized Cost (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
SNF Obligation	$ 1,426	$ 1,366
Carrying Amount
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	7,342	8,412
SNF Obligation	1,426	1,366
Fair Value
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	7,661	8,521
SNF Obligation	1,406	1,278
Fair Value \| Level 2
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	6,995	7,805
SNF Obligation	1,406	1,278
Fair Value \| Level 3
Financial Instruments, Financial Liabilities, Balance Sheet Groupings [Abstract]
Long-Term Debt, including amounts due within one year	666	716
SNF Obligation	$ 0	$ 0

- Definition

Fair value portion of debt instrument payable, including, but not limited to, notes payable and loans payable.

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+ Details

Segment Information - Generation Total Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Segment Reporting Information [Line Items]
Revenues from contracts with customers	$ 22,663	$ 18,964	$ 20,841
Other revenues	2,870	4,604	4,077
Total Operating revenues	25,533	23,568	24,918
Total Purchased power and fuel expenses	(14,681)	(11,419)	(16,001)
Revenues, Net of Purchased Power and Fuel Expense	10,852	12,149	8,917
Operating Segments
Segment Reporting Information [Line Items]
Revenues from contracts with customers	20,299	17,016	18,397
Other revenues	1,669	2,417	617
Total Operating revenues	21,968	19,433	19,014
Total Purchased power and fuel expenses	(11,299)	(9,383)	(9,762)
Revenues, Net of Purchased Power and Fuel Expense	10,669	10,050	9,252
Operating Segments \| Mid-Atlantic
Segment Reporting Information [Line Items]
Revenues from contracts with customers	6,461	5,429	5,453
Other revenues	26	93	(315)
Total Operating revenues	6,487	5,522	5,138
Total Purchased power and fuel expenses	(3,076)	(2,442)	(2,214)
Revenues, Net of Purchased Power and Fuel Expense	3,411	3,080	2,924
Operating Segments \| Midwest
Segment Reporting Information [Line Items]
Revenues from contracts with customers	5,288	3,848	4,846
Other revenues	516	957	(188)
Total Operating revenues	5,804	4,805	4,658
Total Purchased power and fuel expenses	(2,102)	(1,603)	(1,403)
Revenues, Net of Purchased Power and Fuel Expense	3,702	3,202	3,255
Operating Segments \| New York
Segment Reporting Information [Line Items]
Revenues from contracts with customers	2,389	1,937	1,910
Other revenues	(199)	113	111
Total Operating revenues	2,190	2,050	2,021
Total Purchased power and fuel expenses	(590)	(597)	(770)
Revenues, Net of Purchased Power and Fuel Expense	1,600	1,453	1,251
Operating Segments \| ERCOT
Segment Reporting Information [Line Items]
Revenues from contracts with customers	1,296	1,053	1,232
Other revenues	608	497	114
Total Operating revenues	1,904	1,550	1,346
Total Purchased power and fuel expenses	(767)	(503)	(764)
Revenues, Net of Purchased Power and Fuel Expense	1,137	1,047	582
Operating Segments \| Other Power Regions
Segment Reporting Information [Line Items]
Revenues from contracts with customers	4,865	4,749	4,956
Other revenues	718	757	895
Total Operating revenues	5,583	5,506	5,851
Total Purchased power and fuel expenses	(4,764)	(4,238)	(4,611)
Revenues, Net of Purchased Power and Fuel Expense	819	1,268	1,240
Other
Segment Reporting Information [Line Items]
Revenues from contracts with customers	2,364	1,948	2,444
Other revenues	1,201	2,187	3,460
Total Operating revenues	3,565	4,135	5,904
Total Purchased power and fuel expenses	(3,382)	(2,036)	(6,239)
Revenues, Net of Purchased Power and Fuel Expense	183	2,099	(335)
Unrealized mark-to-market gains (losses)	1,758	1,429	1,859
Other \| Product and Service, Other
Segment Reporting Information [Line Items]
Unrealized mark-to-market gains (losses)	$ (805)	$ 316	$ 1,399

Derivative Financial Instruments

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Financial Instruments

We use derivative instruments to manage commodity price risk, interest rate risk, and foreign exchange risk related to ongoing business operations.

Authoritative guidance requires that derivative instruments be recognized as either assets or liabilities at fair value, with changes in fair value of the derivative recognized in earnings immediately. Other accounting treatments, including NPNS, are available through special election and designation, provided they meet specific, restrictive criteria both at the time of designation and on an ongoing basis. All derivative instruments, excluding NPNS, are recorded at fair value through earnings. For all NPNS derivative instruments, accounts receivable or accounts payable are recorded when derivatives settle and revenue or expense is recognized in earnings as the underlying physical commodity is delivered.

Authoritative guidance for the offsetting of assets and liabilities requires the fair value of derivative instruments to be shown in the Combined Notes to Consolidated Financial Statements on a gross basis, even when the derivative instruments are subject to legally enforceable master netting agreements and qualify for net presentation in the Consolidated Balance Sheets. A master netting agreement is an agreement between two counterparties that may have derivative and non-derivative contracts with each other providing for the net settlement of all referenced contracts via one payment stream, which takes place as the contracts deliver, when collateral is requested or in the event of default. In the tables below, which present fair value balances, our commodity economic hedges are shown gross. The impact of the netting of fair value balances with the same counterparty that are subject to legally enforceable master netting agreements, as well as netting of cash collateral, including margin on exchange positions, is aggregated in the collateral and netting columns.

Our use of cash collateral is generally unrestricted unless we were downgraded below investment grade. As our senior unsecured debt rating is currently rated at BBB+ and Baa1 by S&P and Moody's, respectively, it would take a three-notch downgrade by S&P or Moody's for our rating to go below investment grade.

Commodity Price Risk

We employ established policies and procedures to manage our risks associated with market fluctuations in commodity prices by entering into physical and financial derivative contracts, including swaps, futures, forwards, options, and short-term and long-term commitments to purchase and sell energy and energy-related products. We believe these instruments, which are either determined to be non-derivative or classified as economic hedges, mitigate exposure to fluctuations in commodity prices.

To the extent the amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in the prices of electricity, natural gas, and other commodities. We use a variety of derivative and non-derivative instruments to manage the commodity price risk of our electric generation facilities, including power and gas sales, fuel and power purchases, natural gas transportation and pipeline capacity agreements, and other energy-related products marketed and purchased. To manage these risks, we may enter into fixed-price derivative or non-derivative contracts to hedge the variability in future cash flows from expected sales of power and gas and purchases of power and fuel. The objectives for executing such hedges include fixing the price for a portion of anticipated future electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.

In general, increases and decreases in forward market prices have a positive and negative impact, respectively, on owned and contracted generation positions that have not been hedged. Beginning in 2024, our existing nuclear fleet is eligible for a nuclear PTC, an important tool in managing commodity price risk for each nuclear unit not already receiving state support. The nuclear PTC provides increasing levels of support as unit revenues decline below levels established in the IRA and is further adjusted for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. See Note 6 — Government Assistance for additional information.

In locations and periods where our load serving activities do not naturally offset existing generation portfolio risk, remaining commodity price exposure is managed through portfolio hedging activities. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. During this prompt three-year period, we seek to mitigate the price risk associated with our load serving contracts, non-nuclear generation, and any residual price risk for our nuclear generation that the nuclear PTC and state programs may not fully mitigate. We also enter transactions that further optimize the economic benefits of our overall portfolio.

The following tables provide a summary of the commodity derivative fair value balances recorded as of December 31, 2025 and 2024:


December 31, 2025	Economic Hedges		Collateral (a)		Netting(a)		Total
Derivative assets (current)	$	7,349	$	375	$	(6,791)	$	933
Derivative assets (noncurrent)	5,030		272		(4,853)		449
Total derivative assets	12,379		647		(11,644)		1,382
Derivative liabilities (current)	(7,642)		386		6,791		(465)
Derivative liabilities (noncurrent)	(5,585)		319		4,853		(413)
Total derivative liabilities	(13,227)		705		11,644		(878)
Total derivative net assets (liabilities)	$	(848)	$	1,352	$	—	$	504

December 31, 2024
Derivative assets (current)	$	5,518	$	152	$	(4,860)	$	810
Derivative assets (noncurrent)	3,672		120		(3,421)		371
Total derivative assets	9,190		272		(8,281)		1,181
Derivative liabilities (current)	(5,498)		173		4,860		(465)
Derivative liabilities (noncurrent)	(3,961)		141		3,421		(399)
Total derivative liabilities	(9,459)		314		8,281		(864)
Total derivative net assets (liabilities)	$	(269)	$	586	$	—	$	317

_________

(a)We net all available amounts allowed in our Consolidated Balance Sheets in accordance with authoritative guidance for derivatives. These amounts include unrealized derivative transactions with the same counterparty under legally enforceable master netting agreements and cash collateral.

The following table summarizes the net buy/(sell) notional position of commodity derivative transactions, excluding our NPNS derivatives that are not recorded at fair value, as of December 31, 2025 and 2024:


(In millions)	As of December 31,
Commodity Type	2025	2024	Unit of Measure
Electricity	(260)	(130)	MWh
Natural Gas	33	33	MMBtu
Emissions	(35)	(18)	Short Ton

Economic Hedges (Commodity Price Risk)

For the years ended December 31, 2025, 2024, and 2023, we recognized the following net pre-tax commodity unrealized gains (losses), which are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.


	For the Years Ended December 31,
Income Statement Location	2025		2024		2023
Operating revenues	$	(804)	$	313	$	1,402
Purchased power and fuel	183		963		(2,368)
Total	$	(621)	$	1,276	$	(966)

Interest Rate and Foreign Exchange Risk

We utilize interest rate swaps to manage our interest rate exposure and foreign currency derivatives to manage foreign exchange rate exposure associated with international commodity sales and purchases in currencies other than U.S. dollars, both of which are treated as economic hedges. The notional amounts were $1,439 million and $592 million as of December 31, 2025 and 2024, respectively.

The derivative assets and liabilities for the years ended December 31, 2025 and 2024 and the unrealized gains and losses associated with management of interest rate and foreign currency risk for the years ended December 31, 2025, 2024, and 2023 were not material. The unrealized gains and losses associated with management of interest rate and foreign currency exchange rate risk are also included in the Net fair value changes related to derivatives line in the Consolidated Statements of Cash Flows.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties on executed derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts as of the reporting date.

For commodity derivatives, we enter into enabling agreements that allow for payment netting with our counterparties, which reduces our exposure to counterparty risk by providing for the offset of amounts payable to the counterparty against amounts receivable from the counterparty. Typically, each enabling agreement is for a specific commodity and, with respect to each individual counterparty, netting is limited to transactions involving that specific commodity product, except where master netting agreements exist with a counterparty that allows for cross product netting. In addition to right of offset language in the enabling agreement, our credit department establishes credit limits, margining thresholds and collateral requirements for each counterparty, which are defined in the derivative contracts. Counterparty credit limits are based on an internal credit review process that considers a variety of factors, including the results of a scoring model, leverage, liquidity, profitability, credit ratings by credit rating agencies, and other risk management criteria. To the extent that a counterparty’s margining thresholds are exceeded, the counterparty is required to post collateral with us, as specified in each enabling agreement. Our credit department monitors current and forward credit exposure to counterparties and their affiliates, both on an individual and an aggregate basis.

The following tables provide information on the credit exposure for derivative instruments, inclusive of payables and receivables, net of collateral and instruments that are subject to master netting agreements, as of December 31, 2025. The amounts in the tables below exclude credit risk exposure from individual retail counterparties, NPNS contracts, forward values on non-derivative contracts and exposure through RTOs, ISOs, as well as commodity exchanges. The tables further delineate that exposure by credit rating of the counterparties and provide guidance on the concentration of credit risk to individual counterparties.


Rating as of December 31, 2025	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	966	$	10	$	956	1	$	152
Non-investment grade	10		1		9		—	—
No external ratings
Internally rated — investment grade	172		6		166		—	—
Internally rated — non-investment grade	156		23		133		—	—
Total	$	1,304	$	40	$	1,264	1	$	152

__________

(a)As of December 31, 2025, credit collateral held from counterparties was entirely in the form of letters of credit.


Net Credit Exposure by Type of Counterparty	As of December 31, 2025
Investor-owned utilities, marketers, power producers	$	1,052
Energy cooperatives and municipalities	89
Financial Institutions	48
Other	75
Total	$	1,264

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically and financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. Certain of our derivative instruments contain provisions that require us to post collateral. We also enter into commodity transactions on exchanges where the exchanges act as the counterparty to each trade. Transactions on the exchanges must adhere to comprehensive collateral and margining requirements. This collateral may be posted in the form of cash or credit support with thresholds contingent upon our credit ratings from S&P and Moody's. The collateral and credit support requirements vary by contract and by counterparty. These credit-risk-related contingent features stipulate that if we were to be downgraded or lose our investment grade credit ratings (based on our senior unsecured debt rating), we would be required to provide additional collateral. This incremental collateral requirement allows for the offsetting of derivative instruments that are assets with the same counterparty, where the contractual right of offset exists under applicable master netting agreements. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. In such cases, we believe an amount of several months of future payments (e.g., capacity payments) rather than a calculation of fair value is a reasonable estimate for the contingent collateral obligation, which has been factored into the disclosure below.

The aggregate fair value of all derivative instruments with credit-risk-related contingent features in a liability position that are not fully collateralized (excluding transactions on the exchanges that are fully collateralized) is detailed in the table below:


	As of December 31,
Credit-Risk-Related Contingent Features	2025		2024
Gross fair value of derivative contracts containing this feature	$	(1,307)	$	(1,346)
Offsetting fair value of contracts under master netting arrangements	554		602
Net fair value of derivative contracts containing this feature	$	(753)	$	(744)

As of December 31, 2025 and 2024, we posted or held the following amounts of cash collateral and letters of credit on derivative contracts with external counterparties, after giving consideration to offsetting derivative and non-derivative positions under master netting agreements.


	As of December 31,
	2025		2024
Cash collateral posted	$	1,399	$	635
Letters of credit posted	718		890
Cash collateral held	47		49
Letters of credit held	115		91
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(a)(b)(c)	2,670		1,949

_________

(a)Certain of our contracts contain provisions that allow a counterparty to request additional collateral when there has been a subjective determination that our credit quality has deteriorated, generally termed “adequate assurance”. Due to the subjective nature of these provisions, we estimate the amount of collateral that we may ultimately be required to post in relation to the maximum exposure with the counterparty.

(b)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties.

(c)A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively.

We routinely enter into supply forward contracts with certain utilities with one-sided collateral postings only from us. If market prices fall below the benchmark price levels in these contracts, the utilities are not required to post collateral. However, when market prices rise above the benchmark price levels, we are required to post collateral once certain unsecured credit limits are exceeded.

- 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

Consolidated Balance Sheets - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Current assets

Cash and cash equivalents

$ 3,641

$ 3,022

Restricted cash and cash equivalents

107

Accounts receivable, net

4,266

3,718

Derivative Asset, Current

945

843

Inventories, net

1,736

1,600

Renewable energy credits

789

797

Other

635

689

Total current assets

12,119

10,776

Property, plant, and equipment (net of accumulated depreciation and amortization of $19,072 and $18,088, respectively)

22,474

21,235

Deferred debits and other assets

Nuclear decommissioning trust funds

19,336

17,305

Goodwill

420

Derivative assets

450

372

Other

2,450

2,818

Total deferred debits and other assets

22,656

20,915

Total assets

^[1]

57,249

52,926

Current liabilities

Short-term borrowings

1,650

Long-term debt due within one year

1,028

Accounts payable and accrued expenses

4,294

3,943

Derivative liabilities

467

Renewable energy credit obligation

1,075

1,076

Other

366

332

Total current liabilities

7,944

6,846

Long-term debt

7,250

7,384

Deferred credits and other liabilities

Deferred income taxes and unamortized ITCs

3,544

3,331

Asset retirement obligations

13,193

12,449

Pension and non-pension postretirement benefit obligations

1,977

1,875

5,334

4,518

Derivative liabilities

414

399

Other

2,740

2,585

Total deferred credits and other liabilities

27,202

25,157

Total liabilities

^[1]

42,396

39,387

Commitments and contingencies (Note 18)

Member’s equity

Undistributed earnings (deficit)

5,899

4,066

Accumulated other comprehensive income (loss), net

(2,425)

(2,302)

Total liabilities and equity

57,249

52,926

Constellation Energy Generation, LLC

Current assets

Cash and cash equivalents

3,641

3,018

Restricted cash and cash equivalents

Accounts receivable, net

4,251

3,703

Derivative Asset, Current

945

843

Inventories, net

1,736

1,600

Renewable energy credits

789

797

Other

634

689

Total current assets

12,075

10,747

Property, plant, and equipment (net of accumulated depreciation and amortization of $19,072 and $18,088, respectively)

22,474

21,235

Deferred debits and other assets

Nuclear decommissioning trust funds

19,336

17,305

Goodwill

420

Derivative assets

450

372

Other

2,443

2,814

Total deferred debits and other assets

22,649

20,911

Total assets

^[2]

57,198

52,893

Current liabilities

Short-term borrowings

1,650

Long-term debt due within one year

1,028

Derivative liabilities

467

Renewable energy credit obligation

1,075

1,076

Other

358

328

Total current liabilities

8,040

6,944

Long-term debt

7,250

7,384

Deferred credits and other liabilities

Deferred income taxes and unamortized ITCs

3,544

3,331

Asset retirement obligations

13,193

12,449

Pension and non-pension postretirement benefit obligations

1,977

1,875

5,334

4,518

Derivative liabilities

414

399

Other

2,583

2,410

Total deferred credits and other liabilities

27,045

24,982

Total liabilities

^[2]

42,335

39,310

Commitments and contingencies (Note 18)

Member’s equity

Membership interest

10,144

10,538

Undistributed earnings (deficit)

6,808

4,974

Accumulated other comprehensive income (loss), net

(2,425)

(2,302)

Total member’s equity

14,527

13,210

Noncontrolling interests

336

373

Total equity

14,863

13,583

Total liabilities and equity

57,198

52,893

Constellation Energy Generation, LLC | Nonrelated Party

Current liabilities

Accounts payable and accrued expenses

4,033

3,696

Constellation Energy Generation, LLC | Related Party

Current liabilities

Accounts payable and accrued expenses

$ 365

$ 349

[1]

Our consolidated assets include $4,551 million and $4,318 million at December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $914 million and $968 million at December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information.

[2]

Our consolidated assets include $4,551 million and $4,318 million as of December 31, 2025 and 2024, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $914 million and $968 million as of December 31, 2025 and 2024, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 21–Variable Interest Entities for additional information.

Debt and Credit Agreements - Short Term Debt (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Schedule of line of credit, short term, and long term debt [Line Items]
Short-term borrowings	$ 1,650	$ 0
Term Loan Due May 2026
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread	0.90%
Term Loan Due May 2026 \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Weighted Average Interest Rate	5.09%
Short-term borrowings	$ 900
Term Loan Due September 2026
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread	0.90%
Term Loan Due September 2026 \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Weighted Average Interest Rate	4.93%
Short-term borrowings	$ 750

Mergers, Acquisitions, and Dispositions - Narrative (Details) $ / shares in Units, shares in Millions, $ in Millions			1 Months Ended
	Jan. 07, 2026 USD ($) $ / shares GW TW shares	Jan. 10, 2025 USD ($)	Nov. 30, 2023 USD ($) MW	Jun. 30, 2027	Jun. 30, 2026	Dec. 31, 2025
Calpine
Mergers, Acquisitions, and Dispositions [Line Items]
Payments to acquire businesses		$ 4,500
Calpine \| Forecast
Mergers, Acquisitions, and Dispositions [Line Items]
Newly issued shares, lock-up period (percentage)				50.00%	50.00%
Calpine \| Subsequent Event
Mergers, Acquisitions, and Dispositions [Line Items]
Purchase price	$ 22,000
Newly issued shares (in shares) \| shares	50
Par value (in dollars per share) \| $ / shares	$ 0
Calpine \| Natural Gas, Geothermal, Battery Storage, and Solar Assets \| Subsequent Event
Mergers, Acquisitions, and Dispositions [Line Items]
MW of generation \| GW	23
Calpine \| Retail Electric Supplier Platform \| Subsequent Event
Mergers, Acquisitions, and Dispositions [Line Items]
MW of generation \| TW	62
NRG Energy, Inc.
Mergers, Acquisitions, and Dispositions [Line Items]
Purchase price			$ 1,660
MW of generation \| MW			2,645
NRG Energy, Inc.
Mergers, Acquisitions, and Dispositions [Line Items]
Ownership interest			44.00%
NRG Energy, Inc. \| STP Nuclear Operating Company
Mergers, Acquisitions, and Dispositions [Line Items]
Ownership interest			40.00%
NRG Energy, Inc. \| City of Austin
Mergers, Acquisitions, and Dispositions [Line Items]
Ownership interest			16.00%
Constellation South Texas LLP
Mergers, Acquisitions, and Dispositions [Line Items]
Sale of equity ownership						2.00%

Cover Page - USD ($)	12 Months Ended
Cover Page - USD ($)	Dec. 31, 2025	Feb. 01, 2026	Jun. 30, 2025
Document Information [Line Items]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2025
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-41137
Entity Registrant Name	CONSTELLATION ENERGY CORPORATION
Entity Tax Identification Number	87-1210716
Entity Incorporation, State or Country Code	PA
Entity Address, Address Line One	1310 Point Street
Entity Address, City or Town	Baltimore
Entity Address, State or Province	MD
Entity Address, Postal Zip Code	21231-3380
City Area Code	(833)
Local Phone Number	883-0162
Title of 12(b) Security	Common Stock, without par value
Trading Symbol	CEG
Security Exchange Name	NASDAQ
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 100,560,269,473
Entity Common Stock Shares Outstanding		361,990,335
Documents Incorporated by Reference [Text Block]	Documents Incorporated by Reference Portions of the Registrants’ Definitive Proxy Statement relating to the 2026 Annual Meeting of Shareholders are incorporated by reference into Part III of this report. The Registrants expect to file the Definitive Proxy Statement with the Securities and Exchange Commission within 120 days after December 31, 2025.
Document Fiscal Year Focus	2025
Document Fiscal Period Focus	FY
Entity Central Index Key	0001868275
Amendment Flag	false
Constellation Energy Generation, LLC
Document Information [Line Items]
Entity File Number	333-85496
Entity Registrant Name	CONSTELLATION ENERGY GENERATION, LLC
Entity Tax Identification Number	23-3064219
Entity Incorporation, State or Country Code	PA
Entity Address, Address Line One	200 Energy Way
Entity Address, City or Town	Kennett Square
Entity Address, State or Province	PA
Entity Address, Postal Zip Code	19348-2473
City Area Code	(833)
Local Phone Number	883-0162
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Central Index Key	0001168165

Income Taxes - Income (Loss) Before Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Domestic	$ 3,458	$ 4,433	$ 2,137
Foreign	53	83	310
Total Income (loss) before income taxes	$ 3,511	$ 4,516	$ 2,447

- Definition

Amount of income (loss) from continuing operations before deduction of income tax expense (benefit) and income (loss) attributable to noncontrolling interest, and addition of income (loss) from equity method investments.

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+ Details

Commitments and Contingencies - Schedule of Spent Nuclear Fuel Obligation (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	$ 1,426	$ 1,366
Former ComEd units
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	1,271	1,219
One time fee	277
Fitzpatrick
Spent Nuclear Fuel Obligation [Line Items]
Spent nuclear fuel obligation	155	$ 147
One time fee	$ 34

Segment Information (Tables)

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Revenue from External Customers by Geographic Areas

The following tables disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. The disaggregation of revenues reflects our power sales by geographic region.

The following tables, which relate directly to our Consolidated Statements of Operations and Comprehensive Income, provide the reconciliation of operating revenues, purchased power and fuel expenses, and RNF for our reportable segments for the years ended December 31, 2025, 2024, and 2023.


2025	Revenues from contracts with customers		Other revenues(a)		Total Operating revenues		Total Purchased power and fuel expenses		Total RNF
Mid-Atlantic	$	6,461	$	26	$	6,487	$	(3,076)	$	3,411
Midwest	5,288		516		5,804		(2,102)		3,702
New York	2,389		(199)		2,190		(590)		1,600
ERCOT	1,296		608		1,904		(767)		1,137

Other Power Regions	4,865		718		5,583		(4,764)		819
Total Reportable Segments	20,299		1,669		21,968		(11,299)		10,669
Other(b)	2,364		1,201		3,565		(3,382)		183
Total Consolidated Results	$	22,663	$	2,870	$	25,533	$	(14,681)	$	10,852

2024
Mid-Atlantic	$	5,429	$	93	$	5,522	$	(2,442)	$	3,080
Midwest	3,848		957		4,805		(1,603)		3,202
New York	1,937		113		2,050		(597)		1,453
ERCOT	1,053		497		1,550		(503)		1,047

Other Power Regions	4,749		757		5,506		(4,238)		1,268
Total Reportable Segments	17,016		2,417		19,433		(9,383)		10,050
Other(b)	1,948		2,187		4,135		(2,036)		2,099
Total Consolidated Results	$	18,964	$	4,604	$	23,568	$	(11,419)	$	12,149


2023
Mid-Atlantic	$	5,453	$	(315)	$	5,138	$	(2,214)	$	2,924
Midwest	4,846		(188)		4,658		(1,403)		3,255
New York	1,910		111		2,021		(770)		1,251
ERCOT	1,232		114		1,346		(764)		582

Other Power Regions	4,956		895		5,851		(4,611)		1,240
Total Reportable Segments	18,397		617		19,014		(9,762)		9,252
Other(b)	2,444		3,460		5,904		(6,239)		(335)
Total Consolidated Results	$	20,841	$	4,077	$	24,918	$	(16,001)	$	8,917

__________

(a)Includes revenues from nuclear PTCs beginning in 2024 as well as derivatives and leases. Intersegment activity in all periods presented is not material.

(b)Represents revenue activities not allocated to a region. See text above for a description of included activities. Other includes unrealized losses of ($805) million, and unrealized gains of $316 million and $1,399 million, and natural gas revenues from contracts with customers of $1,758 million, $1,429 million, and $1,859 million, for the years ended December 31, 2025, 2024, and 2023, respectively.

Basis of Presentation (Details)	12 Months Ended
Basis of Presentation (Details)	Dec. 31, 2025 segment
Significant Accounting Policies Additional Narrative Information [Line Items]
Number of reportable segments	5
Software and Software Development Costs
Significant Accounting Policies Additional Narrative Information [Line Items]
Expected life	5 years

Variable Interest Entities - Summary of Significant Unconsolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Variable Interest Entity [Line Items]

Total assets

^[1]

$ 57,249

$ 52,926

Total liabilities

^[1]

42,396

39,387

Commercial Agreement VIEs | Variable Interest Entity, Not Primary Beneficiary

Variable Interest Entity [Line Items]

Total assets

711

617

Total liabilities

Other ownership interests in VIE

$ 616

$ 575

[1]

- Definition

Amount of asset recognized for present right to economic benefit.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 235
-Name Accounting Standards Codification
-Section S99
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+ Details

- 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

Debt and Credit Agreements - Debt Issuance Under Exchange (Details) - USD ($) $ in Millions	1 Months Ended
	Jan. 31, 2026	Dec. 31, 2025
Senior Notes
Debt Instrument [Line Items]
Issued Amount		$ 2,290
Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Issued Amount	$ 2,750
Senior Notes \| 2029 Senior Notes
Debt Instrument [Line Items]
Interest Rate		4.625%
Issued Amount		$ 647
Senior Notes \| 2031 Senior Notes due February
Debt Instrument [Line Items]
Interest Rate		5.00%
Issued Amount		$ 848
Senior Notes \| 2031 Senior Notes due March
Debt Instrument [Line Items]
Interest Rate		3.75%
Issued Amount		$ 795
Senior Notes \| 2028 Floating Rate Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Basis spread	0.60%
Issued Amount	$ 300
Senior Notes \| 2028 Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Interest Rate	3.90%
Issued Amount	$ 900
Senior Notes \| 2031 Senior Notes due January \| Subsequent Event
Debt Instrument [Line Items]
Interest Rate	4.40%
Issued Amount	$ 750
Senior Notes \| 2066 Senior Notes \| Subsequent Event
Debt Instrument [Line Items]
Interest Rate	5.875%
Issued Amount	$ 800
Unsecured notes \| Senior Unsecured Notes \| Subsequent Event
Debt Instrument [Line Items]
Issued Amount	$ 2,750

Lessor - Operating Lease, Payments, Fiscal Year Maturity (Details) $ in Millions	Dec. 31, 2025 USD ($)
Leases [Abstract]
2026	$ 50
2027	50
2028	50
2029	48
2030	9
2031 and thereafter	29
Total	$ 236

Government Assistance (Details) - Nuclear PTCs - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Government Assistance [Line Items]
Estimate	$ 320	$ 2,080
Consideration from sale		1,750
Cash proceeds received	95	$ 1,570
Estimated nuclear PTC receivable	$ 120
Government Assistance, Asset, Statement of Financial Position [Extensible Enumeration]	Other
Government Assistance, Liability, Decrease, Statement of Financial Position [Extensible Enumeration]	Accounts payable and accrued expenses	Accounts payable and accrued expenses
Estimated nuclear PTCs credits used	$ 375	$ 150
Estimated refunds recognized	$ 1,190	$ 1,030
Government Assistance, Liability, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Government Assistance, Operating Income, Increase (Decrease), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues
Government assistance, operating income, increase (decrease)	$ 125	$ 50
Other Noncurrent Assets
Government Assistance [Line Items]
Estimated nuclear PTC receivable		$ 185
Government Assistance, Asset, Statement of Financial Position [Extensible Enumeration]		Other
Other Current Assets
Government Assistance [Line Items]
Estimated nuclear PTC receivable		$ 95
Government Assistance, Asset, Statement of Financial Position [Extensible Enumeration]		Other

Revenue from Contracts with Customers (Tables)

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table shows the amounts of future revenues expected to be recorded in each year for performance obligations that are unsatisfied or partially unsatisfied as of December 31, 2025. This disclosure only includes contracts for which the total consideration is fixed and determinable at contract inception. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes mark-to-market derivatives and certain power and gas sales contracts which contain variable volumes and/or variable pricing.


	2026		2027		2028		2029		2030		2031 and thereafter		Total
Remaining performance obligations	$	386	$	269	$	135	$	117	$	61	$	79	$	1,047

Variable Interest Entities - Assets and Liabilities of Consolidated VIEs (Details) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Dec. 31, 2023

Variable Interest Entity [Line Items]

Cash and cash equivalents

$ 3,641

$ 3,022

$ 368

Restricted cash and cash equivalents

107

$ 86

Accounts receivable, net

4,266

3,718

Inventories, net

1,485

1,357

Other current assets

635

689

Total current assets

12,119

10,776

Property, plant and equipment, net

22,474

21,235

Other

2,450

2,818

Total assets

^[1]

57,249

52,926

Long-term debt due within one year

1,028

Accounts payable and accrued expenses

4,294

3,943

Other

366

332

Total current liabilities

7,944

6,846

Long-term debt

7,250

7,384

Asset retirement obligations

13,193

12,449

Other deferred credits and other liabilities

2,740

2,585

Total deferred credits and other liabilities

27,202

25,157

Total liabilities

^[1]

42,396

39,387

Variable Interest Entity, Primary Beneficiary

Variable Interest Entity [Line Items]

Cash and cash equivalents

Restricted cash and cash equivalents

Accounts receivable, net

2,477

2,146

Inventories, net

Other current assets

Total current assets

2,619

2,306

Property, plant and equipment, net

1,942

2,025

Other

123

142

Total assets

4,684

4,473

Long-term debt due within one year

Accounts payable and accrued expenses

Other

Total current liabilities

103

118

Long-term debt

578

642

Asset retirement obligations

231

206

Other deferred credits and other liabilities

Total deferred credits and other liabilities

233

208

Total liabilities

914

968

Unamortized energy contract assets, current

Unamortized energy contract assets, noncurrent

$ 116

$ 133

[1]

Debt and Credit Agreements - Summary of Bank Commitments, Credit Facility Borrowings and Available Capacity (Details) - USD ($) $ in Millions	Dec. 31, 2025	Sep. 30, 2025	Dec. 31, 2024	Nov. 30, 2024
Short-term Debt [Line Items]
Aggregate Bank Commitment	$ 9,458		$ 8,958
Facility Draws	0		0
Outstanding Letters of Credit(a)	2,085		2,173
Outstanding Commercial Paper	0		0
Available Capacity	7,361		6,742
Commercial Paper
Short-term Debt [Line Items]
Aggregate Bank Commitment	4,500		4,500
Revolving Credit Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment	4,500	$ 4,500	4,500
Facility Draws	0		0
Outstanding Letters of Credit(a)	40		51
Outstanding Commercial Paper	0		0
Available Capacity	4,460		4,449
Bilaterals
Short-term Debt [Line Items]
Aggregate Bank Commitment	2,350		1,850
Facility Draws	0		0
Outstanding Letters of Credit(a)	1,276		1,095
Outstanding Commercial Paper	0		0
Available Capacity	1,074		755
Accounts Receivable Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment	1,500		1,500	$ 1,100
Facility Draws	0		0
Outstanding Letters of Credit(a)	0		0
Outstanding Commercial Paper	0		0
Available Capacity	1,500		1,500
Liquidity Facility
Short-term Debt [Line Items]
Aggregate Bank Commitment	971		971
Facility Draws	0		0
Outstanding Letters of Credit(a)	647		907
Outstanding Commercial Paper	0		0
Available Capacity	312		21
Liquidity Facility \| No Additional Collateral Posted
Short-term Debt [Line Items]
Outstanding Commercial Paper	959		928
Project Finance
Short-term Debt [Line Items]
Aggregate Bank Commitment	137		137
Facility Draws	0		0
Outstanding Letters of Credit(a)	122		120
Outstanding Commercial Paper	0		0
Available Capacity	15		17
Other Credit Facility
Short-term Debt [Line Items]
Outstanding Letters of Credit(a)	$ 15		$ 15

Retirement Benefits - Contributions Made to Pension and Other Postretirement Benefit Plans (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Total contributions	$ 211	$ 184	$ 54
Planned contributions	248
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total contributions	174	177	26
Planned contributions	162
Pension Benefits \| Qualified Plan
Defined Benefit Plan Disclosure [Line Items]
Total contributions	161	161
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total contributions	37	$ 7	$ 28
Planned contributions	64
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Planned contributions	$ 22

- 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 715
-SubTopic 20
-Name Accounting Standards Codification
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-Paragraph 5
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
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-URI https://asc.fasb.org/1943274/2147480506/715-20-50-5

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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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
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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Reference 14: http://www.xbrl.org/2003/role/disclosureRef
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+ Details

Supplemental Financial Information - Summary of Other Income (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Supplemental Financial Information [Abstract]
Net realized income on NDT funds - Regulatory Agreement Units	$ 672	$ 553	$ 657
Net realized income on NDT funds - Non-Regulatory Agreement Units	322	266	335
Net unrealized (losses) gains on NDT funds - Regulatory Agreement Units	764	184	397
Net unrealized (losses) gains on NDT funds - Non-Regulatory Agreement Units	506	156	259
Regulatory offset to NDT fund-related activities	(1,152)	(592)	(845)
Total Decommissioning-related activities	1,112	567	803
Net unrealized gains (losses) from equity investments(c)	(304)	11	307
Other	128	92	158
Total Other, net	$ 936	$ 670	$ 1,268

Fair Value of Financial Assets and Liabilities - Fair Value Measurement of Assets and Liabilities, Recurring (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Assets
Cash equivalents	$ 42	$ 120
NDT fund investments	19,396	17,321
Rabbi trust investments	112	100
Investments in equities	87	389
Economic hedges	12,393	9,225
Effect of netting and allocation of collateral	(10,998)	(8,010)
Derivative assets subtotal	1,395	1,215
Liabilities
Economic hedges	(13,231)	(9,462)
Effect of netting and allocation of collateral	12,350	8,596
Derivative liabilities subtotal	(881)	(866)
Deferred compensation obligation	(124)	(93)
Total liabilities measured at fair value	(1,005)	(959)
Total net assets	20,027	18,186
Asset, notational amount	810	1,119
Liability, notational amount	810	1,119
Nuclear Decommissioning Trust Fund Investments
Liabilities
Net liabilities	166	148
Cash and Cash Equivalents \| Constellation Energy Generation, LLC
Assets
Cash equivalents	3,621	2,924
Restricted cash \| Constellation Energy Generation, LLC
Assets
Cash equivalents	57	71
Exelon Corporate \| Cash and Cash Equivalents
Assets
Cash equivalents	70	130
Exelon Corporate \| Cash
Assets
Cash equivalents	0	4
Cash equivalents
Assets
NDT fund investments	237	350
Equities
Assets
NDT fund investments	7,671	7,127
Fixed income
Assets
NDT fund investments	4,162	3,919
Private credit
Assets
NDT fund investments	132	134
Total assets measured at fair value
Assets
Assets	21,032	19,145
Level 1
Assets
Cash equivalents	42	120
NDT fund investments	8,518	7,506
Rabbi trust investments	66	58
Investments in equities	87	389
Economic hedges	1,114	1,278
Effect of netting and allocation of collateral	(889)	(1,097)
Derivative assets subtotal	225	181
Assets	8,938	8,254
Liabilities
Economic hedges	(1,148)	(1,222)
Effect of netting and allocation of collateral	1,065	1,180
Derivative liabilities subtotal	(83)	(42)
Deferred compensation obligation	0	0
Total liabilities measured at fair value	(83)	(42)
Total net assets	8,855	8,212
Level 1 \| Cash equivalents
Assets
NDT fund investments	72	187
Level 1 \| Equities
Assets
NDT fund investments	6,245	5,230
Level 1 \| Fixed income
Assets
NDT fund investments	2,201	2,089
Level 1 \| Private credit
Assets
NDT fund investments	0	0
Level 2
Assets
Cash equivalents	0	0
NDT fund investments	3,157	3,522
Rabbi trust investments	45	41
Investments in equities	0	0
Economic hedges	7,449	5,306
Effect of netting and allocation of collateral	(6,853)	(4,790)
Derivative assets subtotal	596	516
Assets	3,798	4,079
Liabilities
Economic hedges	(8,021)	(5,462)
Effect of netting and allocation of collateral	7,657	5,157
Derivative liabilities subtotal	(364)	(305)
Deferred compensation obligation	(124)	(93)
Total liabilities measured at fair value	(488)	(398)
Total net assets	3,310	3,681
Level 2 \| Cash equivalents
Assets
NDT fund investments	165	163
Level 2 \| Equities
Assets
NDT fund investments	1,426	1,897
Level 2 \| Fixed income
Assets
NDT fund investments	1,566	1,462
Level 2 \| Private credit
Assets
NDT fund investments	0	0
Level 3
Assets
Cash equivalents	0	0
NDT fund investments	527	502
Rabbi trust investments	1	1
Investments in equities	0	0
Economic hedges	3,830	2,641
Effect of netting and allocation of collateral	(3,256)	(2,123)
Derivative assets subtotal	574	518
Assets	1,102	1,021
Liabilities
Economic hedges	(4,062)	(2,778)
Effect of netting and allocation of collateral	3,628	2,259
Derivative liabilities subtotal	(434)	(519)
Deferred compensation obligation	0	0
Total liabilities measured at fair value	(434)	(519)
Total net assets	668	502
Level 3 \| Cash equivalents
Assets
NDT fund investments	0	0
Level 3 \| Equities
Assets
NDT fund investments	0	0
Level 3 \| Fixed income
Assets
NDT fund investments	395	368
Level 3 \| Private credit
Assets
NDT fund investments	132	134
Assets measured at NAV
Assets
NDT fund investments	$ 7,194	$ 5,791

Accounts Receivable - Allowance for Credit Losses (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 190	$ 56
Plus: Current period provision for expected credit losses	47	17
Less: Write-offs, net of recoveries	(79)	(21)
Plus: Facility amendment impact	0	138
Ending balance	$ 158	$ 190

Derivative Financial Instruments - Summary of Cash Collateral and Letters of Credit (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Cash collateral posted	$ 1,399	$ 635
Letters of credit posted	718	890
Cash collateral held	47	49
Letters of credit held	115	91
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)	$ 2,670	$ 1,949

- Definition

Amount of obligation to return cash collateral under master netting arrangements that have not been offset against derivative assets.

+ References + Details

- Definition

Amount of right to receive cash collateral under master netting arrangements that have not been offset against derivative liabilities.

+ References + Details

Consolidated Statements of Changes in Equity - USD ($) $ in Millions	Total	Retained Earnings (Deficit)	Accumulated Other Comprehensive Income (Loss), net	Noncontrolling Interests	Constellation Energy Generation, LLC	Constellation Energy Generation, LLC Membership Interest	Constellation Energy Generation, LLC Retained Earnings (Deficit)	Constellation Energy Generation, LLC Accumulated Other Comprehensive Income (Loss), net	Constellation Energy Generation, LLC Noncontrolling Interests
Beginning Balance at Dec. 31, 2022					$ 11,414	$ 12,408	$ 412	$ (1,760)	$ 354
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	$ 1,577	$ 1,623		$ (46)	1,577		1,623		(46)
Distribution to member	53			53	53				53
Other comprehensive income (loss), net of income taxes					(1,239)	(871)	(368)
Other comprehensive income (loss), net of income taxes	(431)		$ (431)		(431)			(431)
Ending Balance at Dec. 31, 2023					11,374	11,537	1,667	(2,191)	361
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	3,738	3,749		(11)	3,738		3,749		(11)
Distribution to member	23			23	23				23
Other comprehensive income (loss), net of income taxes					(1,441)	(999)	(442)
Other comprehensive income (loss), net of income taxes	(111)		(111)		(111)			(111)
Ending Balance at Dec. 31, 2024					13,583	10,538	4,974	(2,302)	373
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,323	$ 2,319		4	2,323		2,319		4
Distribution to member	(41)			$ (41)	(41)				(41)
Contribution from member					156	156
Other comprehensive income (loss), net of income taxes					(1,035)	(550)	(485)
Other comprehensive income (loss), net of income taxes	$ (123)		$ (123)		(123)			(123)
Ending Balance at Dec. 31, 2025					$ 14,863	$ 10,144	$ 6,808	$ (2,425)	$ 336

- Definition

Amount after tax and reclassification adjustments of other comprehensive income (loss).

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
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+ 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
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+ Details

Asset Retirement Obligations - Nuclear Decommissioning Asset Retirement Obligation Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 647	$ 655	$ 596
Constellation South Texas LLP
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Sale of equity ownership	2.00%
Nuclear Decommissioning
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	$ 12,186	13,891
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	108	(2,299)
Accretion expense	630	640
Costs incurred related to decommissioning plants	(16)	(24)
Reclassification to liabilities held for sale	0	(22)
Ending balance	$ 12,908	$ 12,186	$ 13,891

Regulatory Matters	12 Months Ended
Regulatory Matters	Dec. 31, 2025
Regulated Operations [Abstract]
Regulatory Matters	Regulatory Matters The following matters below discuss the status of our material regulatory and legislative proceedings. New England Regulatory Matters Mystic Units 8 and 9 Cost of Service Agreement. In December 2018, FERC issued an order accepting a cost of service agreement for Mystic Units 8 and 9 for the period between June 1, 2022 to May 31, 2024. The agreement preserved the two gas-fired electric generating units for the period while allowing the Mystic units to recover their costs of operating, including a substantial portion of the costs associated with the adjacent EMT. Upon the expiration of the agreement on May 31, 2024, the two generating units retired. The Mystic COS required an annual process whereby we identified and supported our projected costs under the agreement and/or true-up previous projections to the actual costs incurred. Interested parties then had the opportunity to challenge our filings. All proceedings related to the annual files or outstanding matters related to the Mystic COS have been settled and approved by FERC. The settlements did not have a material financial impact on our consolidated financial statements. Federal Regulatory Matters One Big Beautiful Bill Act of 2025. In July 2025, the OBBBA was signed into law, which, among other things, permanently extends key provisions of the 2017 Tax Cuts and Jobs Act, including full bonus depreciation and immediate deduction of research and development expenses. In addition, the OBBBA preserves transferability and certain federal tax credits from the IRA, specifically, 45U for existing nuclear plants through 2032 and 45Y for new nuclear projects, including uprates, restarts, and new reactors, through 2035, while enhancing the credit to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements. As it relates to both 45U and 45Y, certain foreign entity of concern rules must be met to qualify for the respective credits. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. While the provisions of the OBBBA resulted in acceleration of cash benefits of approximately $200 million, the impact of these provisions recognized in the year ended December 31, 2025 was not material to our results of operations. Operating License Renewals Conowingo Hydroelectric Project. In 2012, we submitted an application to FERC for a new license for the Conowingo Hydroelectric Project (Conowingo). In connection with our efforts to obtain a water quality certification pursuant to Section 401 of the Clean Water Act (401 Certification) from MDE for Conowingo, we had been working with MDE and other stakeholders to resolve water quality licensing issues, including: (1) water quality, (2) fish habitat, and (3) sediment. In 2019, we and MDE filed with FERC a Joint Offer of Settlement (Offer of Settlement) that would resolve all outstanding issues relating to the 401 Certification. FERC subsequently issued a new 50-year license for Conowingo, effective March 1, 2021. Several environmental groups appealed FERC’s ruling to the U.S. Court of Appeals for the D.C. Circuit. The court of appeals issued a decision vacating FERC’s decision to grant Conowingo its license renewal and sending the matter back to FERC for further proceedings. Upon issuance of the mandate from the U.S. Court of Appeals for the D.C. Circuit, we began operating under an annual license, which renews automatically, containing the same terms as the license that was in effect prior to the 2021 FERC order. MDE informed us that as a result of the U.S. Court of Appeals decision, MDE would be resuming its administrative reconsideration of the 401 Certification. In September 2025, we reached a settlement agreement with MDE and the other parties to the MDE reconsideration proceeding, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, which resolves all outstanding issues relating to the 401 Certification. As a result, MDE issued a Revised Water Quality Certification, which is needed for FERC to move forward with the issuance of a new 50-year license. The Revised Water Quality Certification and accompanying settlement agreement provide for a modified operational flow regime, funding for water quality and resiliency projects, commitments for trash and debris removal, fish and eel passage improvements, funding for freshwater mussel restoration and control of invasive species like snakeheads and blue catfish, and funds to support additional studies on dredging and related activities. Our commitments under the various provisions of this settlement are not effective unless and until FERC approves and issues the new license. The terms of this settlement have no impact on the prior settlement agreement with the DOI. The financial impact of this settlement and other commitments related to this renewal are estimated to be $15 million to $20 million per year, on average, recognized over the term of the 50-year renewal, inclusive of capital and operating costs. The actual timing and amount of the majority of these costs are not currently fixed and will vary from year to year throughout the life of the new license. We cannot currently predict when FERC will issue the new license. Depreciation provisions continue to assume operation through 2071 given our expectation that a 50-year license will be issued. Peach Bottom Units 2 and 3. In March 2020, the NRC approved a second 20-year license renewal for Peach Bottom Units 2 and 3. As a result, Peach Bottom Units 2 and 3 were granted the authority to operate through 2053 and 2054, respectively. Notwithstanding its 2020 approval, in February 2022, the NRC took action to modify Peach Bottom's subsequently renewed licenses in response to a request for hearing that the NRC had not previously adjudicated. In its February 2022 decision, the NRC reversed itself and concluded that the previous environmental review required by the National Environmental Policy Act (NEPA) for the Peach Bottom subsequently renewed licenses was incomplete because it did not adequately address environmental impacts resulting from renewing the units’ licenses for an additional 20 years. As a result, the NRC undertook a rulemaking to modify its regulations and guidance to specifically address environmental impacts during the period of subsequent license renewal. In addition, the NRC modified the expiration dates for the Peach Bottom licenses from 2053 and 2054 to 2033 and 2034, respectively, pending the completion of the updated NEPA analysis. In September 2025, the NRC completed its environmental impact review of Peach Bottom Units 2 and 3, restoring the expiration dates of the respective operating licenses to 2053 and 2054, consistent with current accounting estimates utilized for both depreciation and ARO assumed retirement dates.

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 (loss)	$ 2,323	$ 3,738	$ 1,577
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,601	2,700	2,514
Deferred income taxes and amortization of ITCs	273	222	251
Net fair value changes related to derivatives	645	(1,297)	996
Net realized and unrealized (gains) losses on NDT funds	(708)	(311)	(476)
Net realized and unrealized (gains) losses on equity investments	279	(11)	(307)
Other non-cash operating activities	(223)	(172)	18
Changes in assets and liabilities:
Accounts receivable	(363)	688	396
Inventories	(134)	(99)	60
Accounts payable and accrued expenses	316	1,121	(1,330)
Option premiums received (paid), net	38	216	26
Collateral received (posted), net	(773)	1,803	(1,491)
Income taxes	625	296	325
Pension and non-pension postretirement benefit contributions	(211)	(184)	(54)
Other assets and liabilities	(451)	(11,174)	(7,806)
Net cash flows provided by (used in) operating activities	4,237	(2,464)	(5,301)
Cash flows from investing activities
Capital expenditures	(2,949)	(2,565)	(2,422)
Proceeds from NDT fund sales	6,946	6,005	5,822
Investment in NDT funds	(7,284)	(6,282)	(6,050)
Collection of DPP, net	0	10,217	7,340
Other investing activities	103	85	31
Net cash flows provided by (used in) investing activities	(3,198)	7,428	3,031
Cash flows from financing activities
Change in short-term borrowings	0	(1,105)	146
Proceeds from short-term borrowings with maturities greater than 90 days	1,650	200	539
Repayments of short-term borrowings with maturities greater than 90 days	0	(739)	(200)
Issuance of long-term debt	0	920	3,195
Retirement of long-term debt	(1,076)	(121)	(168)
Other financing activities	(108)	(1)	42
Net cash flows provided by (used in) financing activities	(420)	(2,289)	2,196
Increase (decrease) in cash, restricted cash, and cash equivalents	619	2,675	(74)
Cash, restricted cash, and cash equivalents at beginning of period	3,129	454	528
Cash, restricted cash, and cash equivalents at end of period	3,748	3,129	454
Supplemental disclosure of non-cash investing and financing activities
Increase (decrease) in DPP	0	9,045	8,097
Increase (decrease) in PP&E related to ARO update	187	(1,486)	501
Constellation Energy Generation, LLC
Cash flows from operating activities
Net income (loss)	2,323	3,738	1,577
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,601	2,700	2,514
Deferred income taxes and amortization of ITCs	273	222	251
Net fair value changes related to derivatives	645	(1,297)	996
Net realized and unrealized (gains) losses on NDT funds	(708)	(311)	(476)
Net realized and unrealized (gains) losses on equity investments	279	(11)	(307)
Other non-cash operating activities	(304)	(218)	(44)
Changes in assets and liabilities:
Accounts receivable	(363)	697	389
Receivables from and payables to affiliates, net	16	231	73
Inventories	(134)	(99)	60
Accounts payable and accrued expenses	326	1,116	(1,330)
Option premiums received (paid), net	38	216	26
Collateral received (posted), net	(773)	1,803	(1,491)
Income taxes	625	296	325
Pension and non-pension postretirement benefit contributions	(211)	(184)	(54)
Other assets and liabilities	(464)	(11,369)	(7,897)
Net cash flows provided by (used in) operating activities	4,169	(2,470)	(5,388)
Cash flows from investing activities
Capital expenditures	(2,949)	(2,565)	(2,422)
Proceeds from NDT fund sales	6,946	6,005	5,822
Investment in NDT funds	(7,284)	(6,282)	(6,050)
Collection of DPP, net	0	10,217	7,340
Acquisitions of assets and businesses	(14)	(32)	(1,690)
Other investing activities	103	85	31
Net cash flows provided by (used in) investing activities	(3,198)	7,428	3,031
Cash flows from financing activities
Change in short-term borrowings	0	(1,105)	146
Proceeds from short-term borrowings with maturities greater than 90 days	1,650	200	539
Repayments of short-term borrowings with maturities greater than 90 days	0	(739)	(200)
Issuance of long-term debt	0	920	3,195
Retirement of long-term debt	(1,076)	(121)	(168)
Distributions to member	(1,035)	(1,441)	(1,239)
Contributions from member	156	0	0
Other financing activities	(61)	3	23
Net cash flows provided by (used in) financing activities	(366)	(2,283)	2,296
Increase (decrease) in cash, restricted cash, and cash equivalents	605	2,675	(61)
Cash, restricted cash, and cash equivalents at beginning of period	3,115	440	501
Cash, restricted cash, and cash equivalents at end of period	3,720	3,115	440
Supplemental disclosure of non-cash investing and financing activities
Increase (decrease) in DPP	0	9,045	8,097
Increase (decrease) in PP&E related to ARO update	$ 187	$ (1,486)	$ 501

Asset Retirement Obligations

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Nuclear Decommissioning Asset Retirement Obligations

We have a legal obligation to decommission our nuclear power plants following the permanent cessation of operations. To estimate our nuclear decommissioning obligations we use a probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple outcome scenarios that include significant estimates and assumptions, and are based on decommissioning cost studies, cost escalation rates, probabilistic cash flow models, and discount rates. We update our AROs annually, unless circumstances warrant more frequent updates, based on our review of updated cost studies and our annual evaluation of cost escalation factors and probabilities assigned to various scenarios.

The financial statement impact for changes in an ARO, on an individual unit basis, due to the changes in and timing of estimated cash flows generally result in a corresponding change in the unit’s ARC in Property, plant, and equipment in the Consolidated Balance Sheets. If an ARO decreases for a Non-Regulatory Agreement Unit without any remaining ARC, the corresponding change is recorded as a decrease in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income, whereas the corresponding decrease for Regulatory Agreement Units without any remaining ARC results in an increase to the Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets.

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:


	2025		2024
Beginning balance as of January 1	$	12,186	$	13,891
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	108		(2,299)
Accretion expense	630		640
Costs incurred related to decommissioning plants	(16)		(24)
Reclassification to liabilities held for sale(a)	—		(22)
Ending balance as of December 31	$	12,908	$	12,186

__________

(a)Reflects amounts transferred to Liabilities held for sale for the sale of 2% interest to CPS in connection with the 2023 acquisition of interest in STP. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

The net $108 million increase in the AROs during 2025 for the changes in, and timing of, estimated future cash flows was driven primarily by higher escalation rates partially offset by higher discount rates and revised cost studies for our Braidwood, Byron, Clinton, and LaSalle nuclear plants.

The net $2,299 million decrease in the AROs during 2024 for changes in the amounts and timing of estimated decommissioning cash flows was driven by multiple adjustments, including the following:

•Net decrease of $3,036 million due to changes in assumed retirement dates for various plants, including Braidwood, Byron, Calvert Cliffs, FitzPatrick, LaSalle, Limerick, NMP Unit 2, Quad Cities, Salem and Crane

•A decrease of $154 million related to a change in assumed timing of DOE acceptance of SNF and a revised cost study for Salem

•An increase of $891 million due to an increase in cost escalation rates and lower discount rates

NDT Funds

NDT funds have been established for each of our nuclear units to satisfy our nuclear decommissioning obligations, as required by the NRC, and withdrawals from these funds for reasons other than to pay for decommissioning are restricted pursuant to NRC requirements until all decommissioning activities have been completed. Generally, NDT funds established for a particular unit may not be used to fund the decommissioning obligations of any other unit.

The NDT funds associated with our nuclear units have been funded with amounts collected from the previous owners and their respective utility customers. PECO is authorized to collect funds, in revenues, through regulated rates for decommissioning the former PECO nuclear plants, and these collections are scheduled through the operating lives of these former PECO plants. The amounts collected from PECO customers are remitted to us and deposited into the NDT funds for the unit for which funds are collected. Every five years, PECO files a rate adjustment with the PAPUC that reflects PECO’s calculations of the estimated amount needed to decommission each of the former PECO units based on updated fund balances and estimated decommissioning costs. The rate adjustment is used to determine the amount collectible from PECO customers. In March 2022, PECO filed its Nuclear Decommissioning Cost Adjustment with the PAPUC proposing an annual recovery from customers of approximately $4 million. In August 2022, the PAPUC approved the filing, and the new rates became effective January 1, 2023.

Additionally, for the STP units, we maintain decommissioning trust funds for those units proportionate to our ownership. We also retain the authority through the PUCT to obtain additional decommissioning funding through AEP Texas and CenterPoint. Every five years, owners of each Texas jurisdictional nuclear generation unit are required to file an update of decommissioning costs with the PUCT in support of appropriate utility rates for decommissioning trust funding. In July 2023, the decommissioning cost update for our share of the STP decommissioning obligation was filed, proposing annual funding amounts from AEP Texas and CenterPoint totaling approximately $1 million. In March 2024, the PUCT approved the filing, and AEP Texas and CenterPoint tariffs were adjusted accordingly in May and August 2024, respectively.

Any shortfall of funds necessary for decommissioning, determined for each generating station unit, are generally required to be funded by us, with the exception of STP and the former PECO units. We have recourse to collect additional amounts from the respective utility customers through the utility commissions for the former PECO units and STP in the event of a shortfall of NDT funds. Collection of additional amounts for the former PECO units are subject to certain limitations and thresholds, as prescribed by an order from the PAPUC that limits collection of amounts associated with the first $50 million of any shortfall of trust funds compared to decommissioning costs, as well as 5% of any additional shortfalls, on an aggregate basis for all former PECO units. The initial $50 million and up to 5% of any additional shortfalls would be borne by us. No such limitations exist for the STP units, however PUCT regulations require that any funds remaining in the trust after completion of decommissioning to be refunded to utility customers in a manner determined by the commission. Aside from the former PECO units and STP, no recourse exists to collect additional amounts from utility customers for any of our other nuclear units.

With respect to the Regulatory Agreement Units, any funds remaining in the NDTs after all decommissioning has been completed are required to be refunded to the respective utility customers, subject to certain limitations that allow sharing of excess funds with us related to the former PECO units. With respect to our other nuclear units, we retain any funds remaining after decommissioning. However, in connection with CENG's acquisition of the NMP and Ginna plants and settlements with certain regulatory agencies, certain conditions pertaining to NDT funds apply that, if met, could possibly result in obligations to make payments to certain third parties (clawbacks). For NMP and Ginna, the clawback provisions are triggered only in the event that the required decommissioning activities are discontinued or not started or completed in a timely manner. In the event that the clawback provisions are triggered for NMP, then, depending upon the triggering event, an amount equal to 50% of the total amount withdrawn from the funds for non-decommissioning activities as defined in the agreement or 50% of any excess funds in the trust funds above the amounts required for decommissioning (including SNF management and site restoration) is to be paid to the NMP sellers. In the event that the clawback provisions are triggered for Ginna, then an amount equal to any estimated cost savings realized by not completing any of the required decommissioning activities is to be paid to the Ginna sellers. We expect to comply with applicable regulations and timely commence and complete all required decommissioning activities.

We had NDT funds totaling $19,396 million and $17,321 million as of December 31, 2025 and 2024, respectively. The current portions of the NDT funds, which are included in Other current assets in our Consolidated Balance Sheets, were not material as of December 31, 2025 and 2024. See Note 22 — Supplemental Financial Information for additional information on activities of the NDT funds.

Accounting Implications of the Regulatory Agreement Units

See Note 1 — Basis of Presentation for additional information on the accounting policy for Regulatory Agreement Units.

For the former PECO units and STP, given the symmetric settlement provisions that allow for continued recovery of decommissioning costs from the respective utility customers in the event of a shortfall and the obligation for us to ultimately return excess funds to the respective utility customers (on an aggregate basis for all seven former PECO units and on the underlying utility customer basis for STP) decommissioning-related activities are generally offset in the Consolidated Statements of Operations and Comprehensive Income, regardless of whether the NDT funds are expected to exceed or fall short of the total estimated decommissioning obligation. The offset of decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income results in an equal adjustment to noncurrent payables or noncurrent receivables. Any changes to the existing PECO or STP regulatory agreements could impact our ability to offset decommissioning-related activities in the Consolidated Statements of Operations and Comprehensive Income, and the potential impact to our consolidated financial statements could be material.

For the former ComEd units, given no further recovery from ComEd customers is permitted and we retain an obligation to ultimately return any unused NDTs to ComEd customers (on a unit-by-unit basis), to the extent the related NDT investment balances are expected to exceed the total estimated decommissioning obligation for each unit, decommissioning-related activities are offset in the Consolidated Statements of Operations and Comprehensive Income which results in us recognizing a noncurrent payable. However, given the asymmetric settlement provision that does not allow for continued recovery from ComEd customers in the event of a shortfall, recognition of a receivable related to former ComEd Units is not permissible and accounting for decommissioning-related activities for that unit would not be offset, and the impact to the Consolidated Statements of Operations and Comprehensive Income could be material during such periods.

The following table presents our noncurrent payables to ComEd, PECO, CenterPoint, and AEP Texas reflected as Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets as of December 31, 2025 and 2024:


	As of December 31,
	2025		2024
ComEd	$	4,313	$	3,780
PECO	442		247
CenterPoint	430		365
AEP Texas	149		126
Payables related to Regulatory Agreement Units	$	5,334	$	4,518

As of December 31, 2025, decommissioning-related activities for all of the former ComEd units, except for Zion (see Zion Station Decommissioning below), are currently offset in the Consolidated Statements of Operations and Comprehensive Income.

The decommissioning-related activities for the Non-Regulatory Agreement Units are reflected in the Consolidated Statements of Operations and Comprehensive Income within Operating and maintenance expense, Depreciation and amortization expense, and Other, net.

Zion Station Decommissioning

In 2010, we completed an asset sale agreement under which ZionSolutions assumed responsibility for decommissioning Zion Station and we transferred to ZionSolutions substantially all the Zion Station’s assets, including the related NDT funds. In November 2023, ZionSolutions completed its contractual obligations and transferred the NRC license back to us. We will store the SNF at Zion Station until it is transferred to the DOE for ultimate disposal and complete all remaining decommissioning activities associated with the SNF dry storage facility.

Any shortage of funds necessary to maintain the SNF and decommission the SNF storage facility is ultimately required to be funded by us. As of December 31, 2025 and 2024, the ARO associated with Zion's SNF storage facility is $170 million and $163 million, respectively, and the NDT funds available to fund this obligation are $67 million and $63 million, respectively.

NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in specified minimum amounts for radiological decommissioning of the facility at the end of its life. The estimated decommissioning obligations are calculated using an NRC methodology that is different from the AROs recorded in the Consolidated Balance Sheets primarily due to differences in the type of costs included in the estimates, the basis for estimating such costs, and assumptions regarding the decommissioning alternatives to be used, potential license renewals, decommissioning cost escalation, and the growth rate in the NDT funds. Under NRC regulations, if the minimum funding requirements for radiological decommissioning calculated under the NRC methodology are greater than the future value of the NDT funds, also calculated under the NRC methodology, then the NRC requires resolution of the shortfalls which could include further funding or other financial guarantees.

Key assumptions used in the minimum funding calculation for radiological decommissioning costs using the NRC methodology at December 31, 2025 include: (1) consideration of costs only for the removal of radiological contamination at each unit; (2) the option on a unit-by-unit basis to use generic, non-site specific cost estimates; (3) consideration of only one decommissioning scenario for each unit; (4) the plants cease operation at the end of their current license lives (with no assumed license renewals for those units that have not already received renewals); (5) the assumption of current nominal dollar cost estimates that are neither escalated through the anticipated period of decommissioning, nor discounted using the CARFR; and (6) assumed annual after-tax returns on the NDT funds of 2% (3% for the former PECO units, as specified by the PAPUC).

In contrast, the key criteria and assumptions used by us to determine the AROs and to forecast the target growth in the NDT funds as of December 31, 2025 include: (1) the use of site specific cost estimates that are updated at least once every five years; (2) the inclusion in the ARO estimate of all legally unavoidable costs required to decommission the unit (e.g., radiological decommissioning and full site restoration for certain units, on-site SNF maintenance and storage subsequent to ceasing operations and until DOE acceptance, and disposal of certain LLRW); (3) as applicable, the consideration of multiple scenarios where decommissioning and site restoration activities, as applicable, are completed under possible scenarios ranging from 10 to 70 years after the cessation of plant operations or the end of the current licensed operating life; (4) the consideration of multiple end of life scenarios; (5) the measurement of the obligation at the present value of the future estimated costs and an annual accretion of the ARO; and (6) an estimated targeted annual pre-tax return on the NDT funds of 6.2% to 7.1% (as compared to a historical 5-year annual average pre-tax return of approximately 6.8%).

We are required to provide to the NRC a biennial report by unit (annually for units that have been retired or are within five years of license expiration), based on values as of December 31, addressing our ability to meet the NRC minimum funding levels. Depending on the value of the trust funds, we may be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that NRC minimum funding requirements are met. As a result, our cash flows and financial position may be significantly adversely affected.

We filed our biennial decommissioning funding status report with the NRC in March 2025 for all units, including our shutdown units, except for STP units which were included in a separate report submitted to the NRC submitted by STPNOC. The status reports demonstrated adequate decommissioning funding assurance based on trust fund values as of December 31, 2024 for all units except for Peach Bottom Unit 1. Financial assurance for decommissioning Peach Bottom Unit 1 is provided by collections from PECO customers. See NDT Funds section above for additional information.

We will file the next decommissioning funding status report with the NRC in March 2026. This report will reflect the status of decommissioning funding as of December 31, 2025 for shutdown units and any units within 5 years of license expiration. We expect the funding status report to demonstrate adequate funding assurance based on the value of trust funds as of December 31, 2025 for all units.

As the future values of trust funds change due to market conditions, the NRC minimum funding status of our units will change. In addition, if changes occur to the regulatory agreements with the PAPUC or the PUCT that currently allow amounts to be collected from utility customers for decommissioning the former PECO and STP units, the NRC minimum funding status of those plants could change at subsequent NRC filing dates.

Non-Nuclear Asset Retirement Obligations

We have AROs for plant closure costs associated with our natural gas, oil, and renewable generating facilities, including asbestos abatement, removal of certain storage tanks, restoring leased land to the condition it was in prior to construction of renewable generating stations, disposal of hazardous materials, and other decommissioning-related activities. See Note 1 — Basis of Presentation for additional information on the accounting policy for AROs.

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:


	2025		2024
Beginning balance as of January 1	$	288	$	257
Net increase due to changes in, and timing of, estimated future cash flows	12		19
Accretion expense	17		15

Costs incurred related to decommissioning plants	—		(3)

Ending balance as of December 31	$	317	$	288

Schedule II - Valuation and Qualifying Accounts Schedule (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Allowance for credit losses
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	$ 196	$ 61	$ 51
Charged to Costs and Expenses	49	18	25
Charged to Other Accounts	1	138	0
Deductions	(79)	(21)	(15)
Balance at End of Period	167	196	61
Deferred tax valuation allowance
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	3	10	11
Charged to Costs and Expenses	0	(7)	0
Charged to Other Accounts	0	0	(1)
Deductions	0	0	0
Balance at End of Period	3	3	10
Reserve for obsolete materials
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Period	238	246	238
Charged to Costs and Expenses	0	(4)	8
Charged to Other Accounts	(1)	(4)	9
Deductions	(22)	0	(9)
Balance at End of Period	$ 215	$ 238	$ 246

Intangible Assets - Schedule of Other Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Finite-Lived Intangible Assets [Line Items]
Gross	$ 2,024	$ 2,094
Accumulated Amortization	(1,823)	(1,858)
Net	201	236
UECs
Finite-Lived Intangible Assets [Line Items]
Gross	1,850	1,850
Accumulated Amortization	(1,686)	(1,669)
Net	164	181
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Gross	174	244
Accumulated Amortization	(137)	(189)
Net	$ 37	$ 55

- 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.

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+ Details

Stock-Based Compensation Plans - Unit Activity (Details) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Performance Shares
Shares
Beginning Balance (in shares)	535,626
Granted (in shares)	120,057
Change in performance (in shares)	96,623
Forfeited (in shares)	(3,812)
Undistributed vested awards (in shares)	(469,066)
Ending Balance (in shares)	279,428	535,626
Weighted Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share)	$ 99.06
Granted (in dollars per share)	321.83	$ 127.03
Change in performance (in dollars per share)	313.60
Forfeited (in dollars per share)	195.73
Undistributed vested awards (in dollars per share)	332.97
Ending balance (in dollars per share)	$ 198.49	$ 99.06
Restricted Stock Units (RSUs)
Shares
Beginning Balance (in shares)	809,093
Granted (in shares)	265,512
Vested (in shares)	(437,388)
Forfeited (in shares)	(11,067)
Undistributed vested awards (in shares)	(76,272)
Ending Balance (in shares)	549,878	809,093
Weighted Average Grant Date Fair Value (per share)
Beginning balance (in dollars per share)	$ 96.53
Granted (in dollars per share)	312.97	$ 134.18
Vested (in dollars per share)	82.45
Forfeited (in dollars per share)	197.23
Undistributed vested awards (in dollars per share)	271.03
Ending balance (in dollars per share)	$ 181.54	$ 96.53

Derivative Financial Instruments - Summary of Credit Risk Related Contingent Features (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Gross fair value of derivative contracts containing this feature	$ (1,307)	$ (1,346)
Offsetting fair value of in-the-money contracts under master netting arrangements	554	602
Net fair value of derivative contracts containing this feature	$ (753)	$ (744)

- Definition

Fair value, before effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities elected not to be offset. Excludes liabilities not subject to a master netting arrangement.

+ References + Details

Debt and Credit Agreements - Summary of Credit Facility Thresholds (Details) - USD ($) $ in Millions	1 Months Ended
	Feb. 24, 2026	Dec. 31, 2025	Dec. 31, 2024
Line of Credit Facility [Line Items]
Credit facility		$ 9,458	$ 8,958
Bilaterals
Line of Credit Facility [Line Items]
Credit facility		2,350	$ 1,850
Bilaterals \| Subsequent Event
Line of Credit Facility [Line Items]
Increase in credit agreement	$ 100
Bilaterals \| January 2016
Line of Credit Facility [Line Items]
Credit facility		150
Bilaterals \| October 2019
Line of Credit Facility [Line Items]
Credit facility		200
Bilaterals \| November 2019
Line of Credit Facility [Line Items]
Credit facility		300
Bilaterals \| November 2019
Line of Credit Facility [Line Items]
Credit facility		100
Bilaterals \| November 2019
Line of Credit Facility [Line Items]
Credit facility		100
Bilaterals \| May 2020
Line of Credit Facility [Line Items]
Credit facility		300
Bilaterals \| August 2022
Line of Credit Facility [Line Items]
Credit facility		50
Bilaterals \| March 2023
Line of Credit Facility [Line Items]
Credit facility		100
Bilaterals \| December 2023
Line of Credit Facility [Line Items]
Credit facility		200
Bilaterals \| March 2024
Line of Credit Facility [Line Items]
Credit facility		200
Bilaterals \| May 2024
Line of Credit Facility [Line Items]
Credit facility		150
Bilaterals \| January 2025
Line of Credit Facility [Line Items]
Credit facility		200
Bilaterals \| March 2025
Line of Credit Facility [Line Items]
Credit facility		$ 300

Derivative Financial Instruments - Summary of Economic Hedges (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Derivative [Line Items]
Total	$ (645)	$ 1,297	$ (996)
Economic Hedges \| Commodity Contract
Derivative [Line Items]
Total	(621)	1,276	(966)
Economic Hedges \| Commodity Contract \| Operating revenues
Derivative [Line Items]
Total	(804)	313	1,402
Economic Hedges \| Commodity Contract \| Purchased power and fuel
Derivative [Line Items]
Total	$ 183	$ 963	$ (2,368)

- Definition

The net change in the difference between the fair value and the carrying value, or in the comparative fair values, of derivative instruments, including options, swaps, futures, and forward contracts, held at each balance sheet date, that was included in earnings for the period.

+ References + Details

Shareholders' Equity (Tables)

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Accelerated Share Repurchases

The following table summarizes each ASR agreement for the years ended December 31, 2025 and December 31, 2024:


(in millions, except average price paid per share)
ASR Agreement Initiation	Total Cost		Initial Shares Received	ASR Agreement Settlement	Additional Shares Received	Total Number of Shares Purchased	Average Price Paid per Share
March 2024	$	354	1.7	May 2024	0.2	1.9	$	182.65
May 2024	$	505	1.8	July 2024	0.6	2.4	$	211.40
June 2025	$	404	1.1	August 2025	0.2	1.3	$	311.84

Schedule Of Changes In Accumulated Other Comprehensive Income (Loss)

The following tables present changes in AOCI, net of tax, by component:


	Gains (losses) on Cash Flow Hedges		Pension and OPEB Items(a)		Foreign Currency Items		Total
Balance at December 31, 2022	$	(9)	$	(1,725)	$	(26)	$	(1,760)
OCI before reclassifications	(2)		(453)		2		(453)
Amounts reclassified from AOCI	1		21		—		22
Net current-period OCI	(1)		(432)		2		(431)
Balance at December 31, 2023	$	(10)	$	(2,157)	$	(24)	$	(2,191)
OCI before reclassifications	—		(176)		(10)		(186)
Amounts reclassified from AOCI	4		71		—		75
Net current-period OCI	4		(105)		(10)		(111)
Balance at December 31, 2024	$	(6)	$	(2,262)	$	(34)	$	(2,302)
OCI before reclassifications	—		(219)		21		(198)
Amounts reclassified from AOCI	7		68		—		75
Net current-period OCI	7		(151)		21		(123)
Balance at December 31, 2025	$	1	$	(2,413)	$	(13)	$	(2,425)

__________

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 14 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Year Ended December 31,
	2025		2024		2023
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost	$	(24)	$	(24)	$	(10)
Pension and OPEB plans valuation adjustment	74		59		151

Cybersecurity Risk Management and Strategy Disclosure	12 Months Ended
Cybersecurity Risk Management and Strategy Disclosure	Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]	Risk Management and Strategy We have established technical systems programs and processes to manage material risks from cybersecurity threats including assessing and identifying existing cybersecurity risks, as well as continuously monitoring for developing risks. Our cybersecurity risk management strategy is established at the executive level and is implemented through our cybersecurity program which deploys risk-based security controls and services to protect our customers, personnel, information and cyber assets. The program aligns enterprise cyber and physical security controls with the National Institute of Standards & Technology (NIST) Cybersecurity Framework (CSF) and other industry standards such as the NERC and NRC cybersecurity standards. Our cybersecurity program is aligned to the five functions of the NIST Cybersecurity Framework – identify, detect, protect, respond, and recover. Cybersecurity risk is assessed and reported in our enterprise risk management program, which utilizes the Three Lines Model adapted from the Institute of Internal Auditors, for risk management to assign clear risk responsibilities across the enterprise. Through coordination with operational teams, we align on cybersecurity risk classification, categorization, likelihood, and potential impact to the Company. At the highest level, our program includes multi-layered oversight by the Board of Directors and Board Committees. Our cybersecurity and physical security controls are implemented through technical systems, policies and procedures we utilize for planning, performing, managing, assessing, innovating, and improving our security controls. To protect our information and cyber assets, we implement practices for training and screening of personnel, access management, network defense, asset configuration management, vulnerability assessment (including penetration testing), third-party security, and privacy and information protection. Our defense-in-depth strategy to protect our cyber assets and sensitive information reduces the potential severity and duration of a cybersecurity incident by leveraging security measures across various layers of the enterprise. Cross-functional executive steering committees and peer groups, with business unit and technical stakeholder participation, are maintained to support oversight, security controls development, change management, implementation, evaluation, continuous improvement, and sustainment. To assist in detecting cybersecurity events, we deploy security logging and monitoring, malicious code detection, and data loss protection tools. If we are the target of a cybersecurity attack, we have established processes for incident response and crisis management to triage potential incidents, determine severity, contain, and eradicate a threat. These processes require notifications to regulatory and other governmental authorities of cybersecurity events as required by law, including providing notice to investors for material cybersecurity events. To recover our systems and information, we utilize established system recovery plans, data and configuration backup strategies, and business continuity plans. As part of our process to continuously improve, we utilize our internal audit, risk, and legal functions to evaluate security controls and risk management practices. We also engage third-party subject matter experts to independently assess our programs, processes and technical controls, as needed. For our regulated cyber assets associated with critical infrastructure, such as those within the scope of NERC and the NRC, regulatory auditors and inspectors monitor our adherence to mandatory cybersecurity requirements on a regular frequency using a variety of compliance monitoring and enforcement mechanisms.
Cybersecurity Risk Management Processes Integrated [Flag]	true
Cybersecurity Risk Management Processes Integrated [Text Block]	Our cybersecurity risk management strategy is established at the executive level and is implemented through our cybersecurity program which deploys risk-based security controls and services to protect our customers, personnel, information and cyber assets.
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]	Board Governance and Management Our Board is actively engaged in monitoring the performance of the Company's cybersecurity program and maintains oversight of the Company’s enterprise risk program, including with respect to commodity markets, market design, enterprise security (physical and cyber), operating risks, and financial performance. While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters. The Nuclear Oversight Committee is tasked with overseeing compliance with policies and procedures to manage and mitigate cybersecurity risks associated with our nuclear assets. The Audit and Risk Committee oversees policies and processes established by management to identify, assess, monitor, manage and control technology and cyber risks, among other risks. Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks. We also report on the state of our cybersecurity program, provide key risk indicators to track performance, and schedule additional informational sessions on cybersecurity practices, as needed. Emergent matters or events are reported to the Board between scheduled meetings on an ad hoc basis through our incident response and crisis management protocols. At the executive and management level, the Chief Administration Officer, via delegations to the cybersecurity organization, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise. Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services, including coordination with our corporate security function. Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity. Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity. In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block]	While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters.
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]	Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks.
Cybersecurity Risk Role of Management [Text Block]	At the executive and management level, the Chief Administration Officer, via delegations to the cybersecurity organization, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise. Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services, including coordination with our corporate security function. Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity. Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity. In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program.
Cybersecurity Risk Management Positions or Committees Responsible [Flag]	true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block]	Our Board is actively engaged in monitoring the performance of the Company's cybersecurity program and maintains oversight of the Company’s enterprise risk program, including with respect to commodity markets, market design, enterprise security (physical and cyber), operating risks, and financial performance. While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters. The Nuclear Oversight Committee is tasked with overseeing compliance with policies and procedures to manage and mitigate cybersecurity risks associated with our nuclear assets. The Audit and Risk Committee oversees policies and processes established by management to identify, assess, monitor, manage and control technology and cyber risks, among other risks. Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks. We also report on the state of our cybersecurity program, provide key risk indicators to track performance, and schedule additional informational sessions on cybersecurity practices, as needed. Emergent matters or events are reported to the Board between scheduled meetings on an ad hoc basis through our incident response and crisis management protocols. At the executive and management level, the Chief Administration Officer, via delegations to the cybersecurity organization, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise. Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services, including coordination with our corporate security function. Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity. Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity. In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]	Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]	Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag]	true

Segment Information - Narrative (Details)	12 Months Ended
Segment Information - Narrative (Details)	Dec. 31, 2025 segment
Segment Reporting [Abstract]
Number of reportable segments	5

Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on a Recurring Basis Gain Loss Included in Earnings (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	$ 317	$ 856
Total unrealized gains (losses)	(47)	(121)
Operating Revenues
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	$ (340)	$ (539)	$ 706
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Total unrealized gains (losses)	$ (172)	$ 207	$ 1,673
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Purchased Power and Fuel
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	$ 65	$ (293)	$ (503)
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Total unrealized gains (losses)	$ 116	$ (333)	$ (479)
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Other, net
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	$ 9	$ 5	$ 2
Fair Value, Asset, Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues	Operating revenues
Total unrealized gains (losses)	$ 9	$ 5	$ 2
Fair Value, Asset, Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net

Stock-Based Compensation Plans - Unit Fair Value (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share)	$ 321.83	$ 127.03
Total fair value of performance shares vested	$ 156	$ 138
Unrecognized compensation costs	$ 41	$ 50
Remaining weighted-average period	1 year 6 months
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant date fair value (in dollars per share)	$ 312.97	$ 134.18
Total fair value of performance shares vested	$ 57	$ 42
Unrecognized compensation costs	$ 57	$ 41
Remaining weighted-average period	1 year 10 months 24 days	1 year 9 months 18 days

- 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

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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

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-URI https://asc.fasb.org/1943274/2147480429/718-10-50-2

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-Topic 718
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-Name Accounting Standards Codification
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-Topic 718
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480483/718-10-35-1D

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+ Details

Consolidated Balance Sheets, Parent - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Current assets

Cash and cash equivalents

$ 3,641

$ 3,022

Restricted cash and cash equivalents

107

Accounts receivable, net

4,266

3,718

Derivative assets

945

843

Inventories, net

1,736

1,600

Renewable energy credits

789

797

Other

635

689

Total current assets

12,119

10,776

Property, plant, and equipment (net of accumulated depreciation and amortization of $19,072 and $18,088, respectively)

22,474

21,235

Deferred debits and other assets

Nuclear decommissioning trust funds

19,336

17,305

Goodwill

420

Derivative assets

450

372

Other

2,450

2,818

Total deferred debits and other assets

22,656

20,915

Total assets

^[1]

57,249

52,926

Current liabilities

Short-term borrowings

1,650

Long-term debt due within one year

1,028

Accounts payable and accrued expenses

4,294

3,943

Derivative liabilities

467

Renewable energy credit obligation

1,075

1,076

Other

366

332

Total current liabilities

7,944

6,846

Long-term debt

7,250

7,384

Deferred credits and other liabilities

Deferred income taxes and unamortized ITCs

3,544

3,331

Asset retirement obligations

13,193

12,449

Pension and non-pension postretirement benefit obligations

1,977

1,875

5,334

4,518

Derivative liabilities

414

399

Other

2,740

2,585

Total deferred credits and other liabilities

27,202

25,157

Total liabilities

^[1]

42,396

39,387

Commitments and contingencies (Note 18)

Member’s equity

Common stock (No par value, 1,000 shares authorized, 312 shares and 313 shares outstanding, respectively)

11,043

11,402

Retained earnings (deficit)

5,899

4,066

Accumulated other comprehensive income (loss), net

(2,425)

(2,302)

Total shareholders’ equity

14,517

13,166

Noncontrolling interests

336

373

Total equity

14,853

13,539

Total liabilities and equity

$ 57,249

$ 52,926

[1]

Income Taxes - Schedule of Carryforwards and Corresponding Valuation Allowances (Details) $ in Millions	Dec. 31, 2025 USD ($)
Federal
Operating Loss Carryforwards [Line Items]
Federal general business credits carryforwards and other carryforwards	$ 0
State
Operating Loss Carryforwards [Line Items]
State net operating losses (NOL) and other carryforwards	393
Deferred taxes on state tax attributes (net)	17
Valuation allowance on state tax attributes	(3)
Foreign
Operating Loss Carryforwards [Line Items]
State net operating losses (NOL) and other carryforwards	20
Deferred taxes on state tax attributes (net)	$ 5

Debt and Credit Agreements - Narrative (Details) $ in Millions		1 Months Ended							3 Months Ended	6 Months Ended			12 Months Ended			13 Months Ended
	Jun. 30, 2023	Feb. 24, 2026 USD ($)	Jan. 31, 2026 USD ($)	Nov. 30, 2025 USD ($)	Sep. 30, 2025 USD ($)	Jan. 31, 2024 USD ($)	May 31, 2023	May 31, 2021 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023	Jun. 30, 2023	Dec. 31, 2025 USD ($) MW	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Jun. 30, 2024	Nov. 30, 2024 USD ($)	Dec. 31, 2020 USD ($)	Mar. 31, 2016 USD ($)	Dec. 31, 2015	Sep. 30, 2013 USD ($)	Dec. 31, 2011 USD ($)
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									$ 9,458	$ 8,958			$ 9,458	$ 8,958
Repayments of debt													1,076	121	$ 168
Loan									0	0			0	0
Loan balance									7,403				7,403
Letters of credit outstanding									2,085	2,173			2,085	2,173
Total long-term debt									7,403	8,474			7,403	8,474
Calpine \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Debt assumed		$ 6,500	$ 12,600
Senior unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Amount									2,290				2,290
Total long-term debt									$ 5,688	6,588			$ 5,688	6,588
Senior unsecured notes \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Amount			2,750
Senior unsecured notes \| Calpine \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Amount			2,300
Maximum \| Senior unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Rates									6.50%				6.50%
Minimum \| Senior unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Rates									5.60%				5.60%
Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Nonrecourse debt									$ 1,900	2,000			$ 1,900	2,000
Revolving Credit Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility					$ 4,500				4,500	4,500			4,500	4,500
Aggregate commitments available including incremental commitments					7,000
Incremental commitments					$ 2,500
Line of credit facility, fee rate					0.175%
Loan									0	0			0	0
Letters of credit outstanding									$ 40	51			$ 40	51
Letter of credit
Schedule of line of credit, short term, and long term debt [Line Items]
Rates									1.075%				1.075%
Accounts Receivable Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									$ 1,500	1,500			$ 1,500	1,500			$ 1,100
Loan									0	0			0	0
Letters of credit outstanding									0	0			0	0
Accounts Receivable Facility \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Amount drawn		600
Bilaterals
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									2,350	1,850			2,350	1,850
Loan									0	0			0	0
Letters of credit outstanding									1,276	1,095			$ 1,276	1,095
Daily Simple SOFR Rate \| Non-investment grade \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread													1.00%
Daily Simple SOFR Rate \| Revolving Credit Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread					0.075%
Term SOFR Rate \| Non-investment grade \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread													2.00%
Term SOFR Rate \| Revolving Credit Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread					1.075%
Secured Overnight Financing Rate (SOFR) Overnight Index Swap Rate \| Accounts Receivable Facility
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread													0.10%
DOE Loan Program \| Unsecured notes
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread				0.375%
Amount				$ 1,000
Corporate Debt \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Repayments of debt			2,500
Corporate Debt \| Calpine \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Debt assumed			7,600
Various Non-recourse Debt and Project Financing Arrangements \| Calpine \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Debt assumed			$ 5,000
Senior Secured First Lien Notes \| Subsequent Event
Schedule of line of credit, short term, and long term debt [Line Items]
Repayments of debt		$ 1,250
Antelope Valley Solar Ranch One \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread													0.375%
Loan																						$ 646
Average blended interest rate																				2.82%
Loan balance									335	365			$ 335	365
Letters of credit outstanding									36	36			36	36
Continetal Wind \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility									$ 128				$ 128
Rates									6.00%				6.00%
Amount																					$ 613
Loan balance									$ 260	290			$ 260	290
Letters of credit outstanding									122	119			$ 122	119
Total net capacity (in megawatts) \| MW													667
Revolver facility									4				$ 4
Renewable Power Generation \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Rates																			4.11%
Amount																			$ 150
Loan balance									55	60			55	60
Renewables 2020 \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Loan balance																		$ 750
Notational amount, debt						$ 120							516
Interest rate, debt hedge						3.98%					0.8295%	1.05%
Total long-term debt									$ 600	$ 630			$ 600	630
Renewables 2020 \| Secured Overnight Financing Rate (SOFR) \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread									2.00%	2.25%						2.76%
Floor rate									1.00%				1.00%
Renewables 2020 \| LIBOR \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Basis spread	2.50%
West Medway II, LLC \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Credit facility								$ 150
Notational amount, debt								$ 113
Interest rate, debt hedge							0.5365%	0.61%
Total long-term debt										$ 50				$ 50
West Medway II, LLC \| Nonrecourse \| Maximum
Schedule of line of credit, short term, and long term debt [Line Items]
Rates							3.225%
West Medway II, LLC \| Nonrecourse \| Minimum
Schedule of line of credit, short term, and long term debt [Line Items]
Rates							2.975%
West Medway II, LLC \| Secured Overnight Financing Rate (SOFR) \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Rates							3.35%
West Medway II, LLC \| LIBOR \| Nonrecourse
Schedule of line of credit, short term, and long term debt [Line Items]
Rates							2.875%

Retirement Benefits - Assumptions (Details)	12 Months Ended
Retirement Benefits - Assumptions (Details)	Dec. 31, 2025	Dec. 31, 2024
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Period average rate	4.25%
Period average rate thereafter	3.75%
Pension Benefits
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	5.38%	5.66%
Investment crediting rate	5.93%	5.72%
Rate of compensation increase	4.25%	4.25%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	5.66%	5.17%
Investment crediting rate	5.72%	5.07%
Expected long-term rate of return on plan assets	6.50%	6.50%
Rate of compensation increase(d)	4.25%	4.25%
OPEB
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Benefit Obligation [Abstract]
Discount rate	5.30%	5.63%
Rate of compensation increase	4.25%	4.25%
Healthcare cost trend on covered charges	9.00%	7.00%
Healthcare cost trend on covered charges, ultimate rate	5.00%	5.00%
Defined Benefit Plan, Weighted Average Assumptions Used in Calculating Net Periodic Benefit Cost [Abstract]
Discount rate	5.63%	5.15%
Expected long-term rate of return on plan assets	6.00%	6.50%
Rate of compensation increase(d)	4.25%	4.25%
Healthcare cost trend on covered charges	0.0700	0.0500
Healthcare cost trend on covered charges, ultimate rate	0.0500

Stock-Based Compensation Plans - Schedule of Stock-based Compensation Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Total stock-based compensation expense included in Operating and maintenance expense	$ 385	$ 332	$ 178
Income tax benefit	(99)	(85)	(45)
Total after-tax stock-based compensation expense	$ 286	$ 247	$ 133

Shareholders' Equity

12 Months Ended

Dec. 31, 2025

Equity [Abstract]

Shareholders' Equity

Share Repurchase Program (CEG Parent)

Since 2023, our Board of Directors authorized the repurchase of up to $3 billion of the Company's outstanding common stock. Share repurchases may be made through a variety of methods, which may include open market transactions, privately negotiated transactions, or purchases pursuant to a Rule 10b5-1 trading plan, provided that the amounts spent do not exceed what is authorized. Any repurchased shares are constructively retired and cancelled. The program does not obligate us to acquire a minimum number of shares during any period and our repurchase of the Company's common stock may be limited, suspended, or discontinued at any time at our discretion and without prior notice. No other repurchase plans or programs have been authorized. As of December 31, 2025, there was approximately $593 million of remaining authority to repurchase shares of the Company's outstanding common stock.

During 2025, there were no open market repurchases. During 2024, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $150 million.

In 2024 and 2025, we entered into ASR agreements with financial institutions to initiate share repurchases of our common stock. Under the ASR agreements, we paid a specified amount to the financial institutions and received an initial delivery of shares of common stock, which resulted in an immediate reduction in the number of our shares outstanding. Based on the terms of the ASR agreements, we received an initial share delivery based on 80% of each ASR agreements' cost. Upon settlement of the ASR agreements, the financial institution delivers additional incremental shares. The total number of shares ultimately delivered, and therefore the average price paid per share, is determined at the end of the applicable purchase period of each ASR agreement based on the average of the daily-volume weighted average share price, less a discount.

The following table summarizes each ASR agreement for the years ended December 31, 2025 and December 31, 2024:


(in millions, except average price paid per share)
ASR Agreement Initiation	Total Cost		Initial Shares Received	ASR Agreement Settlement	Additional Shares Received	Total Number of Shares Purchased	Average Price Paid per Share
March 2024	$	354	1.7	May 2024	0.2	1.9	$	182.65
May 2024	$	505	1.8	July 2024	0.6	2.4	$	211.40
June 2025	$	404	1.1	August 2025	0.2	1.3	$	311.84

Capped Call Options. During 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $150 million plus a nominal cash premium. The cash received restored the remaining authority available for repurchases.

Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants)

The following tables present changes in AOCI, net of tax, by component:


	Gains (losses) on Cash Flow Hedges		Pension and OPEB Items(a)		Foreign Currency Items		Total
Balance at December 31, 2022	$	(9)	$	(1,725)	$	(26)	$	(1,760)
OCI before reclassifications	(2)		(453)		2		(453)
Amounts reclassified from AOCI	1		21		—		22
Net current-period OCI	(1)		(432)		2		(431)
Balance at December 31, 2023	$	(10)	$	(2,157)	$	(24)	$	(2,191)
OCI before reclassifications	—		(176)		(10)		(186)
Amounts reclassified from AOCI	4		71		—		75
Net current-period OCI	4		(105)		(10)		(111)
Balance at December 31, 2024	$	(6)	$	(2,262)	$	(34)	$	(2,302)
OCI before reclassifications	—		(219)		21		(198)
Amounts reclassified from AOCI	7		68		—		75
Net current-period OCI	7		(151)		21		(123)
Balance at December 31, 2025	$	1	$	(2,413)	$	(13)	$	(2,425)

__________

The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):


	Year Ended December 31,
	2025		2024		2023
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost	$	(24)	$	(24)	$	(10)
Pension and OPEB plans valuation adjustment	74		59		151

Stock-Based Compensation Plans - Narrative (Details) - shares	12 Months Ended
	Dec. 31, 2025	Feb. 01, 2022
Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares authorized		20,000,000
Performance Shares \| Long Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Percentage to be settled as common stock	50.00%
Percentage to be settled as cash	50.00%
Performance period	3 years
Vesting period	3 years
Restricted Stock Units (RSUs) \| Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period	3 years
Restricted Stock Units (RSUs) \| Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Requisite service period	5 years

Retirement Benefits - Benefit Obligations Net of Plan Assets, Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Other current liabilities	$ (22)	$ (9)
Pension and non-pension benefit obligations	(1,072)	(1,071)
OPEB
Defined Contribution Plan Disclosure [Line Items]
Other current liabilities	(52)	(20)
Pension and non-pension benefit obligations	$ (905)	$ (804)

Basis of Presentation (Policies)	12 Months Ended
Basis of Presentation (Policies)	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Constellation Energy Corporation (“CEG Parent” or the “Company”), a Pennsylvania corporation, was formed for the purpose of separation of Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries from its predecessor parent company, Exelon Corporation (“Exelon”), into an independent, publicly traded company. On February 1, 2022, the separation was completed by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of its predecessor’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the “Separation”). Constellation has been an individual registrant since 2002 with the registration of its public debt securities under the Securities Act. Prior to the Separation, Constellation historically filed consolidated financial statements as an individual registrant to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs. The remaining interests in the consolidated VIEs are included in noncontrolling interests in the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We proportionately consolidate our undivided ownership interest in jointly-owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly-Owned Electric Plants for additional information on the application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates to a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost, adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings.
Use of Estimates	Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, UECs, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ materially from those estimates.
Revenues	Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction.
Taxes Directly Imposed on Revenue-Producing Transactions	Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and sustainable solutions. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in revenue and expense in the Consolidated Statements of Operations and Comprehensive Income.
Government Assistance	Government Assistance. As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current U.S. GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined under GAAP related to accounting for contingencies.
Leases	Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases.
Income Taxes	Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income.
Cash and Cash Equivalents	Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2025 and 2024, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities.
Allowance for Credit Losses on Accounts Receivables	Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience and current information. The allowance for credit losses for our retail and wholesale customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. The allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality.
Variable Interest Entities	Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: •qualitative assessment of factors determinant in whether we have a controlling financial interest, •ongoing reconsideration of this assessment, and •where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary.
Inventories	Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Reserves are recorded for excess and obsolete inventory. Natural gas, oil, and emission allowances are generally included in Inventory when delivered and are expensed to Purchased power and fuel expense when consumed. Materials and supplies are generally included in Inventory when delivered and are expensed to Operating and maintenance, or capitalized to Property, plant and equipment, as appropriate, when installed or used.
Debt and Equity Security Investments	Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the NAV for qualifying investments as a practical expedient to determine the fair values. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and expected payment of income taxes on trust earnings.Equity Security Investments. We hold equity securities both with and without readily determinable fair values. For those with readily determinable fair values, realized and unrealized gains and losses are recognized in Other, net within the Consolidated Statements of Operations and Comprehensive Income. For those without readily determinable fair values, we have elected the measurement alternative, which records investments at cost adjusted for observable transactions involving identical or similar investments of the same issuer, less impairment. Changes in measurement under this alternative are also reported in Other, net within the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income in the amount by which the security’s carrying amount exceeds its fair value.
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with outages and planned major maintenance activities are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property are charged to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project-specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense.
Nuclear Fuel	Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed.
Depreciation and Amortization	Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated useful lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated useful lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions.
Asset Retirement Obligations	Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning AROs annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units.
Accounting Implications of the Regulatory Agreement Units	Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables within Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets.
Asset Impairments	Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record the proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in income (losses) of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income.
Derivative Financial Instruments	Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of our customer-facing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value.
Retirement Benefits	Retirement Benefits We sponsor defined benefit pension and OPEB plans as described in Note 14 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans are remeasured annually as of year end. The measurements involve various factors, assumptions, and accounting policy elections. The impact of assumption changes or experiences different from that assumed on pension and OPEB obligations are recognized over time, not immediately in the Consolidated Statements of Operations and Comprehensive Income. For defined benefit pension plans, gains or losses exceeding the greater of 10% of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. For OPEB plans, gains or losses exceeding the greater of 10% of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population. We separately report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans in our Consolidated Statements of Operations and Comprehensive Income. The service cost component remains in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single-employer plan accounting.
Renewable Energy Certificates/Credits	Renewable Energy Certificates/Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost when delivered and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the relative fair value at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

Income Taxes - Income Taxes Paid (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Income Taxes [Line Items]
Federal	$ 341	$ 242	$ 315
Total income taxes paid (net of refunds)	446	436	466
Illinois
Income Taxes [Line Items]
State	16	24	19
Maryland
Income Taxes [Line Items]
State	11	24	7
Other state
Income Taxes [Line Items]
State	91	141	41
United Kingdom
Income Taxes [Line Items]
Foreign	(20)	0	61
Other foreign
Income Taxes [Line Items]
Foreign	$ 7	$ 5	$ 23

Commitments and Contingencies - Settlement Agreements (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Commitments and Contingencies Disclosure [Abstract]
DOE receivable - current	$ 117	$ 124
DOE receivable - noncurrent	28	42
Amounts owed to co-owners	$ (20)	$ (40)

Leases - Lease Terms (Details)	12 Months Ended
Leases - Lease Terms (Details)	Dec. 31, 2025
Minimum
Lessor, Lease, Description [Line Items]
Remaining lease terms	1 year
Options to extend the term	2 years
Options to terminate within	2 years
Remaining lease terms	1 year
Options to extend the term	5 years
Maximum
Lessor, Lease, Description [Line Items]
Remaining lease terms	30 years
Options to extend the term	30 years
Remaining lease terms	15 years
Options to extend the term	20 years

Derivative Financial Instruments - Summary of Credit Risk Exposure (Details) $ in Millions	12 Months Ended
	Dec. 31, 2025 USD ($) counterparty
Total Exposure Before Credit Collateral
Derivative [Line Items]
Total	$ 1,304
Total Exposure Before Credit Collateral \| Internally rated — investment grade
Derivative [Line Items]
Total	172
Total Exposure Before Credit Collateral \| Internally rated — non-investment grade
Derivative [Line Items]
Total	156
Total Exposure Before Credit Collateral \| Investment grade
Derivative [Line Items]
Total	966
Total Exposure Before Credit Collateral \| Non-investment grade
Derivative [Line Items]
Total	10
Credit Collateral
Derivative [Line Items]
Total	40
Credit Collateral \| Internally rated — investment grade
Derivative [Line Items]
Total	6
Credit Collateral \| Internally rated — non-investment grade
Derivative [Line Items]
Total	23
Credit Collateral \| Investment grade
Derivative [Line Items]
Total	10
Credit Collateral \| Non-investment grade
Derivative [Line Items]
Total	1
Net Exposure
Derivative [Line Items]
Total	1,264
Net Exposure \| Investor-owned utilities, marketers, power producers
Derivative [Line Items]
Total	1,052
Net Exposure \| Energy cooperatives and municipalities
Derivative [Line Items]
Total	89
Net Exposure \| Financial Institutions
Derivative [Line Items]
Total	48
Net Exposure \| Other
Derivative [Line Items]
Total	75
Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Total	166
Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Total	133
Net Exposure \| Investment grade
Derivative [Line Items]
Total	956
Net Exposure \| Non-investment grade
Derivative [Line Items]
Total	$ 9
Number of Counterparties Greater than 10% of Net Exposure
Derivative [Line Items]
Number of counterparties \| counterparty	1,000,000
Number of Counterparties Greater than 10% of Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Number of Counterparties Greater than 10% of Net Exposure \| Investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	1,000,000
Number of Counterparties Greater than 10% of Net Exposure \| Non-investment grade
Derivative [Line Items]
Number of counterparties \| counterparty	0
Net Exposure of Counterparties Greater than 10% of Net Exposure
Derivative [Line Items]
Total	$ 152
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Internally rated — investment grade
Derivative [Line Items]
Total	0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Internally rated — non-investment grade
Derivative [Line Items]
Total	0
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Investment grade
Derivative [Line Items]
Total	152
Net Exposure of Counterparties Greater than 10% of Net Exposure \| Non-investment grade
Derivative [Line Items]
Total	$ 0

Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule Of Goodwill

The following table provides a rollforward of the carrying amount of goodwill from January 1, 2024 to December 31, 2025. There were no impairment losses for the years ended December 31, 2025, 2024, and 2023.


	2025		2024
Beginning balance as of January 1	$	420	$	425
Goodwill allocated to assets held for sale	—		(5)
Ending balance as of December 31	$	420	$	420

Schedule of Finite-Lived Intangible Assets

Our other intangible assets and liabilities included in Other current assets, Other deferred debits and other assets, Other current liabilities, and Other deferred credits and other liabilities in the Consolidated Balance Sheets, consisted of the following as of December 31, 2025 and 2024. The customer relationships are generally amortized on a straight line basis, while UECs are amortized in accordance with the expected realization of the underlying cash flows:


	December 31, 2025						December 31, 2024
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
UECs	$	1,850	$	(1,686)	$	164	$	1,850	$	(1,669)	$	181
Customer Relationships	174		(137)		37		244		(189)		55

Total	$	2,024	$	(1,823)	$	201	$	2,094	$	(1,858)	$	236

Schedule Of Finite-Lived Intangible Assets Amortization Expense

The following table summarizes the amortization expense related to our other intangible assets and liabilities for the years ended December 31, 2025, 2024, and 2023:


	For the Years Ended December 31,
	2025		2024		2023
Amortization expense(a)	$	35	$	60	$	58

__________

(a)See Note 22 — Supplemental Financial Information for additional information on amortization expense.

Schedule of Finite-Lived Intangible Assets, Future Amortization Expense

The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2025:


For the Years Ending December 31,	Estimated Future Amortization Expense
2026	$	41
2027	33
2028	28
2029	20
2030	16
2031 and thereafter	63
Total	$	201

- Definition

Tabular disclosure of goodwill by reportable segment and in total which includes a rollforward schedule.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 3: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 4: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 5: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 6: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 7: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1
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-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 8: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
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-Section 50
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-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 9: http://www.xbrl.org/2009/role/commonPracticeRef
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-Name Accounting Standards Codification
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-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 10: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
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Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
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-Section 50
-Paragraph 2
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-2

+ Details

Debt and Credit Agreements - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2025 USD ($)
Debt Disclosure [Abstract]
2026	$ 92
2027	666
2028	828
2029	157
2030	99
2031 and thereafter	5,561
Total	$ 7,403

- Definition

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

+ References

+ Details

Retirement Benefits - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2025 USD ($)
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
2026	$ 595
2027	580
2028	598
2029	590
2030	590
2031 through 2035	2,848
Total estimated future benefits payments through 2035	5,801
OPEB
Defined Contribution Plan Disclosure [Line Items]
2026	125
2027	127
2028	127
2029	127
2030	126
2031 through 2035	608
Total estimated future benefits payments through 2035	$ 1,240

Jointly-Owned Electric Plants (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
STP
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	44.00%
Constellation South Texas LLP
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Sale of equity ownership	2.00%
Nuclear Plant \| NMP Unit 2
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	82.00%
Plant in service	$ 1,119	$ 1,122
Accumulated depreciation	363	327
CWIP	$ 53	27
Nuclear Plant \| Quad Cities
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	75.00%
Plant in service	$ 1,324	1,294
Accumulated depreciation	852	840
CWIP	$ 29	13
Nuclear Plant \| Peach Bottom
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	50.00%
Plant in service	$ 1,590	1,570
Accumulated depreciation	752	721
CWIP	$ 25	15
Nuclear Plant \| STP
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	44.00%
Plant in service	$ 1,064	1,040
Accumulated depreciation	98	52
CWIP	$ 23	25
Nuclear Plant \| Salem
Schedule Of Jointly Owned Utility Plant Net Ownership [Abstract]
Ownership interest	42.59%
Plant in service	$ 842	791
Accumulated depreciation	402	387
CWIP	$ 101	$ 68

Commitments and Contingencies - Schedule of Commercial Commitments (Details) $ in Millions	Dec. 31, 2025 USD ($)
Guarantor Obligations [Line Items]
2026	$ 2,387
2027	190
2028	336
2029	0
2030	1
2031 and beyond	3
Total	2,917
Letters of credit
Guarantor Obligations [Line Items]
2026	1,784
2027	190
2028	122
2029	0
2030	1
2031 and beyond	3
Total	2,100
Surety bonds
Guarantor Obligations [Line Items]
2026	603
2027	0
2028	214
2029	0
2030	0
2031 and beyond	0
Total	$ 817

Consolidated Statements of Changes in Equity, Parent (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Statement of Stockholders' Equity [Abstract]
Common stock dividends (in dollars per share)	$ 0.3878	$ 0.3525	$ 0.2820

Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Other Commitments

Commercial commitments as of December 31, 2025, representing commitments potentially triggered by future events, were as follows:


	Expiration within
	2026		2027		2028		2029		2030		2031 and beyond		Total
Letters of credit	$	1,784	$	190	$	122	$	—	$	1	$	3	$	2,100
Surety bonds(a)	603		—		214		—		—		—		817
Total commercial commitments	$	2,387	$	190	$	336	$	—	$	1	$	3	$	2,917

__________

(a)Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Schedule of Government Settlement Agreements

As of December 31, 2025 and 2024, the amount of SNF storage costs for

which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2025		December 31, 2024
DOE receivable - current(a)	$	117	$	124
DOE receivable - noncurrent(b)	28		42
Amounts owed to co-owners(c)	(20)		(40)

__________

(a)Recorded in Accounts receivable, net.

(b)Recorded in Other deferred debits and other assets.

(c)Recorded primarily in Accounts payable and accrued expenses and Accounts receivable, net. Represents amounts owed to the co-owners of Peach Bottom, Quad Cities, and NMP Unit 2 generating facilities

Spent Nuclear Fuel Obligation

The below table outlines the SNF liability, which is recorded within Other deferred credits and other liabilities, as of December 31, 2025 and 2024:


	December 31, 2025		December 31, 2024
Former ComEd units(a)	$	1,271	$	1,219
Fitzpatrick(b)	155		147
Total SNF Obligation	$	1,426	$	1,366

__________

(a)ComEd previously elected to defer payment of the one-time fee of $277 million for its units that began operations before April 7, 1983, with interest to the date of payment, until just prior to the first delivery of SNF to the DOE. The unfunded liabilities for SNF disposal costs, including the one-time fee, were transferred to us as part of Exelon’s 2001 corporate restructuring. See Note 10 — Asset Retirement Obligations for additional detail on Zion Station’s SNF obligation which is included in the table above.

(b)A prior owner of FitzPatrick elected to defer payment of the one-time fee of $34 million, with interest to the date of payment, for the FitzPatrick unit. As part of the FitzPatrick acquisition on March 31, 2017, we assumed a SNF liability for the DOE one-time fee obligation with interest related to FitzPatrick along with an offsetting asset, included in Other deferred debits and other assets, for the contractual right to reimbursement from NYPA, a prior owner of FitzPatrick, for amounts paid for the FitzPatrick DOE one-time fee obligation.

Fair Value of Financial Assets and Liabilities - Fair Value Inputs Assets Quantitative Information (Details) - Level 3 $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Mark-to-market derivatives—Economic hedges	$ (232)	$ (137)
Cash collateral posted (received)	$ 372	$ 136
Minimum \| Discounted Cash Flow \| Forward power price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	1.89	2.57
Minimum \| Discounted Cash Flow \| Forward gas price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	(0.46)	2.09
Minimum \| Option Model \| Volatility percentage
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	0.14	0.23
Maximum \| Discounted Cash Flow \| Forward power price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	154	140
Maximum \| Discounted Cash Flow \| Forward gas price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	15	15
Maximum \| Option Model \| Volatility percentage
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	1.97	1.41
Arithmetic Average \| Discounted Cash Flow \| Forward power price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	52	49
Arithmetic Average \| Discounted Cash Flow \| Forward gas price
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	3.52	3.68
Arithmetic Average \| Option Model \| Volatility percentage
Fair Value Measurement Inputs and Valuation Techniques [Abstract]
Unobservable Input	0.59	0.57

Segment Information

12 Months Ended

Dec. 31, 2025

Segment Reporting [Abstract]

Segment Information

Operating segments are determined based on information used by the CODM in deciding how to evaluate performance and allocate resources. We have five reportable segments consisting of the Mid-Atlantic, Midwest, New York, ERCOT, and all other power regions referred to collectively as “Other Power Regions.”

The basis for our reportable segments is the integrated management of our electricity business that is located in different geographic regions, and largely representative of the footprints of ISO/RTO and/or NERC regions, which utilize multiple supply sources to provide electricity through various distribution channels (wholesale and retail). Our hedging strategies and risk metrics are also aligned to these same geographic regions. Descriptions of each of our five reportable segments are as follows:

•Mid-Atlantic represents operations in the eastern half of PJM, which includes New Jersey, Maryland, Virginia, West Virginia, Delaware, the District of Columbia, and parts of Pennsylvania and North Carolina.

•Midwest represents operations in the western half of PJM and the United States footprint of MISO, excluding MISO’s Southern Region.

•New York represents operations within NYISO.

•ERCOT represents operations within Electric Reliability Council of Texas that covers a majority of the state of Texas.

•Other Power Regions:

•New England represents operations within ISO-NE.

•South represents operations in FRCC, MISO’s Southern Region, and the remaining portions of SERC not included within MISO or PJM.

•West represents operations in WECC, which includes CAISO.

•Canada represents operations across the entire country of Canada and includes AESO, OIESO, and the Canadian portion of MISO.

Constellation's CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations or deemed more useful than the GAAP information provided elsewhere in this report. In our evaluation of operating segments, we noted the CODM reviews a variety of performance and profitability measures at a consolidated level with a primary focus on RNF reporting at the regional level. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the significant segment expense. Purchased power costs include all costs associated with the procurement and supply of electricity including capacity, energy, and ancillary services. Fuel expense includes the fuel costs for our owned generation and fuel costs associated with tolling agreements. The results of our other business activities are not regularly reviewed by the CODM and are therefore not classified as operating segments or included in the regional reportable segment amounts. These activities include wholesale and retail sales of natural gas, energy-related sales in the United Kingdom, as well as sales of other energy-related products and sustainable solutions that are not significant to our overall results of operations. Further, our unrealized gains and losses on economic hedging activities and our amortization of certain intangible assets and liabilities relating to commodity contracts recorded at fair value from mergers and acquisitions are also excluded from the regional reportable segment amounts. The CODM does not use a measure of total assets in making decisions regarding allocating resources to or assessing the performance of these reportable segments.


2025	Revenues from contracts with customers		Other revenues(a)		Total Operating revenues		Total Purchased power and fuel expenses		Total RNF
Mid-Atlantic	$	6,461	$	26	$	6,487	$	(3,076)	$	3,411
Midwest	5,288		516		5,804		(2,102)		3,702
New York	2,389		(199)		2,190		(590)		1,600
ERCOT	1,296		608		1,904		(767)		1,137

Other Power Regions	4,865		718		5,583		(4,764)		819
Total Reportable Segments	20,299		1,669		21,968		(11,299)		10,669
Other(b)	2,364		1,201		3,565		(3,382)		183
Total Consolidated Results	$	22,663	$	2,870	$	25,533	$	(14,681)	$	10,852

2024
Mid-Atlantic	$	5,429	$	93	$	5,522	$	(2,442)	$	3,080
Midwest	3,848		957		4,805		(1,603)		3,202
New York	1,937		113		2,050		(597)		1,453
ERCOT	1,053		497		1,550		(503)		1,047

Other Power Regions	4,749		757		5,506		(4,238)		1,268
Total Reportable Segments	17,016		2,417		19,433		(9,383)		10,050
Other(b)	1,948		2,187		4,135		(2,036)		2,099
Total Consolidated Results	$	18,964	$	4,604	$	23,568	$	(11,419)	$	12,149


2023
Mid-Atlantic	$	5,453	$	(315)	$	5,138	$	(2,214)	$	2,924
Midwest	4,846		(188)		4,658		(1,403)		3,255
New York	1,910		111		2,021		(770)		1,251
ERCOT	1,232		114		1,346		(764)		582

Other Power Regions	4,956		895		5,851		(4,611)		1,240
Total Reportable Segments	18,397		617		19,014		(9,762)		9,252
Other(b)	2,444		3,460		5,904		(6,239)		(335)
Total Consolidated Results	$	20,841	$	4,077	$	24,918	$	(16,001)	$	8,917

__________

(a)Includes revenues from nuclear PTCs beginning in 2024 as well as derivatives and leases. Intersegment activity in all periods presented is not material.

- 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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+ Details

Consolidated Statements of Cash Flows, Parent - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Cash flows from operating activities
Net income (loss)	$ 2,323	$ 3,738	$ 1,577
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and energy contract amortization	2,601	2,700	2,514
Deferred income taxes and amortization of ITCs	273	222	251
Net fair value changes related to derivatives	645	(1,297)	996
Net realized and unrealized (gains) losses on NDT funds	(708)	(311)	(476)
Net realized and unrealized (gains) losses on equity investments	279	(11)	(307)
Other non-cash operating activities	(223)	(172)	18
Changes in assets and liabilities:
Accounts receivable	(363)	688	396
Inventories	(134)	(99)	60
Accounts payable and accrued expenses	316	1,121	(1,330)
Option premiums received (paid), net	38	216	26
Collateral received (posted), net	(773)	1,803	(1,491)
Income taxes	625	296	325
Pension and non-pension postretirement benefit contributions	(211)	(184)	(54)
Other assets and liabilities	(451)	(11,174)	(7,806)
Net cash flows provided by (used in) operating activities	4,237	(2,464)	(5,301)
Cash flows from investing activities
Capital expenditures	(2,949)	(2,565)	(2,422)
Proceeds from NDT fund sales	6,946	6,005	5,822
Investment in NDT funds	(7,284)	(6,282)	(6,050)
Collection of DPP, net	0	10,217	7,340
Acquisition of business	(14)	(32)	(1,690)
Other investing activities	103	85	31
Net cash flows provided by (used in) investing activities	(3,198)	7,428	3,031
Cash flows from financing activities
Change in short-term borrowings	0	(1,105)	146
Proceeds from short-term borrowings with maturities greater than 90 days	1,650	200	539
Repayments of short-term borrowings with maturities greater than 90 days	0	(739)	(200)
Issuance of long-term debt	0	920	3,195
Retirement of long-term debt	(1,076)	(121)	(168)
Dividends paid on common stock	(486)	(444)	(366)
Repurchases of common stock	(400)	(999)	(992)
Other financing activities	(108)	(1)	42
Net cash flows provided by (used in) financing activities	(420)	(2,289)	2,196
Increase (decrease) in cash, restricted cash, and cash equivalents	619	2,675	(74)
Cash, restricted cash, and cash equivalents at beginning of period	3,129	454	528
Cash, restricted cash, and cash equivalents at end of period	3,748	3,129	454
Supplemental disclosure of non-cash investing and financing activities
Increase (decrease) in DPP	0	9,045	8,097
Increase (decrease) in PP&E related to ARO update	$ 187	$ (1,486)	$ 501

Supplemental Financial Information

12 Months Ended

Dec. 31, 2025

Supplemental Financial Information [Abstract]

Supplemental Financial Information

Supplemental Consolidated Statements of Operations and Comprehensive Income Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income.


	For the Years Ended December 31,
Taxes other than income taxes	2025		2024		2023
Property	$	289	$	285	$	253
Gross receipts(a)	163		134		139
Payroll	161		152		142
Other	9		15		19
Total	$	622	$	586	$	553

__________

(a)Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.


	For the Years Ended December 31,
Other, net	2025		2024		2023
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	672	$	553	$	657
Non-Regulatory Agreement Units	322		266		335
Net unrealized gains (losses) on NDT funds
Regulatory Agreement Units	764		184		397
Non-Regulatory Agreement Units	506		156		259
Regulatory offset to NDT fund-related activities(b)	(1,152)		(592)		(845)
Total Decommissioning-related activities	1,112		567		803
Net unrealized gains (losses) from equity investments(c)	(304)		11		307

Other	128		92		158
Total Other, net	$	936	$	670	$	1,268

__________

(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units.

(c)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.

Supplemental Cash Flow Information

The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows.


		For the Years Ended December 31,
Depreciation, amortization and accretion	Income statement location	2025		2024		2023
PP&E	Depreciation and amortization	$	967	$	1,101	$	1,073
Nuclear fuel	Purchased power and fuel	952		884		787
ARO accretion	Operating and maintenance	647		655		596
Amortization of intangible assets, net(a)	Depreciation and amortization	18		22		23
Amortization of UECs	Operating revenues or Purchased power and fuel	17		38		35
Total depreciation, amortization, and accretion		$	2,601	$	2,700	$	2,514

__________

(a)Primarily related to the amortization of customer relationships and trade names. Excludes UEC amortization, which is shown separately in the table.


	For the Years Ended December 31,
Cash paid during the year	2025		2024		2023
Interest (net of amount capitalized)	$	412	$	375	$	264


	CEG Parent						Constellation
	For the Years Ended December 31,						For the Years Ended December 31,
Other non-cash operating activities	2025		2024		2023		2025		2024		2023
Other decommissioning-related activity(a)	$	(463)	$	(485)	$	(534)	$	(463)	$	(485)	$	(534)
Energy-related options(b)	(103)		32		183		(103)		32		183
Pension and non-pension postretirement benefit costs	152		107		47		152		107		47














Other	191		174		322		110		128		260
Total other non-cash operating activities	$	(223)	$	(172)	$	18	$	(304)	$	(218)	$	(44)

__________

(a)Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units.

(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

The following table provides a reconciliation of cash, restricted cash, and cash equivalents reported in the Consolidated Balance Sheets that sum to the total of the same amounts in the Consolidated Statements of Cash Flows.


December 31, 2025	CEG Parent		Constellation
Cash and cash equivalents	$	3,641	$	3,641
Restricted cash and cash equivalents	107		79

Total cash, restricted cash, and cash equivalents	$	3,748	$	3,720


December 31, 2024
Cash and cash equivalents	$	3,022	$	3,018
Restricted cash and cash equivalents	107		97
Total cash, restricted cash, and cash equivalents	$	3,129	$	3,115


December 31, 2023
Cash and cash equivalents	$	368	$	366
Restricted cash and cash equivalents	86		74

Total cash, restricted cash, and cash equivalents	$	454	$	440

For additional information on restricted cash, see Note 1 — Basis of Presentation.

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Consolidated Balance Sheets.


Inventories, net	December 31, 2025		December 31, 2024
Materials and supplies	$	1,485	$	1,357
Natural gas, oil, and emission allowances	251		243
Total	$	1,736	$	1,600


	Accounts payable and accrued expenses
December 31, 2025	CEG Parent		Constellation
Accounts payable	$	2,813	$	2,801
Compensation-related accruals(a)	920		672
Taxes accrued(b)	246		245
Other accrued expenses	315		315
Total	$	4,294	$	4,033


December 31, 2024
Accounts payable	$	2,369	$	2,348
Compensation-related accruals(a)	907		689
Taxes accrued(b)	232		223
Other accrued expenses	435		436
Total	$	3,943	$	3,696

__________

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

(b)Net of $375 million and $150 million as of December 31, 2025 and 2024, respectively, related to nuclear PTC that was used to offset the current tax liability. See Note 6 — Government Assistance for additional information on the nuclear PTC.

The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets.


Investments	December 31, 2025		December 31, 2024
Equity method investments	$	3	$	2
Other investments:
Employee benefit trusts and investments(a)	112		100
Equity investments with readily determinable fair values(b)	82		387
Equity investments without readily determinable fair values	109		150
Other available for sale debt security investments	1		1
Total	$	307	$	640

__________

(a)Debt and equity security investments are recorded at fair market value.

(b)Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.

Basis of Presentation	12 Months Ended
Basis of Presentation	Dec. 31, 2025
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation Description of Business We are the nation's largest producer of clean energy and a leading supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. Basis of Presentation Constellation Energy Corporation (“CEG Parent” or the “Company”), a Pennsylvania corporation, was formed for the purpose of separation of Constellation Energy Generation, LLC (“Constellation”, formerly Exelon Generation Company, LLC) and its subsidiaries from its predecessor parent company, Exelon Corporation (“Exelon”), into an independent, publicly traded company. On February 1, 2022, the separation was completed by distributing all the outstanding shares of the Company’s common stock, on a pro rata basis to the holders of its predecessor’s common stock, with the Company holding all the interests in Constellation previously held by Exelon (the “Separation”). Constellation has been an individual registrant since 2002 with the registration of its public debt securities under the Securities Act. Prior to the Separation, Constellation historically filed consolidated financial statements as an individual registrant to reflect its financial position and operating results as a stand-alone, wholly owned subsidiary of Exelon. The accompanying Consolidated Financial Statements have been prepared in accordance with GAAP for annual financial statements and in accordance with the instructions to Form 10-K and Regulation S-X promulgated by the SEC. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated. Certain prior period amounts have been reclassified to conform to the presentation in the current period. Amounts disclosed relate to CEG Parent and Constellation unless specifically noted as relating to CEG Parent only. Unless otherwise indicated or the context otherwise requires, references herein to the terms “we,” “us,” and “our” refer collectively to CEG Parent and Constellation. We own 100% of our significant consolidated subsidiaries, either directly or indirectly, except for certain consolidated VIEs. The remaining interests in the consolidated VIEs are included in noncontrolling interests in the Consolidated Balance Sheets. See Note 21 — Variable Interest Entities for additional information on consolidated VIEs. We consolidate the accounts of entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Where we do not have a controlling financial interest in an entity, proportionate consolidation, equity method accounting or accounting for investments in equity securities with or without readily determinable fair value is applied. We proportionately consolidate our undivided ownership interest in jointly-owned electric plants. Under proportionate consolidation, we separately record our proportionate share of the assets, liabilities, revenues and expenses related to the undivided interest in the asset. See Note 9 — Jointly-Owned Electric Plants for additional information on the application of proportionate consolidation. We apply equity method accounting when we have a significant influence over an investee through an ownership in equity, which generally approximates to a 20% to 50% voting interest. We apply equity method accounting to certain investments and joint ventures. Under equity method accounting, we report our interest in the entity as an investment and our percentage share of the earnings from the entity as single line items in our consolidated financial statements. We use accounting for investments in equity securities with or without readily determinable fair values if we lack significant influence, which generally results when we hold less than 20% of the common stock of an entity. Under accounting for investments in equity securities with readily determinable fair values, the investments are reported based on quoted prices in active markets and realized and unrealized gains and losses are included in earnings. Under accounting for investments in equity securities without readily determinable fair values, the investments are reported at cost, adjusted for changes from observable transactions for identical or similar investments of the same issuer, less impairment, and changes in measurement are reported in earnings. Use of Estimates The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the amounts reported in the financial statements and accompanying notes. Areas in which significant estimates have been made include, but are not limited to, the accounting for nuclear decommissioning costs and other AROs, pension and OPEB plans, inventory reserves, allowance for credit losses, long-lived asset valuations and impairment assessments, derivative instruments, goodwill, UECs, fixed asset depreciation, environmental costs and other loss contingencies, taxes and unbilled energy revenues. Actual results could differ materially from those estimates. Revenues Operating Revenues. Our operating revenues generally consist of revenues from contracts with customers involving competitive sales of power, natural gas, and other energy-related products and sustainable solutions. We recognize revenue from contracts with customers to depict the transfer of goods or services to customers in an amount that we expect to be entitled to in exchange for those goods or services. At the end of each reporting period, we accrue an estimate for the unbilled amount of power and natural gas delivered or services provided to customers. Commodity Derivatives. Derivative instruments are generally recorded at fair value with subsequent changes in fair value recognized as realized and unrealized revenue or expense. The classification of revenue or expense is based on the intent of the transaction. See Note 15 — Derivative Financial Instruments for additional information. Taxes Directly Imposed on Revenue-Producing Transactions. We collect certain taxes from customers such as sales and gross receipts taxes, along with other taxes, surcharges and fees, that are levied by state or local governments on the sale or distribution of electricity and natural gas and any taxable energy-related products and sustainable solutions. Some of these taxes are imposed on the customer, but paid by us, while others are imposed on us. Where these taxes are imposed on the customer, such as sales taxes, they are reported on a net basis in revenues. However, where these taxes are imposed on us, such as gross receipts taxes, they are reported on a gross basis in revenue and expense in the Consolidated Statements of Operations and Comprehensive Income. Government Assistance. As a result of the enactment of the IRA, we qualify for certain federal government incentives through eligible activities. These incentives include both refundable and transferable tax credits. The current U.S. GAAP framework does not address the receipt of government assistance by for-profit entities. We account for this government assistance by analogy to International Accounting Standard (IAS) 20, Accounting for Government Grants and Disclosure of Government Assistance, and recognize the benefits when there is reasonable assurance that we will comply with the required conditions and that the benefits will be received. We believe the reasonable assurance term as used in IAS 20 is analogous to the term probable as defined under GAAP related to accounting for contingencies. See Note 6 — Government Assistance for additional information. Leases We recognize a ROU asset and lease liability for operating leases with a term of greater than one year. Operating lease ROU assets are included in Other deferred debits and other assets and operating lease liabilities are included in Other current liabilities and Other deferred credits and other liabilities in the Consolidated Balance Sheets. The ROU asset is measured as the sum of (1) the present value of all remaining fixed and in-substance fixed payments using the rate implicit in the lease whenever that is readily determinable or our incremental borrowing rate, (2) any lease payments made at or before the commencement date (less any lease incentives received) and (3) any initial direct costs incurred. The lease liability is measured the same as the ROU asset, but excludes any payments made before the commencement date and initial direct costs incurred. Lease terms include options to extend or terminate the lease if it is reasonably certain they will be exercised. We include non-lease components for most asset classes, which are service-related costs that are not integral to the use of the asset, in the measurement of the ROU asset and lease liability. Expense for operating leases and leases with a term of one year or less is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the derivation of benefit from use of the leased property. Variable lease payments are recognized in the period in which the related obligation is incurred and consist primarily of payments for purchases of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease expense and variable lease payments are recorded to Purchased power and fuel expense for contracted generation or Operating and maintenance expense for all other lease agreements in the Consolidated Statements of Operations and Comprehensive Income. Income from operating leases, including subleases, is recognized on a straight-line basis over the term of the lease, unless another systematic and rational basis is more representative of the pattern in which income is earned over the term of the lease. Variable lease payments are recognized in the period in which the related obligation is performed and consist primarily of payments received from sales of electricity under contracted generation that are based on the electricity produced by those generating assets. Operating lease income and variable lease payments are recorded to Operating revenues in the Consolidated Statements of Operations and Comprehensive Income. Our operating leases consist primarily of contracted generation, real estate including office buildings, and vehicles and equipment. We generally account for contracted generation in which the generating asset is not renewable as a lease if the customer has dispatch rights and obtains substantially all the economic benefits. We generally do not account for contracted generation in which the generating asset is renewable as a lease if the customer does not design the generating asset. We account for land right arrangements that provide for exclusive use as leases while shared use land arrangements are generally not leases. See Note 11 — Leases for additional information. Income Taxes Deferred federal and state income taxes are recorded on temporary differences between the book and tax basis of assets and liabilities and for tax benefits carried forward. ITCs have been deferred in the Consolidated Balance Sheets and are recognized in book income over the life of the related property. We account for uncertain income tax positions using a benefit recognition model with a two-step approach; a more-likely-than-not recognition criterion and a measurement approach that measures the position as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. If it is not more likely than not that the benefit of the tax position will be sustained on its technical merits, no benefit is recorded. Uncertain tax positions that relate only to timing of when an item is included on a tax return are considered to have met the recognition threshold. We recognize accrued interest related to unrecognized tax benefits in Interest expense, net or Other, net (interest income) and recognize penalties related to unrecognized tax benefits in Other, net in the Consolidated Statements of Operations and Comprehensive Income. Cash and Cash Equivalents We consider investments purchased with an original maturity of three months or less to be cash equivalents. Restricted Cash and Cash Equivalents Restricted cash and cash equivalents represent funds that are restricted to satisfy designated current liabilities. As of December 31, 2025 and 2024, restricted cash and cash equivalents primarily represented the payment of medical, dental, vision, and long-term disability benefits and project-specific nonrecourse financing structures for debt service and financing of operations of the underlying entities. See Note 16 — Debt and Credit Agreements and Note 22 — Supplemental Financial Information for additional information. Allowance for Credit Losses on Accounts Receivables The allowance for credit losses reflects our best estimate of losses on the customers' accounts receivable balances based on historical experience and current information. The allowance for credit losses for our retail and wholesale customers is based on accounts receivable aging historical experience coupled with specific identification through a credit monitoring process, which considers current conditions such as industry trends, macroeconomic factors, changes in the regulatory environment, external credit ratings, publicly available news, payment status, payment history, and the exercise of collateral calls. When a wholesale customer’s risk characteristics are no longer aligned with the pooled population, we use specific identification to develop an allowance for credit losses. Adjustments to the allowance for credit losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. We have certain non-customer receivables in Current Assets and Other deferred debits and other assets which primarily are with governmental agencies. The allowance for credit losses related to these receivables is not material. We monitor these balances and will record an allowance if there are indicators of a decline in credit quality. Variable Interest Entities We account for our investments in and arrangements with VIEs based on the following specific requirements: •qualitative assessment of factors determinant in whether we have a controlling financial interest, •ongoing reconsideration of this assessment, and •where we consolidate a VIE (as primary beneficiary), disclosure of (1) the assets of the consolidated VIE, if they can be used to only settle specific obligations of the consolidated VIE, and (2) the liabilities of a consolidated VIE for which creditors do not have recourse to the general credit of the primary beneficiary. See Note 21 — Variable Interest Entities for additional information. Inventories Inventory is recorded at the lower of weighted average cost or net realizable value. Reserves are recorded for excess and obsolete inventory. Natural gas, oil, and emission allowances are generally included in Inventory when delivered and are expensed to Purchased power and fuel expense when consumed. Materials and supplies are generally included in Inventory when delivered and are expensed to Operating and maintenance, or capitalized to Property, plant and equipment, as appropriate, when installed or used. Debt and Equity Security Investments Debt and Equity Investments within NDT funds. We have debt and equity securities held in our NDT funds which are measured and recorded at fair value. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Regulatory Agreement Units are offset in Noncurrent payables related to Regulatory Agreement Units. Realized and unrealized gains and losses, net of trust-level taxes, on our NDT funds associated with the Non-Regulatory Agreement Units are included in Other, net in the Consolidated Statements of Operations and Comprehensive Income. For equity securities without readily determinable fair values, we have elected to use the NAV for qualifying investments as a practical expedient to determine the fair values. Our NDT funds are classified as current or noncurrent assets, depending on the timing of the decommissioning activities and expected payment of income taxes on trust earnings. See Note 10 — Asset Retirement Obligations and Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Equity Security Investments. We hold equity securities both with and without readily determinable fair values. For those with readily determinable fair values, realized and unrealized gains and losses are recognized in Other, net within the Consolidated Statements of Operations and Comprehensive Income. For those without readily determinable fair values, we have elected the measurement alternative, which records investments at cost adjusted for observable transactions involving identical or similar investments of the same issuer, less impairment. Changes in measurement under this alternative are also reported in Other, net within the Consolidated Statements of Operations and Comprehensive Income. Investments in equity securities without readily determinable fair values are qualitatively assessed for impairment each reporting period. If it is determined that the equity security is impaired, an impairment loss will be recognized in Other, net in the Consolidated Statements of Operations and Comprehensive Income in the amount by which the security’s carrying amount exceeds its fair value. See Note 17 — Fair Value of Financial Assets and Liabilities for additional information. Property, Plant and Equipment Property, plant and equipment is recorded at acquired cost. Acquired cost includes construction-related direct labor and material costs. When appropriate, acquired cost also includes capitalized interest. Costs associated with outages and planned major maintenance activities are expensed to Operating and maintenance expense or capitalized to Property, plant, and equipment based on the nature of the activities in the period incurred. The cost of repairs and maintenance and minor replacements of property are charged to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income as incurred. Upon retirement, the cost of property is generally charged to accumulated depreciation in accordance with the composite and group methods of depreciation. Upon replacement of an asset, the costs to remove the asset, net of salvage, are capitalized to gross plant when incurred as part of the cost of the newly installed asset and recorded to depreciation expense over the life of the new asset. Removal costs, net of salvage, incurred for property that will not be replaced is charged to Operating and maintenance expense as incurred. Certain assets follow the unitary method of depreciation and recognize gains and losses in the period of replacement or retirement. These gains and losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Capitalized Software. Certain costs, such as design, coding, and testing incurred during the application development stage of software projects that are internally developed or purchased for operational use are capitalized in Property, plant and equipment in the Consolidated Balance Sheets. Similar costs incurred for cloud-based solutions treated as service arrangements are capitalized in Other current assets and Deferred debits and other assets in the Consolidated Balance Sheets. Such capitalized amounts are amortized ratably over the expected lives of the projects when they become operational, generally not to exceed five years. Capitalized Interest. During construction, we capitalize the costs of debt funds. Most projects will use a debt rate calculated using the general corporate debt pool. In some cases, projects are specifically financed and use a project-specific debt rate, which is excluded from the general corporate debt pool. Capitalization of debt funds is recorded as a charge to construction work in progress and as a non-cash credit to interest expense. See Note 8 — Property, Plant, and Equipment, Note 9 — Jointly-Owned Electric Plants and Note 22 — Supplemental Financial Information for additional information. Nuclear Fuel The cost of nuclear fuel is capitalized in Property, plant and equipment and charged to Purchased power and fuel using the unit-of-production method. Any potential future SNF disposal fees will also be expensed through Purchased power and fuel expense. Additionally, certain on-site SNF storage costs are being reimbursed by the DOE since a DOE (or government-owned) long-term storage facility has not been completed. See Note 18 — Commitments and Contingencies for additional information regarding the cost of SNF storage and disposal. Depreciation and Amortization Except for the amortization of nuclear fuel, depreciation, inclusive of ARC, is generally recorded over the estimated useful lives of property, plant and equipment on a straight-line basis using the group, composite or unitary methods of depreciation. Two methods of depreciating multiple asset groups exist: the group method and the composite method. The group method is typically for groups of assets that are largely homogenous and have approximately the same useful lives. The composite method is used when the assets are heterogeneous and have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimated useful lives are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected future energy market conditions. See Note 8 — Property, Plant, and Equipment for additional information regarding depreciation, and Note 22 — Supplemental Financial Information for additional information regarding amortization expense of nuclear fuel. Asset Retirement Obligations We estimate and recognize a liability for our legal obligation to perform asset retirement activities even though the timing and/or methods of settlement may be conditional on future events. We generally update our nuclear decommissioning AROs annually, unless circumstances warrant more frequent updates, based on our annual evaluation of cost escalation factors and probabilities assigned to the multiple outcome scenarios within our probability-weighted discounted cash flow models. Our multiple outcome scenarios are generally based on decommissioning cost studies which are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. AROs are accreted throughout each year to reflect the time value of money for these present value obligations through a charge to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income for Non-Regulatory Agreement Units and through an offsetting decrease in noncurrent payables related to Regulatory Agreement Units. See Note 10 — Asset Retirement Obligations for additional information. Accounting Implications of the Regulatory Agreement Units Based on the requirements of the ICC, PAPUC, and PUCT that dictate our obligations related to the shortfall or excess of NDT funds necessary for decommissioning the former ComEd, former PECO, and STP units, decommissioning-related activities net of applicable taxes, including realized and unrealized gains and losses on the NDT funds, depreciation of the ARC, and accretion of the decommissioning obligation are generally offset in the Consolidated Statements of Operations and Comprehensive Income and are recorded as noncurrent payables within Payables related to Regulatory Agreement Units in the Consolidated Balance Sheets. See Note 10 — Asset Retirement Obligations for additional information. Asset Impairments Long-Lived Assets. We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life. We determine if long-lived assets or asset groups are potentially impaired by comparing the undiscounted expected future cash flows to the carrying value when indicators of impairment exist. When the undiscounted cash flow analysis indicates a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. Impairment losses are recorded in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income. Goodwill. Goodwill represents the excess of the purchase price paid over the estimated fair value of the net assets acquired and liabilities assumed in the acquisition of a business. Goodwill is not amortized, but is tested for impairment at least annually or on an interim basis if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 12 — Intangible Assets for additional information. Equity Method Investments. We regularly monitor and evaluate equity method investments to determine whether they are impaired. An impairment is recorded when the investment has experienced a decline in value that is other-than-temporary in nature. Additionally, if the entity in which we hold an investment recognizes an impairment loss, we would record the proportionate share of that impairment loss and evaluate the investment for an other-than-temporary decline in value. These impairment losses are recorded in Equity in income (losses) of unconsolidated affiliates in the Consolidated Statements of Operations and Comprehensive Income. Derivative Financial Instruments All derivatives are recognized on the balance sheet at their fair value unless they qualify for certain exceptions, including NPNS. For derivatives intended to serve as economic hedges, changes in fair value are recognized in earnings each period. Amounts classified in earnings are included in Operating revenues, Purchased power and fuel, or Interest expense in the Consolidated Statements of Operations and Comprehensive Income based on the activity the transaction is economically hedging. Cash inflows and outflows related to derivative instruments are included as a component of operating, investing, or financing cash flows in the Consolidated Statements of Cash Flows, depending on the nature of each transaction. As part of our customer-facing business, we enter into contracts to buy and sell energy to meet the requirements of our customers. These contracts include short-term and long-term commitments to purchase and sell energy and energy-related products in the energy markets with the intent and ability to deliver or take delivery of the underlying physical commodity. NPNS are contracts where physical delivery is probable, quantities are expected to be used or sold in the normal course of business over a reasonable period and will not be financially settled. Revenues and expenses on derivative contracts that qualify, and are designated, as NPNS are recognized when the underlying physical transaction is completed. While these contracts are considered derivative financial instruments, they are not required to be recorded at fair value. See Note 15 — Derivative Financial Instruments for additional information. Retirement Benefits We sponsor defined benefit pension and OPEB plans as described in Note 14 — Retirement Benefits. The plan obligations and costs of providing benefits under these plans are remeasured annually as of year end. The measurements involve various factors, assumptions, and accounting policy elections. The impact of assumption changes or experiences different from that assumed on pension and OPEB obligations are recognized over time, not immediately in the Consolidated Statements of Operations and Comprehensive Income. For defined benefit pension plans, gains or losses exceeding the greater of 10% of the PBO or the MRV of plan assets are amortized over the expected average remaining service period of plan participants. For OPEB plans, gains or losses exceeding the greater of 10% of the APBO or the MRV of plan assets are amortized over the average future remaining lifetime of the current inactive population. We separately report the pension and OPEB service cost and non-service cost (credit) components of net periodic benefit costs (credits) for all plans in our Consolidated Statements of Operations and Comprehensive Income. The service cost component remains in Operating and maintenance expense and Property, plant, and equipment, net (where criteria for capitalization of direct labor has been met) while the non-service cost (credit) components are included in Other, net, in accordance with single-employer plan accounting. Renewable Energy Certificates/Credits RECs are included in Renewable energy credits in the Consolidated Balance Sheets. Purchased RECs are recorded at cost when delivered and internally generated RECs are recognized at a zero-cost basis when generated. The cost of RECs purchased on a stand-alone basis is based on the transaction price, while the cost of RECs acquired through PPAs represents the relative fair value at contract inception. Generally, revenue for RECs that are sold to a counterparty under a contract that specifically identifies a power plant is recognized at a point in time when the power is produced. This includes both bundled and unbundled REC sales. Otherwise, the revenue is recognized upon physical transfer of the REC to the customer.

Revenue from Contracts with Customers

12 Months Ended

Dec. 31, 2025

Revenue from Contract with Customer [Abstract]

Revenue from Contracts with Customers

We recognize revenue from contracts with customers to depict the transfer of goods or services to customers at an amount that we expect to be entitled to in exchange for those goods or services. Our primary sources of revenue include competitive sales of power, natural gas, and other energy-related products and sustainable solutions. The performance obligations, revenue recognition, and payment terms associated with these sources of revenue are further discussed in the table below. There are no significant financing components for these sources of revenue.

Unless otherwise noted, for each of the significant revenue categories and related performance obligations described below, we have the right to consideration from the customer in an amount that corresponds directly with the value transferred to the customer for the performance completed to date. Therefore, we generally recognize revenue in the amount for which we have the right to invoice the customer. As a result, there are generally no significant judgments used in determining or allocating the transaction price.

Revenue Source

Description

Performance Obligation

Timing of Revenue Recognition

Payment Terms

Power Sales

Sales of power and other energy-related products to wholesale and retail customers through our customer-facing business

Various, including the delivery of power (generally delivered over time) and other energy-related products such as capacity (generally delivered over time), CMCs, ZECs, RECs or other ancillary services (generally delivered at a point in time)

Concurrently as power is generated for bundled power sale contracts (a)

Generally within the month following delivery to the customer

Natural Gas Sales

Sales of natural gas to wholesale and retail customers through our customer-facing business

Various, including the delivery of natural gas (generally delivered overtime) and sustainable natural gas attributes (generally delivered at a point in time)

Over time as the natural gas is delivered to the customer

Generally within the month following delivery to the customer

Other Products and Services

Sales of other energy-related products and sustainable solutions, such as long-term construction and installation of energy efficiency assets and new power generating facilities, primarily to C&I customers

Construction and/or installation of the asset for the customer

Revenues and associated costs are recognized throughout the contract term using an input method to measure progress towards completion(b)

Generally within 30 or 45 days from the invoice date

__________

(a)Certain contracts may contain limits on the total amount of revenue we are able to collect over the entire term of the contract. In such cases, we estimate the total consideration expected to be received over the term of the contract net of the constraint and allocate the expected consideration to the performance obligations in the contract such that revenue is recognized ratably over the term of the entire contract as the performance obligations are satisfied.

(b)The method recognizes revenue based on the various inputs used to satisfy the performance obligation, such as costs incurred and total labor hours expended. The total amount of revenue that will be recognized is based on the agreed upon contractually-stated amount. The average contract term for these projects is approximately 18 months.

We incur incremental costs in order to execute certain retail power and gas sales contracts. These costs, which primarily relate to retail broker fees and sales commissions, are capitalized when incurred as contract acquisition costs and generally amortized over the corresponding term of the contract. These capitalized costs and related amortization were not material as of and for the years ended December 31, 2025 and 2024.

Transaction Price Allocated to Remaining Performance Obligations


	2026		2027		2028		2029		2030		2031 and thereafter		Total
Remaining performance obligations	$	386	$	269	$	135	$	117	$	61	$	79	$	1,047

Transaction Price Allocated to Previously Satisfied Performance Obligations

Our Clinton and Quad Cities units contract with certain utilities in Illinois which require delivery of all ZECs produced during each planning year (June through May), with total compensation limited by an annual cap for each planning year designed to limit the cost of ZECs to each utility's customers. ZECs delivered that, if paid, would result in the annual cap being exceeded may be paid in subsequent years at the vintage year price as long as the payments would not exceed the annual cap in the year paid. The program commenced June 2017 and continues through May 2027. In various planning years since the program began, we delivered ZECs to the utilities in excess of the annual compensation cap.

The ZEC price and annual compensation cap effective for each planning year are administratively determined by the IPA. For the June 2025 through May 2026 planning year, the ZEC price has been established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year will not exceed the annual cap and, as a result, we recognized $201 million of revenue during the second quarter of 2025 as a receivable for ZECs delivered in prior planning years, with payment expected in the third quarter of 2026. As of December 31, 2025, this receivable is included within Accounts receivable, net in the Consolidated Balance Sheets.

For the June 2024 through May 2025 planning year, the ZEC price was established at $9.38 per ZEC, subject to an annual cap of $222 million. ZECs generated and delivered during this planning year did not exceed the annual cap, however the revenue recognized during the second quarter of 2024 for ZECs delivered in prior planning years was not material.

For the June 2023 through May 2024 planning year, the ZEC price was established at $0.30 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during the planning year did not exceed the annual cap, and as a result we recognized $218 million of revenue during the second quarter of 2023, with payment received in the third quarter of 2024.

Revenue Disaggregation

We disaggregate the revenue recognized from contracts with customers into categories that depict how the nature, amount, timing, and uncertainty of revenue and cash flows are affected by economic factors. See Note 5 — Segment Information for the presentation of revenue disaggregation.

- 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
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-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

Fair Value of Financial Assets and Liabilities

12 Months Ended

Dec. 31, 2025

Fair Value Disclosures [Abstract]

Fair Value of Financial Assets and Liabilities

We measure and classify fair value measurements in accordance with the hierarchy as defined by GAAP. The hierarchy prioritizes the inputs to valuation techniques used to measure fair value into three levels as follows:

•Level 1 — quoted prices (unadjusted) in active markets for identical assets or liabilities that we have the ability to liquidate as of the reporting date

•Level 2 — inputs other than quoted prices included within Level 1 that are directly observable for the asset or liability or indirectly observable through corroboration with observable market data

•Level 3 — unobservable inputs, such as internally developed pricing models or third-party valuations for the asset or liability due to little or no market activity for the asset or liability

Fair Value of Financial Liabilities Recorded at Amortized Cost

The following table presents the carrying amounts and fair values of our long-term debt and the SNF obligation as of December 31, 2025 and 2024. We have no financial liabilities classified as Level 1. The carrying amounts of the short-term liabilities as presented in the Consolidated Balance Sheets are representative of their fair value (Level 2) because of the short-term nature of these instruments.


	December 31, 2025								December 31, 2024
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	7,342	$	6,995	$	666	$	7,661	$	8,412	$	7,805	$	716	$	8,521
SNF Obligation(a)	1,426		1,406		—		1,406		1,366		1,278		—		1,278

__________

(a)SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets.

We use the following methods and assumptions to estimate fair value of our financial liabilities recorded at carrying cost:


Type	Level	Valuation
Long-Term Debt, including amounts due within one year
Taxable Debt Securities	2	The fair value is determined by a valuation model that is based on a conventional discounted cash flow methodology and utilizes assumptions of current market pricing curves. We obtain credit spreads based on trades of our existing debt securities as well as other issuers in the utility sector with similar credit ratings. The yields are then converted into discount rates of various tenors that are used for discounting the respective cash flows of the same tenor for each bond or note.
Variable Rate Financing Debt	2	Debt rates are reset on a regular basis and the carrying value approximates fair value.
Government-Backed Fixed Rate Project Financing Debt	3	The fair value is similar to the process for taxable debt securities. Due to the lack of market trading data on similar debt, the discount rates are derived based on the original loan interest rate spread to the applicable U.S. Treasury rate as well as a current market curve derived from government-backed securities.
Non-Government-Backed Fixed Rate Nonrecourse Debt	3	Fair value is based on market and quoted prices for its own and other nonrecourse debt with similar risk profiles. Given the low trading volume in the nonrecourse debt market, the price quotes used to determine fair value will reflect certain qualitative factors, such as market conditions, investor demand, new developments that might significantly impact the project cash flows or off-taker credit, and other circumstances related to the project.
SNF Obligation
SNF Obligation	2	The carrying amount is derived from a contract with the DOE to provide for disposal of SNF from certain of our nuclear generating stations. See Note 18 — Commitments and Contingencies for further details. When determining the fair value of the obligation, the future carrying amount of the SNF obligation is calculated by compounding the current book value of the SNF obligation at the 13-week U.S. Treasury rate. The compounded obligation amount is discounted back to present value using our discount rate, which is calculated using the same methodology as described above for the taxable debt securities, and an estimated maturity date of 2040 for the years ended December 31, 2025 and 2024.

Recurring Fair Value Measurements

The following tables present assets and liabilities measured and recorded at fair value in the Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2025 and 2024:


	As of December 31, 2025						As of December 31, 2024
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	42	$	—	$	—	$	42	$	120	$	—	$	—	$	120
NDT fund investments
Cash equivalents(b)	72		165		—		237		187		163		—		350
Equities	6,245		1,426		—		7,671		5,230		1,897		—		7,127






Fixed income	2,201		1,566		395		4,162		2,089		1,462		368		3,919
Private credit	—		—		132		132		—		—		134		134
Assets measured at NAV	—		—		—		7,194		—		—		—		5,791



NDT fund investments subtotal(c)	8,518		3,157		527		19,396		7,506		3,522		502		17,321
Rabbi trust investments	66		45		1		112		58		41		1		100




Investments in equities	87		—		—		87		389		—		—		389
Derivative assets
Economic hedges	1,114		7,449		3,830		12,393		1,278		5,306		2,641		9,225

Effect of netting and allocation of collateral	(889)		(6,853)		(3,256)		(10,998)		(1,097)		(4,790)		(2,123)		(8,010)
Derivative assets subtotal	225		596		574		1,395		181		516		518		1,215

Total assets measured at fair value	8,938		3,798		1,102		21,032		8,254		4,079		1,021		19,145

Liabilities
Derivative liabilities
Economic hedges	(1,148)		(8,021)		(4,062)		(13,231)		(1,222)		(5,462)		(2,778)		(9,462)

Effect of netting and allocation of collateral	1,065		7,657		3,628		12,350		1,180		5,157		2,259		8,596
Derivative liabilities subtotal	(83)		(364)		(434)		(881)		(42)		(305)		(519)		(866)
Deferred compensation obligation	—		(124)		—		(124)		—		(93)		—		(93)
Total liabilities measured at fair value	(83)		(488)		(434)		(1,005)		(42)		(398)		(519)		(959)
Total net assets	$	8,855	$	3,310	$	668	$	20,027	$	8,212	$	3,681	$	502	$	18,186

__________

(a)CEG Parent has $70 million and $130 million of Level 1 cash equivalents as of December 31, 2025 and 2024, respectively. We exclude cash of $3,621 million and $2,924 million, and restricted cash of $57 million and $71 million, as of December 31, 2025 and 2024, respectively. CEG Parent has no additional cash exclusions as of December 31, 2025, and an additional $4 million of cash excluded as of December 31, 2024.

(b)Includes net liabilities of $166 million and $148 million as of December 31, 2025 and 2024, respectively, which consist of receivables related to pending securities sales, interest and dividend receivables, repurchase agreement obligations, and payables related to pending securities purchases. The repurchase agreements are generally short-term in nature with durations generally of 30 days or less.

(c)Includes total NDT derivative assets and liabilities that are not material, which have total notional amounts of $810 million and $1,119 million as of December 31, 2025 and 2024, respectively. The notional principal amounts provide one measure of the transaction volume outstanding as of the periods ended and do not represent the amount of our exposure to credit or market loss.

As of December 31, 2025, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $505 million, $487 million, and $576 million, respectively. These commitments will be funded by our existing NDT funds.

Equity Security Investments without Readily Determinable Fair Values. We hold investments without readily determinable fair values with carrying amounts of $109 million and $150 million as of December 31, 2025 and 2024, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the years ended December 31, 2025 and 2024.

Reconciliation of Level 3 Assets and Liabilities

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025 and 2024:


	For the Year Ended December 31, 2025
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2025	$	502	$	(1)		$	1	$	502
Total realized / unrealized gains (losses)
Included in net income (loss)	9		(326)		(a)	—		(317)
Included in Payables related to Regulatory Agreement Units	19		—			—		19
Change in collateral	—		236			—		236
Purchases	—		84			—		84
Sales	—		(5)			—		(5)
Settlements	(4)		51			—		47
Transfers into Level 3	1		(47)		(b)	—		(46)
Transfers out of Level 3	—		148		(b)	—		148
Balance as of December 31, 2025	$	527	$	140		$	1	$	668
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2025	$	9	$	(56)		$	—	$	(47)


	For the Year Ended December 31, 2024
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2024	$	429	$	869		$	1	$	1,299
Total realized / unrealized gains (losses)
Included in net income (loss)	5		(861)		(a)	—		(856)
Included in Payables related to Regulatory Agreement Units	16		—			—		16
Change in collateral	—		(325)			—		(325)
Purchases	66		61			—		127
Sales	—		(83)			—		(83)
Settlements	(15)		29			—		14
Transfers into Level 3	1		44		(b)	—		45
Transfers out of Level 3	—		265		(b)	—		265
Balance as of December 31, 2024	$	502	$	(1)		$	1	$	502
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024	$	5	$	(126)		$	—	$	(121)

__________

(a)Includes a reduction of ($219) million and ($706) million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2025 and 2024, respectively.

(b)Transfers into and out of Level 3 generally occur when the contract tenor becomes less and more observable, respectively, primarily due to changes in market liquidity or assumptions for certain commodity contracts.

The following table presents the income statement classification of the total realized and unrealized gains (losses) included in income for Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025, 2024, and 2023:


	Operating Revenues						Purchased Power and Fuel						Other, net
	2025		2024		2023		2025		2024		2023		2025		2024		2023
Total gains (losses) included in net income	$	(340)	$	(539)	$	706	$	65	$	(293)	$	(503)	$	9	$	5	$	2
Total unrealized gains (losses)	(172)		207		1,673		116		(333)		(479)		9		5		2

Valuation Techniques Used to Determine Fair Value

Cash Equivalents. Investments with original maturities of three months or less when purchased, including mutual and money market funds, are considered cash equivalents. The fair values are based on observable market prices and, therefore, are included in the recurring fair value measurements hierarchy as Level 1.

NDT Fund Investments. The trust fund investments have been established to satisfy our nuclear decommissioning obligations as required by the NRC. The NDT funds hold debt and equity securities directly and indirectly through commingled funds and mutual funds, which are included in equities and fixed income. Our NDT fund investments policies outline investment guidelines for the trusts and limit the trust funds’ exposures to investments in highly illiquid markets and other alternative investments, including private credit, private equity, and real assets. Investments with maturities of three months or less when purchased, including certain short-term fixed income securities are considered cash equivalents and included in the recurring fair value measurements hierarchy as Level 1 or Level 2.

Equities. These investments consist of individually held equity securities, equity mutual funds, and equity commingled funds in domestic and foreign markets. With respect to individually held equity securities, the trustees obtain prices from pricing services, whose prices are generally obtained from direct feeds from market exchanges, which we are able to independently corroborate. Equity securities held individually, including real estate investment trusts, rights, and warrants, are primarily traded on exchanges that contain only actively traded securities due to the volume trading requirements imposed by these exchanges. The equity securities that are held directly by the trust funds are valued based on quoted prices in active markets and categorized as Level 1. Certain equity securities have been categorized as Level 2 because they are based on evaluated prices that reflect observable market information, such as actual trade information or similar securities. Certain private placement equity securities are categorized as Level 3 because they are not publicly traded and are priced using significant unobservable inputs.

Equity commingled funds and mutual funds are maintained by investment companies, and fund investments are held in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For equity commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets on the underlying securities and are not classified within the fair value hierarchy. These investments can typically be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Fixed income. For fixed income securities, which consist primarily of corporate debt securities, U.S. government securities, foreign government securities, municipal bonds, asset and mortgage-backed securities, commingled funds, mutual funds, and derivative instruments, the trustees obtain multiple prices from pricing vendors whenever possible, which enables cross-provider validations in addition to checks for unusual daily movements. A primary price source is identified based on asset type, class, or issue for each security. With respect to individually held fixed income securities, the trustees monitor prices supplied by pricing services and may use a supplemental price source or change the primary price source of a given security if the portfolio managers challenge an assigned price and the trustees determine that another price source is preferable. We have obtained an understanding of how these prices are derived, including the nature and observability of the inputs used in deriving such prices. Additionally, we selectively corroborate the fair values of securities by comparison to other market-based price sources. Investments in U.S. Treasury securities have been categorized as Level 1 because they trade in highly-liquid and transparent markets. Certain private placement fixed income securities

have been categorized as Level 3 because they are priced using certain significant unobservable inputs and are typically illiquid. The remaining fixed income securities, including certain other fixed income investments, are based on evaluated prices that reflect observable market information, such as actual trade information of similar securities, adjusted for observable differences and are categorized as Level 2. This includes equity investments sold short during the period, which represent liabilities.

Other fixed income investments primarily consist of fixed income commingled funds and mutual funds, which are maintained by investment companies and hold fund investments in accordance with a stated set of fund objectives. The values of some of these funds are publicly quoted. For mutual funds which are publicly quoted, the funds are valued based on quoted prices in active markets and have been categorized as Level 1. For fixed income commingled funds and mutual funds which are not publicly quoted, the fund administrators value the funds using the NAV per fund share, derived from the quoted prices in active markets of the underlying securities and are not classified within the fair value hierarchy. These investments typically can be redeemed monthly or more frequently, with 30 or less days of notice and without further restrictions.

Derivative instruments. These instruments, consisting primarily of futures and swaps to manage risk, are recorded at fair value. Over-the-counter derivatives are valued daily, based on quoted prices in active markets and trade in open markets, and have been categorized as Level 1. Derivative instruments other than over-the-counter derivatives are valued based on external price data of comparable securities and have been categorized as Level 2.

Private credit. Private credit investments primarily consist of investments in private debt strategies. These investments are generally less liquid assets, typically with an underlying term of 3 to 5 years, and are usually intended to be held to maturity. The fair value of these investments is determined by the fund manager or administrator using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. Private credit investments held directly by us are categorized as Level 3 because they are based largely on inputs that are unobservable and utilize complex valuation models. For certain private credit funds, the fair value is determined using a combination of valuation models including cost models, market models, and income models and typically cannot be redeemed until maturity of the term loan. These investments are not classified within the fair value hierarchy because their fair value is determined using NAV or its equivalent as a practical expedient.

Private equity. These investments include those in limited partnerships that invest in operating companies that are not publicly traded on a stock exchange such as leveraged buyouts, growth capital, venture capital, distressed investments, and investments in natural resources. These investments typically cannot be redeemed and are generally liquidated over a period of 8 to 10 years from the initial investment date, which is based on our understanding of the investment funds. Private equity valuations are reported by the fund manager and are based on the valuation of the underlying investments, which include unobservable inputs such as cost, operating results, discounted future cash flows, and market-based comparable data. These valuation inputs are unobservable. The fair value of private equity investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

Real assets. These investments are funds with a direct investment in pools of real estate properties or infrastructure assets. These funds are reported by the fund manager and are generally based on independent appraisals of the underlying investments from sources with professional qualifications, typically using a combination of market-based comparable data and discounted cash flows. These valuation inputs are unobservable. Certain real asset investments cannot be redeemed and are generally liquidated over a period of 8 to 25 years from the initial investment date, which is based on our understanding of the investment funds. The remaining liquid real asset investments are generally redeemable from the investment vehicle quarterly, with 30 to 90 days of notice. The fair value of real asset investments is determined using NAV or its equivalent as a practical expedient, and therefore, these investments are not classified within the fair value hierarchy.

We evaluated our NDT portfolios for the existence of significant concentrations of credit risk as of December 31, 2025. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2025, there were no significant concentrations (generally defined as greater than 10%) of risk in the NDT assets.

See Note 10 — Asset Retirement Obligations for additional information on the NDT fund investments.

Rabbi Trust Investments. The Rabbi trusts were established to hold assets related to deferred compensation plans existing for certain active and retired members of executive management and directors. The Rabbi trusts' assets are included in investments in the Consolidated Balance Sheets and consist primarily of money market funds, mutual funds, and life insurance policies. Money market funds and mutual funds are publicly quoted and have been categorized as Level 1 given the clear observability of the prices. The life insurance policies are valued using the cash surrender value of the policies, net of loans against those policies, which is provided by a third-party. Certain life insurance policies, which consist primarily of mutual funds that are priced based on observable market data, have been categorized as Level 2 because the life insurance policies can be liquidated at the reporting date for the value of the underlying assets.

Deferred Compensation Obligations. Our deferred compensation plans allow participants to defer certain cash compensation into a notional investment account. We include such plans in other current and noncurrent liabilities in the Consolidated Balance Sheets. The value of our deferred compensation obligations is based on the market value of the participants’ notional investment accounts. The underlying notional investments are comprised primarily of equities, mutual funds, commingled funds, and fixed income securities which are based on directly and indirectly observable market prices. Since the deferred compensation obligations themselves are not exchanged in an active market, they are categorized as Level 2 in the fair value hierarchy.

The value of certain employment agreement obligations (which are included with the Deferred compensation obligation in the table above) are based on a known and certain stream of payments to be made over time and are categorized as Level 2 within the fair value hierarchy.

Investments in Equities. We hold certain investments in equity securities with readily determinable fair values in addition to those held within the NDT funds. These equity securities are valued based on quoted prices in active markets and are categorized as Level 1.

Derivatives. Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are categorized in Level 1 in the fair value hierarchy. Certain derivatives’ pricing is verified using indicative price quotations available through brokers, over-the-counter, or exchanges and are categorized in Level 2. These price quotations reflect the average of the bid-ask, mid-point prices and are obtained from sources that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. This includes consideration of actual transaction volumes, market delivery points, bid-ask spreads, and contract duration. The remainder of derivative contracts are valued using the Black model, an industry standard option valuation model. The Black model considers inputs such as contract terms, including maturity, and market parameters, including assumptions of the future prices of energy, interest rates, volatility, credit worthiness, and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, model inputs are generally observable. Such instruments are categorized in Level 2. Our derivatives are predominantly at liquid trading points. For derivatives that trade in less liquid markets with limited pricing information, model inputs generally would include both observable and unobservable inputs. These valuations may include an estimated basis adjustment from an illiquid trading point to a liquid trading point for which active price quotations are available. Such instruments are categorized in Level 3.

For valuations that include both observable and unobservable inputs, if the unobservable input is determined to be significant to the overall inputs, the entire valuation is categorized in Level 3. This includes derivatives valued using indicative price quotations whose contract tenure extends into unobservable periods. In instances where observable data is unavailable, consideration is given to the assumptions that market participants would use in valuing the asset or liability. This includes assumptions about market risks such as liquidity, volatility, and contract duration. Such instruments are categorized in Level 3 as the model inputs generally are not observable. We consider credit and non-performance risk in the valuation of derivative contracts categorized in Level 2 and 3, including both historical and current market data, in our assessment of credit and non-performance risk by counterparty. Due to master netting agreements and collateral posting requirements, the impacts of credit and non-performance risk were not material to the consolidated financial statements.

Disclosed below is detail surrounding our significant Level 3 valuations. The calculated fair value includes marketability discounts for margining provisions and other attributes. The Level 3 balance generally consists of forward sales and purchases of power and natural gas and certain transmission congestion contracts. We utilize various inputs and factors including market data and assumptions that market participants would use in pricing

assets or liabilities as well as assumptions about the risks inherent in the inputs to the valuation technique. The inputs and factors include forward commodity prices, commodity price volatility, contractual volumes, delivery location, interest rates, credit quality of counterparties, and credit enhancements.

For commodity derivatives, the primary input to the valuation models is the forward commodity price curve for each instrument. All locations are reviewed and verified by risk management considering published exchange transaction prices, executed bilateral transactions, broker quotes, and other observable or public data sources. The relevant forward commodity curve used to value each of the derivatives depends on a number of factors, including commodity type, delivery location, and delivery period. Price volatility varies by commodity and location. When appropriate, we discount future cash flows using risk-free interest rates with adjustments to reflect the credit quality of each counterparty for assets and our own credit quality for liabilities. The level of observability of a forward commodity price varies generally due to the delivery location and delivery period. Certain delivery locations including PJM West Hub (for power) and Henry Hub (for natural gas) are more liquid and prices are observable for up to three years in the future. The observability period of volatility is generally shorter than the underlying power curve used in option valuations. The forward curve for a less liquid location is estimated by using the forward curve from the liquid location and applying a spread to represent the cost to transport the commodity to the delivery location. This spread does not typically represent a majority of the instrument’s market price. As a result, the change in fair value is closely tied to liquid market movements and not a change in the applied spread. The change in fair value associated with a change in the spread is generally immaterial. An average spread calculated across all Level 3 power and gas delivery locations is approximately $52.17 and $3.52 for power and natural gas, respectively as of December 31, 2025. Many of the commodity derivatives are short term in nature and thus a majority of the fair value may be based on observable inputs even though the contract as a whole must be classified as Level 3.

See Note 15 — Derivative Financial Instruments for additional information on derivatives.

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of December 31, 2025		Fair Value as of December 31, 2024		Valuation Technique	Unobservable Input	2025 Range & Arithmetic Average		2024 Range & Arithmetic Average
Level 3 Derivatives—Economic hedges(a)(b)	$	(232)	$	(137)	Discounted Cash Flow	Forward power price	$1.89 - $154	$52	$2.57 - $140	$49
						Forward gas price	$(0.46) - $15	$3.52	$2.09 - $15	$3.68
					Option Model	Volatility percentage	14% - 197%	59%	23% - 141%	57%

__________

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on Level 3 positions of $372 million and $136 million as of December 31, 2025 and 2024, respectively.

The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

- 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)
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-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
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-Name Accounting Standards Codification
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-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

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-Name Accounting Standards Codification
-Section 50
-Paragraph 6A
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-6A

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-URI https://asc.fasb.org/1943274/2147482106/820-10-50-6A

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-Topic 820
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-URI https://asc.fasb.org/1943274/2147482106/820-10-50-6A

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-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
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-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482106/820-10-50-2

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-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478119/940-820-50-1

+ Details

Leases - Supplemental Balance Sheet Information (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Supplemental Balance Sheet Information [Line Items]
Operating lease ROU assets	$ 371	$ 436
Other current liabilities	72	72
Other deferred credits and other liabilities	433	511
Operating lease liabilities	$ 505	$ 583
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other	Other
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Long-term Contract for Purchase of Electric Power
Supplemental Balance Sheet Information [Line Items]
Operating lease ROU assets	$ 141	$ 176
Operating lease liabilities	$ 241	$ 289

Intangible Assets

12 Months Ended

Dec. 31, 2025

Goodwill and Intangible Assets Disclosure [Abstract]

Intangible Assets

Goodwill

See Note 1 — Basis of Presentation for our policy regarding goodwill. Our operating segments are also considered reporting units for goodwill impairment assessment purposes.


	2025		2024
Beginning balance as of January 1	$	420	$	425
Goodwill allocated to assets held for sale	—		(5)
Ending balance as of December 31	$	420	$	420

Other Intangible Assets and Liabilities


	December 31, 2025						December 31, 2024
	Gross		Accumulated Amortization		Net		Gross		Accumulated Amortization		Net
UECs	$	1,850	$	(1,686)	$	164	$	1,850	$	(1,669)	$	181
Customer Relationships	174		(137)		37		244		(189)		55

Total	$	2,024	$	(1,823)	$	201	$	2,094	$	(1,858)	$	236

The following table summarizes the amortization expense related to our other intangible assets and liabilities for the years ended December 31, 2025, 2024, and 2023:


	For the Years Ended December 31,
	2025		2024		2023
Amortization expense(a)	$	35	$	60	$	58

__________

(a)See Note 22 — Supplemental Financial Information for additional information on amortization expense.

The following table summarizes the estimated future amortization expense related to our other intangible assets and liabilities as of December 31, 2025:


For the Years Ending December 31,	Estimated Future Amortization Expense
2026	$	41
2027	33
2028	28
2029	20
2030	16
2031 and thereafter	63
Total	$	201

Shareholders' Equity - ASR Agreement (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	1 Months Ended					3 Months Ended			12 Months Ended
	Aug. 31, 2025	Jun. 30, 2025	Jul. 31, 2024	May 31, 2024	Mar. 31, 2024	Aug. 31, 2025	Jul. 31, 2024	May 31, 2024	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Equity, Class of Treasury Stock [Line Items]
Common stock repurchased									$ 404	$ 1,009	$ 1,000
March 2024
Equity, Class of Treasury Stock [Line Items]
Common stock repurchased					$ 354
Common stock repurchased (in shares)				0.2	1.7			1.9
Common stock repurchased, average price (in dollars per share)				$ 182.65
May 2024
Equity, Class of Treasury Stock [Line Items]
Common stock repurchased				$ 505
Common stock repurchased (in shares)			0.6	1.8			2.4
Common stock repurchased, average price (in dollars per share)			$ 211.40
June 2025
Equity, Class of Treasury Stock [Line Items]
Common stock repurchased		$ 404
Common stock repurchased (in shares)	0.2	1.1				1.3
Common stock repurchased, average price (in dollars per share)	$ 311.84

- Definition

Number of shares that have been repurchased during the period and have not been retired and are not held in treasury. Some state laws may govern the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock.

+ References + Details

- Definition

Equity impact of the value of stock that has been repurchased during the period and has not been retired and is not held in treasury. Some state laws may mandate the circumstances under which an entity may acquire its own stock and prescribe the accounting treatment therefore. This element is used when state law does not recognize treasury stock.

+ References + Details

Fair Value of Financial Assets and Liabilities - Fair Value Reconciliation of Level 3 Assets and Liabilities Measured on a Recurring Basis (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 502	$ 1,299
Total realized / unrealized gains (losses)
Included in net income (loss)	(317)	(856)
Included in Payables related to Regulatory Agreement Units	19	16
Change in collateral	236	(325)
Purchases	84	127
Sales	(5)	(83)
Settlements	47	14
Transfers into Level 3	(46)	45
Transfers out of Level 3	148	265
Ending Balance	668	502
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(47)	(121)
NDT Fund Investments
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	502	429
Total realized / unrealized gains (losses)
Included in net income (loss)	9	5
Included in Payables related to Regulatory Agreement Units	19	16
Change in collateral	0	0
Purchases	0	66
Sales	0	0
Settlements	(4)	(15)
Transfers into Level 3	1	1
Transfers out of Level 3	0	0
Ending Balance	527	502
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	9	5
Derivatives
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	(1)	869
Total realized / unrealized gains (losses)
Included in net income (loss)	(326)	(861)
Included in Payables related to Regulatory Agreement Units	0	0
Change in collateral	236	(325)
Purchases	84	61
Sales	(5)	(83)
Settlements	51	29
Transfers into Level 3	(47)	44
Transfers out of Level 3	148	265
Ending Balance	140	(1)
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(56)	(126)
Realized gains (losses)	(219)	(706)
Rabbi Trust Investments
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	1	1
Total realized / unrealized gains (losses)
Included in net income (loss)	0	0
Included in Payables related to Regulatory Agreement Units	0	0
Change in collateral	0	0
Purchases	0	0
Sales	0	0
Settlements	0	0
Transfers into Level 3	0	0
Transfers out of Level 3	0	0
Ending Balance	1	1
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	$ 0	$ 0

Intangible Assets - Summary of Amortization Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Amortization Expense	$ 35	$ 60	$ 58

Shareholders' Equity - Narrative (Details) shares in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2025 USD ($)	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($) shares	Dec. 31, 2023 USD ($)	Feb. 28, 2025 repurchaseAgreement
Accumulated Other Comprehensive Income (Loss) [Line Items]
Common stock repurchased		$ 404	$ 1,009	$ 1,000
Capital Allocation Plan
Accumulated Other Comprehensive Income (Loss) [Line Items]
Value of stock authorized for repurchase				$ 3,000
Remaining repurchase amount		$ 593
Common stock repurchased	$ 150
Percentage of agreement cost		80.00%
Number of Share Repurchase Agreements \| repurchaseAgreement					2
Open Market
Accumulated Other Comprehensive Income (Loss) [Line Items]
Common stock repurchased (in shares) \| shares			1.2
Common stock repurchased			$ 150

- 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

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-URI https://asc.fasb.org/1943274/2147481694/830-30-45-20

+ Details

- Definition

+ References + Details

- Definition

+ References + Details

Shareholders' Equity - Income Taxes Allocated to Other Comprehensive Income (Loss) Components (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Actuarial loss reclassified to periodic benefit cost
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans	$ (24)	$ (24)	$ (10)
Pension and non-pension postretirement benefit plans valuation adjustment
Accumulated Other Comprehensive Income (Loss) [Line Items]
Pension and non-pension postretirement benefit plans	$ 74	$ 59	$ 151

- 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

- Definition

Amount of tax expense (benefit) allocated to other comprehensive income (loss).

+ References

Reference 1: http://fasb.org/us-gaap/role/ref/legacyRef
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+ Details

Debt and Credit Agreements (Tables)

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Schedule of Commercial Paper, Credit Facilities and Borrowing Rates

As of December 31, 2025 and 2024, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


December 31, 2025
Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit(a)		Outstanding Commercial Paper(b)		Total Available Capacity
Revolving Credit Facility	$	4,500	$	—	$	40	$	—	$	4,460
Bilaterals(c)	2,350		—		1,276		—		1,074
Accounts Receivable Facility	1,500		—		—		—		1,500
Liquidity Facility	971		—		647		—		312		(d)
Project Finance	137		—		122		—		15
Total	$	9,458	$	—	$	2,085	$	—	$	7,361

December 31, 2024
Revolving Credit Facility	$	4,500	$	—	$	51	$	—	$	4,449
Bilaterals	1,850		—		1,095		—		755
Accounts Receivable Facility	1,500		—		—		—		1,500
Liquidity Facility	971		—		907		—		21		(d)
Project Finance	137		—		120		—		17
Total	$	8,958	$	—	$	2,173	$	—	$	6,742

__________

(a)Excludes an additional outstanding letter of credit which was not issued under these facilities of $15 million as of December 31, 2025 and 2024. See Note 18 — Commitments and Contingencies for additional information.

(b)Our commercial paper program is supported by the revolving credit agreement. In order to maintain our commercial paper program in the amounts indicated above, we must have a credit facility in place, at least equal to the amount of our commercial paper program. As of December 31, 2025 and 2024, the maximum program size of our commercial paper program was $4.5 billion. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. There were no commercial paper borrowings outstanding as of December 31, 2025 and 2024.

(c)Refer to table below for additional information on our bilateral credit agreements.

(d)The maximum amount of the bank commitment is not to exceed $971 million. The aggregate available capacity of the facility is subject to market fluctuations based on the value of U.S Treasury Securities which determines the amount of collateral held in the trust. We may post additional collateral to borrow up to the maximum bank commitment. As of December 31, 2025 and 2024, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $959 million and $928 million, respectively.

Schedule of Bilateral Credit Agreements

Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2025:

Date Initiated(a)

Latest Amendment Date

Maturity Date(b)

Amount

January 2016

April 2023

April 2026

150

October 2019

N/A

200

November 2019

N/A

300

November 2019

N/A

100

November 2019

June 2024

June 2026

100

May 2020(c)

March 2023

N/A

300

August 2022

N/A

March 2023

March 2025

March 2027

100

December 2023

N/A

200

March 2024(c)

N/A

200

May 2024

N/A

150

January 2025(c)

N/A

200

March 2025

N/A

March 2026

300

2,350

__________

(a)Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.

(b)Credit facilities that do not contain a maturity date are specific to the agreements set within each contract. In some instances, credit facilities are automatically renewed based on the contingency standards set within the specific agreement.

(c)In February 2026, we increased the capacity to issue letters of credit by an additional $100 million each for three existing uncommitted bilateral facilities.

Schedule of Short-Term Borrowings

We had short-term loan agreements outstanding as of December 31, 2025 as reflected in the table below. There were no short-term loan agreements outstanding as of December 31, 2024.

Month Initiated

Interest Rate

Maturity

Weighted Average Interest Rate

Outstanding Amount as of December 31, 2025

May 2025

1-month SOFR + 0.90%

May 2026

5.09

900

September 2025

1-month SOFR + 0.90%

September 2026

4.93

750

Schedule of Long-term Debt Instruments

Long-Term Debt

The following table presents the outstanding long-term debt as of December 31, 2025 and 2024:


			December 31,
	Rates	Maturity Date	2025		2024
Long-term debt
Senior unsecured notes	5.60% - 6.50%	2028 - 2054	$	5,688	$	6,588
Tax-exempt notes	4.10% - 4.45%	2029 - 2053(a)	412		435
Notes payable and other	1.71% - 6.10%	2026 - 2035	53		51
Nonrecourse debt:
Fixed rates	2.29% - 6.00%	2031 - 2037	653		720
Variable rates	5.82% - 6.76%	2027	597		680
Total long-term debt			7,403		8,474
Unamortized debt discount and premium, net			(1)		(4)
Unamortized debt issuance costs			(60)		(58)
Long-term debt due within one year			(92)		(1,028)
Long-term debt			$	7,250	$	7,384

________

(a)The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029.

The terms of the debt issuance under the exchange are as follows:


Note	Interest Rate	Maturity	Issued Amount
2029 Senior Notes	4.625%	February 2029	$	647
2031 Senior Notes	5.000%	February 2031	848
2031 Senior Notes	3.750%	March 2031	795
Total			$	2,290

Senior Note Issuance

In January 2026, we issued senior unsecured notes totaling $2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are as follows:


Note	Interest Rate	Maturity	Issued Amount
2028 Floating Rate Senior Notes	SOFR + 0.600%	January 2028	$	300
2028 Senior Notes	3.900%	January 2028	900
2031 Senior Notes	4.400%	January 2031	750
2066 Senior Notes	5.875%	January 2066	800
Total			$	2,750

Schedule of Maturities of Long-term Debt

Long-term debt maturities in the periods 2026 through 2031 and thereafter are as follows:


2026	$	92
2027	666
2028	828
2029	157
2030	99
2031 and thereafter	5,561
Total	$	7,403

- 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

+ Details

Accounts Receivable (Tables)

12 Months Ended

Dec. 31, 2025

Receivables [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable

The following table provides additional information on the disaggregation of customer and other accounts receivable:


	Accounts receivable, net
December 31, 2025	CEG Parent		Constellation
Customer accounts receivable (net of allowance for credit losses of $158 for CEG Parent and Constellation)	$	3,577	$	3,577
Other accounts receivable (net of allowance for credit losses of $9 for CEG Parent and Constellation)	689		674
Total	$	4,266	$	4,251


December 31, 2024
Customer accounts receivable (net of allowance for credit losses of $190 for CEG Parent and Constellation)	$	3,116	$	3,116
Other accounts receivable (net of allowance for credit losses of $6 for CEG Parent and Constellation)	602		587
Total	$	3,718	$	3,703

Allowance for Credit Losses Rollforward

The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2024 to December 31, 2025:


	2025		2024
Balance as of January 1	$	190	$	56
Current period provision for expected credit losses	47		17
Write-offs, net of recoveries(a)	(79)		(21)
Facility amendment impact(b)	—		138
Balance as of December 31	$	158	$	190

__________

(a)Recoveries were not material.

(b)Impact as a result of the December 2024 amendment of our revolving accounts receivable financing arrangement. See below for details.

Purchases and Sales of Accounts Receivable

The following table summarizes our cash proceeds associated with the Facility prior to the amendment:


	For the Years Ended December 31,
	2024		2023
Proceeds from new transfers(a)	$	1,688	$	3,649
Cash collections received on DPP(b)	10,517		8,140
Cash collections reinvested in the Facility	$	12,205	$	11,789

_________

(a)Customer accounts receivable sold into the Facility were $12,262 million and $11,746 million for the years ended December 31, 2024, and 2023, respectively.

(b)Does not include the $300 million and $800 million net cash payments to the Purchasers in 2024 and 2023, respectively, in order to reduce the outstanding borrowing amount under the Facility.

Insider Trading Arrangements	12 Months Ended
Insider Trading Arrangements	Dec. 31, 2025
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Income Taxes - Narrative (Details) - USD ($)		3 Months Ended	12 Months Ended
Income Taxes - Narrative (Details) - USD ($)	Feb. 19, 2026	Mar. 31, 2026	Dec. 31, 2025	Dec. 31, 2024
Income Taxes [Line Items]
Payments received for tax attributes			$ 145,000,000	$ 174,000,000
Other deferred debits and other assets			2,450,000,000	2,818,000,000
Subsequent Event
Income Taxes [Line Items]
Increase (decrease) in income tax receivable	$ (235,000,000)
Forecast
Income Taxes [Line Items]
Increase (decrease) in income tax receivable		$ 235,000,000
State
Income Taxes [Line Items]
Deferred taxes on state tax attributes (net)			17,000,000
Separation from Parent
Income Taxes [Line Items]
Accounts receivable, net			175,000,000	138,000,000
Other deferred debits and other assets			21,000,000	201,000,000
Separation from Parent \| Other Noncurrent Liabilities \| Affiliated Entities
Income Taxes [Line Items]
Payable for tax liabilities upon separation			$ 43,000,000	$ 39,000,000

Derivative Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2025

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Summary of the Derivative Fair Value

The following tables provide a summary of the commodity derivative fair value balances recorded as of December 31, 2025 and 2024:


December 31, 2025	Economic Hedges		Collateral (a)		Netting(a)		Total
Derivative assets (current)	$	7,349	$	375	$	(6,791)	$	933
Derivative assets (noncurrent)	5,030		272		(4,853)		449
Total derivative assets	12,379		647		(11,644)		1,382
Derivative liabilities (current)	(7,642)		386		6,791		(465)
Derivative liabilities (noncurrent)	(5,585)		319		4,853		(413)
Total derivative liabilities	(13,227)		705		11,644		(878)
Total derivative net assets (liabilities)	$	(848)	$	1,352	$	—	$	504

December 31, 2024
Derivative assets (current)	$	5,518	$	152	$	(4,860)	$	810
Derivative assets (noncurrent)	3,672		120		(3,421)		371
Total derivative assets	9,190		272		(8,281)		1,181
Derivative liabilities (current)	(5,498)		173		4,860		(465)
Derivative liabilities (noncurrent)	(3,961)		141		3,421		(399)
Total derivative liabilities	(9,459)		314		8,281		(864)
Total derivative net assets (liabilities)	$	(269)	$	586	$	—	$	317

_________


(In millions)	As of December 31,
Commodity Type	2025	2024	Unit of Measure
Electricity	(260)	(130)	MWh
Natural Gas	33	33	MMBtu
Emissions	(35)	(18)	Short Ton

Economic Hedges (Commodity Price Risk)


	For the Years Ended December 31,
Income Statement Location	2025		2024		2023
Operating revenues	$	(804)	$	313	$	1,402
Purchased power and fuel	183		963		(2,368)
Total	$	(621)	$	1,276	$	(966)

Disclosure of Credit Derivatives


Rating as of December 31, 2025	Total Exposure Before Credit Collateral		Credit Collateral(a)		Net Exposure		Number of Counterparties Greater than 10% of Net Exposure	Net Exposure of Counterparties Greater than 10% of Net Exposure
Investment grade	$	966	$	10	$	956	1	$	152
Non-investment grade	10		1		9		—	—
No external ratings
Internally rated — investment grade	172		6		166		—	—
Internally rated — non-investment grade	156		23		133		—	—
Total	$	1,304	$	40	$	1,264	1	$	152

__________

(a)As of December 31, 2025, credit collateral held from counterparties was entirely in the form of letters of credit.


Net Credit Exposure by Type of Counterparty	As of December 31, 2025
Investor-owned utilities, marketers, power producers	$	1,052
Energy cooperatives and municipalities	89
Financial Institutions	48
Other	75
Total	$	1,264

Fair Value of Derivatives with Credit- Risk Related Contingent Features


	As of December 31,
Credit-Risk-Related Contingent Features	2025		2024
Gross fair value of derivative contracts containing this feature	$	(1,307)	$	(1,346)
Offsetting fair value of contracts under master netting arrangements	554		602
Net fair value of derivative contracts containing this feature	$	(753)	$	(744)

Cash Collateral and Letters of Credit on Derivative Contracts


	As of December 31,
	2025		2024
Cash collateral posted	$	1,399	$	635
Letters of credit posted	718		890
Cash collateral held	47		49
Letters of credit held	115		91
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(a)(b)(c)	2,670		1,949

_________

(b)The downgrade collateral is inclusive of all contracts in a liability position regardless of accounting treatment and excludes any contracts with individual retail counterparties.

(c)A loss of investment grade credit rating would require a three-notch downgrade from current levels of BBB+ and Baa1 at S&P and Moody's, respectively.

- Definition

Tabular disclosure of credit derivatives which includes information by sellers of credit derivatives, about each credit derivative, or each group of similar credit derivatives, including (a) the nature of the credit derivative - its term, how it arose, the events or circumstances that would require the seller to perform under the credit derivative, and the current status of the payment/performance risk of the credit derivative; (b) the maximum potential amount of future payments (undiscounted) the seller could be required to make under the credit derivative; (c) the current fair value of the credit derivative; and (d) the nature of any recourse provisions under the credit derivative, and any assets held either as collateral or by third parties. A credit derivative is a derivative instrument (1) in which one or more of its underlyings are related to the credit risk of a specified entity (or a group of entities) or an index based on the credit risk of a group of entities and (2) that exposes the seller to potential loss from credit-risk-related events specified in the contract. Examples of credit derivatives within the scope of this paragraph include, but are not limited to, credit default swaps, credit spread options, and credit index products; also includes a hybrid instrument that has an embedded credit derivative (for example, but not limited to, a credit-linked note).

+ References + Details

Income Taxes

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Income Taxes

Income (Loss) Before Income Taxes

Income (loss) before income taxes is comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Domestic	$	3,458	$	4,433	$	2,137
Foreign	53		83		310
Total Income (loss) before income taxes	$	3,511	$	4,516	$	2,447

Components of Income Tax Expense or Benefit

Income taxes are comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Federal
Current	$	764	$	451	$	392
Deferred	238		229		302
ITC amortization	(15)		(14)		(15)
State
Current	136		127		142
Deferred	50		(39)		(34)
Foreign
Current	14		(25)		72
Deferred	—		45		—
Total Income tax (benefit) expense	$	1,187	$	774	$	859

Income Taxes Paid

Income taxes (net of refunds) paid during the year was comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Federal	$	341	$	242	$	315
State
Illinois	16		24		19
Maryland	11		24		7
Other state	91		141		41
Foreign
United Kingdom	(20)		—		61
Other foreign	7		5		23
Total income taxes paid (net of refunds)	$	446	$	436	$	466

Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	For the Years Ended December 31,
	2025				2024				2023
U.S. federal statutory income tax	21.0	%	$	737	21.0	%	$	948	21.0	%	$	514
(Decrease) increase due to:
State income taxes, net of federal income tax benefit(a)(b)	4.2		147		1.5		69		3.5		86
Foreign tax effects	0.1		2		0.1		3		0.5		12
Tax credits
PTC	(2.1)		(74)		(9.4)		(425)		—		—
Amortization of ITC, including deferred taxes on basis differences	(0.3)		(12)		(0.2)		(11)		(0.5)		(12)
Other	(0.3)		(8)		(0.4)		(16)		(0.6)		(15)
Nontaxable or nondeductible items
Share-based payment awards	(1.2)		(44)		(0.4)		(17)		(0.3)		(7)
Excess officers compensation	1.5		51		0.7		34		0.8		20
Other	1.0		38		0.2		10		0.4		9
Other adjustments
Qualified NDT fund income and losses	9.9		350		4.0		179		10.3		252
Effective income tax(c)(d)	33.8	%	$	1,187	17.1	%	$	774	35.1	%	$	859

_________

(a)Includes $21 million, ($42) million and ($4) million related to state rate changes and certain state tax positions in 2025, 2024, and 2023, respectively.

(b)In 2025, state taxes in Massachusetts, New York, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category. In 2024, state taxes in Maryland, Illinois, Massachusetts, California, New Jersey, New York, Pennsylvania, and Connecticut made up the majority (greater than 50%) of the tax effect in this category. In 2023, state taxes in Maryland, Pennsylvania, New Jersey, and California made up the majority (greater than 50%) of the tax effect in this category.

(c)The change in effective tax rate in 2025 is primarily due to the inclusion of nuclear PTCs, which are not taxable, and higher income from Qualified NDT funds.

(d)Amounts may not recalculate due to rounding.

Tax Differences and Carryforwards

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2025 and 2024 are presented below:


	December 31, 2025		December 31, 2024
Plant basis differences	$	(3,321)	$	(3,138)
Accrual-based contracts	(35)		(30)
Derivatives and other financial instruments	1,090		700
Deferred pension and postretirement obligation	(359)		(336)
Nuclear decommissioning activities	(187)		(256)
Tax loss carryforward	23		19
Tax loss carryforward valuation allowances	(3)		(3)
Investment in partnerships	(283)		(204)
Other, net	(160)		242
Deferred income tax liabilities (net)	(3,235)		(3,006)
Unamortized ITCs	(309)		(325)
Total deferred income tax liabilities (net) and unamortized ITCs	$	(3,544)	$	(3,331)

The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2025:


	December 31, 2025
Federal


Federal general business credits carryforwards and other carryforwards	$	—

State
State net operating losses (NOL) and other carryforwards	393
Deferred taxes on state tax attributes (net)	17
Valuation allowance on state tax attributes	(3)
Foreign
Foreign NOL and other carryforwards	20
Deferred taxes on foreign tax attributes (net)	5

As of December 31, 2025, NOL carryforwards consisted primarily of NOL in ten states, totaling $17M in deferred tax assets with the majority to expire between 2030 and 2032. A portion of state NOLs is offset with a valuation allowance to address potential limitation on NOL usage prior to expiration.

Unrecognized Tax Benefits

Our unrecognized tax benefits were not material as of and for the years ended December 31, 2025, 2024, and 2023, and if recognized, would not significantly impact our effective tax rate. Further, these amounts are not expected to significantly increase or decrease within the next twelve months.

Total amounts of interest and penalties recognized

Interest and penalty expenses are recorded in Interest expense, net and Other, net, respectively, in the Consolidated Statements of Operations and Comprehensive Income. There was no material interest and penalty expense related to our tax positions for the years ended December 31, 2025, 2024, and 2023.

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction			Open Years(a)
Federal consolidated income tax returns			2010-2024
Illinois unitary corporate income tax returns			2012-2024
Texas combined corporate income tax returns			2021-2024
New Jersey combined corporate income tax returns			2021-2024
Maryland separate corporate income tax returns			2022-2024
Massachusetts combined corporate income tax returns			2022-2024
New York combined corporate income tax returns			2022-2024
Pennsylvania separate corporate income tax returns			2022-2024
California combined corporate income tax returns			2010-2024

__________

(a)Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.

Constellation participates in the IRS Compliance Assurance Process which provides the opportunity to resolve complex tax matters with the IRS prior to filing its federal income tax returns with a goal to achieve certainty with respect to tax matters. Constellation entered the program for the 2024 tax year.

Other Tax Matters

One Big Beautiful Bill Act

In July 2025, Congress passed the OBBBA which, among other things, included certain changes in tax law. See Note 3 — Regulatory Matters for additional information.

Tax Matters Agreement

In connection with the separation, we entered a TMA with Exelon. The TMA governs the respective rights, responsibilities, and obligations between us and Exelon after the separation with respect to tax liabilities and benefits, tax attributes, tax returns, tax contests and other tax sharing regarding U.S. federal, state, local and foreign income taxes, other tax matters and related tax returns.

Responsibility and Indemnification for Taxes. As a former subsidiary of Exelon, we have joint and several liability with Exelon to the IRS and certain state jurisdictions relating to the taxable periods that we were included in federal and state filings. However, the TMA specifies the portion of this tax liability for which we will bear contractual responsibility, and we and Exelon agreed to indemnify each other against any amounts for which such indemnified party is not responsible. Specifically, we will be liable for taxes due and payable in connection with tax returns that we are required to file. We will also be liable for our share of certain taxes required to be paid by Exelon with respect to taxable years or periods (or portions thereof) ending on or prior to the separation to the extent that we would have been responsible for such taxes under the Exelon tax sharing agreement then existing. As of December 31, 2025 and 2024, respectively, our Consolidated Balance Sheets reflect $43 million and $39 million in Other deferred credits and other liabilities, respectively, for tax liabilities where we maintain contractual responsibility to Exelon.

Tax Refunds and Attributes. The TMA provides for the allocation of certain pre-closing tax attributes between us and Exelon. Tax attributes will be allocated in accordance with the principles set forth in the existing Exelon tax sharing agreement, unless otherwise required by law. Under the TMA, we will be entitled to refunds for taxes for which we are responsible. In addition, it is expected that Exelon will have tax attributes that may be used to offset Exelon’s future tax liabilities. A significant portion of such attributes were generated by our business. In February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. During 2025 and 2024, we received payments for tax attributes utilized by Exelon related to the 2024 and 2023 tax years of $145 million and $174 million, respectively. As of December 31, 2025 and 2024, respectively, we had $175 million and $138 million in Accounts receivable, net and $21 million and $201 million in Other deferred debits and other assets for the reclassified tax attributes expected to be utilized by Exelon after separation in accordance with the terms of the TMA.

IRS Notice 2026. In February 2026, the IRS issued Notice 2026‑7 (the “Notice”), which provides guidance on the implementation of the corporate alternative minimum tax (CAMT). The Notice permits taxpayers to deduct repair and maintenance costs under tax law principles in determining adjusted financial statement income and applies retroactively to previously filed tax returns. As a result of this Notice, Exelon amended its 2023 and 2024 tax returns to reflect less CAMT and thus lower utilization of previously refunded tax attributes.

We received a demand letter from Exelon on February 19, 2026, and expect to remit to Exelon $235 million under the TMA related to prior periods. This payment is due within 45 days of our receipt of the demand letter. We will increase our receivable for the $235 million in the first quarter of 2026 as we expect Exelon to pay us as it utilizes these tax attributes in future periods.

- Definition

The entire disclosure for income tax.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 740
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-Section 50
-Paragraph 1
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-Topic 235
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-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 1
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Reference 4: http://www.xbrl.org/2003/role/disclosureRef
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-URI https://asc.fasb.org/1943274/2147482685/740-10-50-12

Reference 5: http://www.xbrl.org/2003/role/exampleRef
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Reference 6: http://www.xbrl.org/2003/role/disclosureRef
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-Paragraph 12C
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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
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-SubTopic 270
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Reference 9: http://www.xbrl.org/2003/role/disclosureRef
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Reference 10: http://www.xbrl.org/2003/role/disclosureRef
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Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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Reference 12: http://www.xbrl.org/2003/role/disclosureRef
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Reference 13: http://www.xbrl.org/2003/role/disclosureRef
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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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-URI https://asc.fasb.org/1943274/2147482603/740-30-50-2

+ Details

Leases - Operating Leases (Details)	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Weighted average remaining lease term	6 years 8 months 12 days	7 years 4 months 24 days	8 years 4 months 24 days
Weighted average discount rate	5.10%	5.00%	5.00%

Income Taxes (Tables)

12 Months Ended

Dec. 31, 2025

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

Income (loss) before income taxes is comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Domestic	$	3,458	$	4,433	$	2,137
Foreign	53		83		310
Total Income (loss) before income taxes	$	3,511	$	4,516	$	2,447

Components of Income Tax Expense or Benefit

Income taxes are comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Federal
Current	$	764	$	451	$	392
Deferred	238		229		302
ITC amortization	(15)		(14)		(15)
State
Current	136		127		142
Deferred	50		(39)		(34)
Foreign
Current	14		(25)		72
Deferred	—		45		—
Total Income tax (benefit) expense	$	1,187	$	774	$	859

Income Taxes Paid

Income taxes (net of refunds) paid during the year was comprised of the following components:


	For the Years Ended December 31,
	2025		2024		2023
Federal	$	341	$	242	$	315
State
Illinois	16		24		19
Maryland	11		24		7
Other state	91		141		41
Foreign
United Kingdom	(20)		—		61
Other foreign	7		5		23
Total income taxes paid (net of refunds)	$	446	$	436	$	466

Effective Income Tax Rate Reconciliation

The effective income tax rate varies from the U.S. federal statutory rate principally due to the following:


	For the Years Ended December 31,
	2025				2024				2023
U.S. federal statutory income tax	21.0	%	$	737	21.0	%	$	948	21.0	%	$	514
(Decrease) increase due to:
State income taxes, net of federal income tax benefit(a)(b)	4.2		147		1.5		69		3.5		86
Foreign tax effects	0.1		2		0.1		3		0.5		12
Tax credits
PTC	(2.1)		(74)		(9.4)		(425)		—		—
Amortization of ITC, including deferred taxes on basis differences	(0.3)		(12)		(0.2)		(11)		(0.5)		(12)
Other	(0.3)		(8)		(0.4)		(16)		(0.6)		(15)
Nontaxable or nondeductible items
Share-based payment awards	(1.2)		(44)		(0.4)		(17)		(0.3)		(7)
Excess officers compensation	1.5		51		0.7		34		0.8		20
Other	1.0		38		0.2		10		0.4		9
Other adjustments
Qualified NDT fund income and losses	9.9		350		4.0		179		10.3		252
Effective income tax(c)(d)	33.8	%	$	1,187	17.1	%	$	774	35.1	%	$	859

_________

(a)Includes $21 million, ($42) million and ($4) million related to state rate changes and certain state tax positions in 2025, 2024, and 2023, respectively.

(c)The change in effective tax rate in 2025 is primarily due to the inclusion of nuclear PTCs, which are not taxable, and higher income from Qualified NDT funds.

(d)Amounts may not recalculate due to rounding.

Tax Effects of Temporary Differences

The tax effects of temporary differences and carryforwards, which give rise to significant portions of the deferred tax assets (liabilities), as of December 31, 2025 and 2024 are presented below:


	December 31, 2025		December 31, 2024
Plant basis differences	$	(3,321)	$	(3,138)
Accrual-based contracts	(35)		(30)
Derivatives and other financial instruments	1,090		700
Deferred pension and postretirement obligation	(359)		(336)
Nuclear decommissioning activities	(187)		(256)
Tax loss carryforward	23		19
Tax loss carryforward valuation allowances	(3)		(3)
Investment in partnerships	(283)		(204)
Other, net	(160)		242
Deferred income tax liabilities (net)	(3,235)		(3,006)
Unamortized ITCs	(309)		(325)
Total deferred income tax liabilities (net) and unamortized ITCs	$	(3,544)	$	(3,331)

Summary of Loss Carryforwards

The following table provides our carryforwards, of which the state-related items are presented on a post-apportioned basis, and any corresponding valuation allowances as of December 31, 2025:


	December 31, 2025
Federal


Federal general business credits carryforwards and other carryforwards	$	—

State
State net operating losses (NOL) and other carryforwards	393
Deferred taxes on state tax attributes (net)	17
Valuation allowance on state tax attributes	(3)
Foreign
Foreign NOL and other carryforwards	20
Deferred taxes on foreign tax attributes (net)	5

Summary of Income Tax Examinations

Description of tax years open to assessment by major jurisdiction


Major Jurisdiction			Open Years(a)
Federal consolidated income tax returns			2010-2024
Illinois unitary corporate income tax returns			2012-2024
Texas combined corporate income tax returns			2021-2024
New Jersey combined corporate income tax returns			2021-2024
Maryland separate corporate income tax returns			2022-2024
Massachusetts combined corporate income tax returns			2022-2024
New York combined corporate income tax returns			2022-2024
Pennsylvania separate corporate income tax returns			2022-2024
California combined corporate income tax returns			2010-2024

__________

(a)Tax years open to assessment include years when we were consolidated by Exelon. See discussion below under the Tax Matters Agreement for responsibility of taxes of these open years.

Leases - Components of Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating lease costs	$ 104	$ 105	$ 96
Variable lease costs	109	145	146
Total lease costs	213	250	242
Sublease income	$ 50	$ 50	$ 50

Derivative Financial Instruments - Summary of Derivative Fair Value Balances (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Derivative [Line Items]
Derivative assets (current)	$ 945	$ 843
Derivative assets (noncurrent)	450	372
Derivative liabilities (current)	(467)	(467)
Derivative liabilities (noncurrent)	(414)	(399)
Commodity Contract
Derivative [Line Items]
Derivative assets (current)	933	810
Derivative assets (noncurrent)	449	371
Total derivative assets	1,382	1,181
Derivative liabilities (current)	(465)	(465)
Derivative liabilities (noncurrent)	(413)	(399)
Total derivative liabilities	(878)	(864)
Total derivative net assets (liabilities)	504	317
Collateral \| Commodity Contract
Derivative [Line Items]
Derivative assets (current)	375	152
Derivative assets (noncurrent)	272	120
Total derivative assets	647	272
Derivative liabilities (current)	386	173
Derivative liabilities (noncurrent)	319	141
Total derivative liabilities	705	314
Total derivative net assets (liabilities)	1,352	586
Netting \| Commodity Contract
Derivative [Line Items]
Derivative assets (current)	(6,791)	(4,860)
Derivative assets (noncurrent)	(4,853)	(3,421)
Total derivative assets	(11,644)	(8,281)
Derivative liabilities (current)	6,791	4,860
Derivative liabilities (noncurrent)	4,853	3,421
Total derivative liabilities	11,644	8,281
Total derivative net assets (liabilities)	0	0
Economic Hedges \| Commodity Contract
Derivative [Line Items]
Derivative assets (current)	7,349	5,518
Derivative assets (noncurrent)	5,030	3,672
Total derivative assets	12,379	9,190
Derivative liabilities (current)	(7,642)	(5,498)
Derivative liabilities (noncurrent)	(5,585)	(3,961)
Total derivative liabilities	(13,227)	(9,459)
Total derivative net assets (liabilities)	$ (848)	$ (269)

Retirement Benefits - Net Benefit Costs (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Contribution Plan Disclosure [Line Items]
Service cost	$ 102	$ 107	$ 105
Interest cost	$ 486	$ 463	$ 480
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Interest Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Expected return on assets	$ (522)	$ (548)	$ (565)
Defined Benefit Plan, Net Periodic Benefit (Cost) Credit, Expected Return (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Prior service (credit) cost	$ (5)	$ (5)	$ (9)
Actuarial (gain) loss	$ 95	$ 93	$ 36
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Other, net	Other, net	Other, net
Settlement charges	$ 1	$ 6	$ 0
Non-service components of pension benefits & OPEB credit	55	9	(58)
Net periodic benefit cost	157	116	47
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Service cost	84	90	89
Interest cost	408	391	404
Expected return on assets	(489)	(506)	(520)
Prior service (credit) cost	1	1	1
Actuarial (gain) loss	103	102	48
Settlement charges	1	6	0
Non-service components of pension benefits & OPEB credit	24	(6)	(67)
Net periodic benefit cost	108	84	22
OPEB
Defined Contribution Plan Disclosure [Line Items]
Service cost	18	17	16
Interest cost	78	72	76
Expected return on assets	(33)	(42)	(45)
Prior service (credit) cost	(6)	(6)	(10)
Actuarial (gain) loss	(8)	(9)	(12)
Settlement charges	0	0	0
Non-service components of pension benefits & OPEB credit	31	15	9
Net periodic benefit cost	$ 49	$ 32	$ 25

Debt and Credit Agreements

12 Months Ended

Dec. 31, 2025

Debt Disclosure [Abstract]

Debt and Credit Agreements

Short-Term Borrowings

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facility for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

Credit Agreements

In September 2025, we amended our existing RCF to increase the available aggregate commitment from $4.5 billion to $7.0 billion, which included incremental revolving credit commitments of $2.5 billion and extension of the maturity date to September 2030. The incremental commitments became available upon closing of the Calpine acquisition in January 2026. The RCF may be drawn down in the form of loans and/or to support commercial paper and letters of credit issuances.

The RCF fixed facility fee rate is 0.175% and borrowings under the RCF bear interest at a rate based upon either the Daily Simple SOFR rate or a Term SOFR rate, plus an adder based upon our credit ratings. The adders for the Daily Simple SOFR-based borrowings and Term SOFR borrowings are 0.075% and 1.075%, respectively. The letters of credit bear interest at a rate of 1.075%.

If we were to lose our investment grade credit rating, the maximum adders for Daily Simple SOFR rate borrowings and Term SOFR rate borrowings would be 1.00% and 2.00%, respectively. The credit agreements also require us to pay facility fees based upon the aggregate commitments. The fees vary depending upon our credit rating.

Accounts Receivable Facility

In December 2024, we amended the Facility to provide NER access to revolving loans from a number of financial institutions ("Lenders") secured by certain customer accounts receivable. As part of the amendment, the maximum funding limit of the of the Facility was increased from $1.1 billion to $1.5 billion and the maturity date was extended to December 2027. Under previous terms of the Facility, certain customer accounts receivable were sold to the Purchasers. Immediately following the amendment, all receivables previously sold were assigned back to us and receivables will no longer be sold to the Purchasers under the amendment. Subsequent to the amendment, draws and repayments related to the Facility will be reflected as Proceeds from short-term borrowings and Repayments of short-term borrowings, respectively, in the Consolidated Statements of Cash Flows. Draws on the facility bear interest at a commercial paper rate or a Daily One Month Term SOFR or Term SOFR rate, plus an adder of 0.10% per annum. Interest is payable monthly. There were no draws on the Facility as of December 31, 2025. In February 2026, we drew on the Facility in the amount of $600 million which was still outstanding as of the date of this filing.

The amended Facility requires the balance of eligible receivables to be maintained at or above the balance of cash proceeds received from the Lenders. To the extent the eligible receivables decrease below such balance, we are required to repay cash to the Lenders. When eligible receivables exceed cash proceeds, we have the ability to increase the cash proceeds received up to the maximum funding limit.

As of December 31, 2025 and 2024, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


December 31, 2025
Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit(a)		Outstanding Commercial Paper(b)		Total Available Capacity
Revolving Credit Facility	$	4,500	$	—	$	40	$	—	$	4,460
Bilaterals(c)	2,350		—		1,276		—		1,074
Accounts Receivable Facility	1,500		—		—		—		1,500
Liquidity Facility	971		—		647		—		312		(d)
Project Finance	137		—		122		—		15
Total	$	9,458	$	—	$	2,085	$	—	$	7,361

December 31, 2024
Revolving Credit Facility	$	4,500	$	—	$	51	$	—	$	4,449
Bilaterals	1,850		—		1,095		—		755
Accounts Receivable Facility	1,500		—		—		—		1,500
Liquidity Facility	971		—		907		—		21		(d)
Project Finance	137		—		120		—		17
Total	$	8,958	$	—	$	2,173	$	—	$	6,742

__________

(c)Refer to table below for additional information on our bilateral credit agreements.

Bilateral Credit Agreements

The following table reflects the bilateral credit agreements at December 31, 2025:

Date Initiated(a)

Latest Amendment Date

Maturity Date(b)

Amount

January 2016

April 2023

April 2026

150

October 2019

N/A

200

November 2019

N/A

300

November 2019

N/A

100

November 2019

June 2024

June 2026

100

May 2020(c)

March 2023

N/A

300

August 2022

N/A

March 2023

March 2025

March 2027

100

December 2023

N/A

200

March 2024(c)

N/A

200

May 2024

N/A

150

January 2025(c)

N/A

200

March 2025

N/A

March 2026

300

2,350

__________

(a)Bilateral credit agreements solely support the issuance of letters of credit and do not back our commercial paper program.

(c)In February 2026, we increased the capacity to issue letters of credit by an additional $100 million each for three existing uncommitted bilateral facilities.

Short-Term Loan Agreements

We had short-term loan agreements outstanding as of December 31, 2025 as reflected in the table below. There were no short-term loan agreements outstanding as of December 31, 2024.

Month Initiated

Interest Rate

Maturity

Weighted Average Interest Rate

Outstanding Amount as of December 31, 2025

May 2025

1-month SOFR + 0.90%

May 2026

5.09

900

September 2025

1-month SOFR + 0.90%

September 2026

4.93

750

Long-Term Debt

The following table presents the outstanding long-term debt as of December 31, 2025 and 2024:


			December 31,
	Rates	Maturity Date	2025		2024
Long-term debt
Senior unsecured notes	5.60% - 6.50%	2028 - 2054	$	5,688	$	6,588
Tax-exempt notes	4.10% - 4.45%	2029 - 2053(a)	412		435
Notes payable and other	1.71% - 6.10%	2026 - 2035	53		51
Nonrecourse debt:
Fixed rates	2.29% - 6.00%	2031 - 2037	653		720
Variable rates	5.82% - 6.76%	2027	597		680
Total long-term debt			7,403		8,474
Unamortized debt discount and premium, net			(1)		(4)
Unamortized debt issuance costs			(60)		(58)
Long-term debt due within one year			(92)		(1,028)
Long-term debt			$	7,250	$	7,384

________

(a)The Tax-exempt notes have a maturity date of June 2029 to April 2053, and a mandatory purchase date that ranges from April 2028 to June 2029.

Long-term debt maturities in the periods 2026 through 2031 and thereafter are as follows:


2026	$	92
2027	666
2028	828
2029	157
2030	99
2031 and thereafter	5,561
Total	$	7,403

DOE Loan Guarantee

In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan will mature in November 2055. Interest rates on the loan will be fixed upon each advance at a spread of 0.375% above U.S. Treasuries of comparable maturity. There have been no borrowings on this loan as of the date of this filing.

Calpine Acquisition

Upon completion of the acquisition of Calpine in January 2026, we assumed approximately $12.6 billion of debt inclusive of approximately $7.6 billion of corporate long-term debt, including senior unsecured and secured notes and corporate term loans in addition to approximately $5 billion of various project financing arrangements. Pursuant to the Exchange Offers discussed below, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes with Constellation senior unsecured notes. Using the proceeds from our January 2026 bond issuance, as discussed below, along with cash on hand and short-term debt, we repaid $2.5 billion of Calpine corporate term loans immediately after the acquisition closing and repaid $1.25 billion of Calpine senior secured first lien notes in February 2026. Following the debt exchange and redemptions discussed, $6.5 billion of Calpine debt remains outstanding.

Debt Exchange Offering

In December 2025, we announced that, in connection with the planned acquisition of Calpine by CEG Parent, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine. Under the Exchange Offers, we solicited consents to holders of certain Calpine debt to amend the notes and the related indentures under which they were issued to eliminate substantially all of the restrictive covenants, restrictive provisions and events of default, other than payment-related and bankruptcy-related events of default. In January 2026, we completed the exchange offering, effectively replacing $2.3 billion of Calpine senior secured and unsecured notes with Constellation senior unsecured notes.

The terms of the debt issuance under the exchange are as follows:


Note	Interest Rate	Maturity	Issued Amount
2029 Senior Notes	4.625%	February 2029	$	647
2031 Senior Notes	5.000%	February 2031	848
2031 Senior Notes	3.750%	March 2031	795
Total			$	2,290

Senior Note Issuance

In January 2026, we issued senior unsecured notes totaling $2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are as follows:


Note	Interest Rate	Maturity	Issued Amount
2028 Floating Rate Senior Notes	SOFR + 0.600%	January 2028	$	300
2028 Senior Notes	3.900%	January 2028	900
2031 Senior Notes	4.400%	January 2031	750
2066 Senior Notes	5.875%	January 2066	800
Total			$	2,750

Debt Covenants

As of December 31, 2025, we are in compliance with all debt covenants.

Nonrecourse Debt

We have also issued nonrecourse debt, for which approximately $1.9 billion and $2 billion of generating assets have been pledged as collateral as of December 31, 2025 and 2024, respectively. Borrowings under these agreements are secured by the assets and equity of each respective project. The lenders do not have recourse against us in the event of a default. If a specific project financing entity does not maintain compliance with its specific nonrecourse debt covenants, there could be a requirement to accelerate repayment of the associated debt or other borrowings earlier than the stated maturity dates. In these instances, if such repayment was not satisfied, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to satisfy the associated debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives.

Antelope Valley Solar Ranch One. In December 2011, the DOE Loan Programs Office issued a guarantee for up to $646 million for a nonrecourse loan from the Federal Financing Bank to support the financing of the construction of the Antelope Valley facility. The project became fully operational in 2014. The loan will mature in January 2037. Interest rates on the loan were fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. The advances were completed in December 2015 and the outstanding loan balance bears interest at an average blended interest rate of 2.82%. As of December 31, 2025 and 2024, approximately $335 million and $365 million were outstanding, respectively. In addition, we have issued letters of credit to support the equity investment in the project, with $36 million outstanding as of December 31, 2025 and 2024. In December 2017, our interests in Antelope Valley were contributed to and are pledged as collateral for the CR financing structures referenced below.

Continental Wind, LLC. In September 2013, Continental Wind, our indirect subsidiary, completed the issuance and sale of $613 million senior secured notes. Continental Wind owns and operates a portfolio of wind farms in Idaho, Kansas, Michigan, Oregon, New Mexico and Texas with a total net capacity of 667 MWs. The net proceeds were distributed to us for general business purposes. The notes are scheduled to mature in February 2033. The notes bear interest at a fixed rate of 6.00% with interest payable semi-annually. As of December 31, 2025 and 2024, approximately $260 million and $290 million were outstanding, respectively.

In addition, Continental Wind has a $128 million letter of credit facility and $4 million working capital revolver facility. Continental Wind has issued letters of credit to satisfy certain of its credit support and security obligations. As of December 31, 2025 and 2024, the Continental Wind letter of credit facility had $122 million and $119 million in letters of credit outstanding related to the project, respectively.

In 2017, our interests in Continental Wind were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below.

Renewable Power Generation. In March 2016, RPG, our indirect subsidiary, issued $150 million aggregate principal amount of nonrecourse senior secured notes. The net proceeds were distributed to us for paydown of long-term debt obligations at Sacramento PV Energy and Constellation Solar Horizons and for general business purposes. The loan is scheduled to mature in March 2035. The term loan bears interest at a fixed rate of 4.11% payable semi-annually. As of December 31, 2025 and 2024, approximately $55 million and $60 million were outstanding, respectively. In 2017, our interests in RPG were contributed to CRP, whose assets were contributed to and are pledged as collateral for the CR financing structure referenced below.

Constellation Renewables. In December 2020, CR entered into a financing agreement for a $750 million nonrecourse senior secured term loan credit facility, scheduled to mature in December 2027. Beginning in October 2025, the term loan bears interest at a variable rate equal to 3-month SOFR plus 2.00%, subject to a 1% SOFR floor with interest payable quarterly. Redemptions prior to October 2025 were based on 3-month SOFR plus 2.25%. Redemptions from June 2023 through June 2024 were based on 3-month SOFR plus 2.76%, and LIBOR plus 2.50% prior to that date.

In addition to the financing, CR entered interest rate swaps to manage a portion of the interest rate exposure in connection with the financing. The swap had an initial notional amount of $516 million and fixed the 3-month LIBOR at 1.05%. Beginning in June 2023, the swap fixed the 3-month SOFR at 0.8295%. The swap expired in December 2024. In January 2024, CR entered an additional interest rate swap to manage a portion of the interest rate exposure in connection with the financing. The swap had a notional amount of $120M and fixed the 3-month SOFR to 3.98%.

Our interests in CRP and Antelope Valley are contributed to and pledged as collateral for this financing. As of December 31, 2025 and 2024, $600 million and $630 million was outstanding, respectively. See Note 21 — Variable Interest Entities for additional information on CRP and Note 15 — Derivative Financial Instruments for additional information on interest rate swaps.

West Medway II, LLC. In May 2021, West Medway II, LLC (West Medway II) entered into a $150 million nonrecourse senior secured term loan maturing in March 2026. Our interests in West Medway II were pledged as collateral. Net proceeds were used for general corporate purposes. Beginning in May 2025, the loan bore interest at 1-month SOFR plus 3.350%. Redemptions from May 2023 to May 2025 were based on 1-month SOFR plus the variable interest rate of 2.975% - 3.225% and LIBOR plus 2.875% prior to that date. West Medway II also entered into interest rate swaps with a $113 million initial notional amount that fixed LIBOR at 0.61% and, beginning in May 2023, fixed SOFR at 0.5365%. The swaps were terminated in August and October 2025. As of December 31, 2024, approximately $50 million was outstanding and the term loan was fully repaid in October 2025.

- Definition

The entire disclosure for information about short-term and long-term debt arrangements, which includes amounts of borrowings under each line of credit, note payable, commercial paper issue, bonds indenture, debenture issue, own-share lending arrangements and any other contractual agreement to repay funds, and about the underlying arrangements, rationale for a classification as long-term, including repayment terms, interest rates, collateral provided, restrictions on use of assets and activities, whether or not in compliance with debt covenants, and other matters important to users of the financial statements, such as the effects of refinancing and noncompliance with debt covenants.

+ References

Reference 1: http://www.xbrl.org/2003/role/disclosureRef
-Topic 815
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8A
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480434/815-10-50-8A

Reference 2: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S50
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480738/235-10-S50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(c))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 4: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 6
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

Reference 5: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 10
-Name Accounting Standards Codification
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-URI https://asc.fasb.org/1943274/2147481544/470-10-50-6

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-SubTopic 40
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-Section 50
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-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

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-Topic 405
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-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 405
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-Section 50
-Paragraph 1
-Subparagraph (a)
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-URI https://asc.fasb.org/1943274/2147477092/405-40-50-1

Reference 11: http://www.xbrl.org/2003/role/disclosureRef
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-Name Accounting Standards Codification
-Section 50
-Paragraph 1B
-Subparagraph (h)
-Publisher FASB
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-SubTopic 30
-Name Accounting Standards Codification
-Section 45
-Paragraph 2
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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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+ Details

Revenue from Contracts with Customers - Performance Obligations (Details) $ in Millions	Dec. 31, 2025 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 1,047
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 386
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 269
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 135
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 117
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 61
Remaining performance obligations, timing	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2031-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligations	$ 79
Remaining performance obligations, timing	1 year

Intangible Assets - Schedule of Goodwill (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Goodwill [Roll Forward]
Beginning balance	$ 420	$ 425
Goodwill allocated to assets held for sale	0	(5)
Ending balance	$ 420	$ 420

- Definition

Amount, after accumulated impairment loss, of asset representing future economic benefit arising from other asset acquired in business combination or from joint venture formation or both, that is not individually identified and separately recognized.

+ References

Reference 1: http://www.xbrl.org/2003/role/exampleRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 55
-Paragraph 24
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482548/350-20-55-24

Reference 2: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 8
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479328/805-10-50-8

Reference 3: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 41
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-41

Reference 4: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 740
-Name Accounting Standards Codification
-Section 55
-Paragraph 13
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478064/805-740-55-13

Reference 5: http://www.xbrl.org/2003/role/exampleRef
-Topic 805
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 39
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479303/805-10-55-39

Reference 6: http://www.xbrl.org/2003/role/exampleRef
-Topic 280
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 49
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482785/280-10-55-49

Reference 7: http://www.xbrl.org/2003/role/exampleRef
-Topic 820
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 100
-Subparagraph (d)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482078/820-10-55-100

Reference 8: http://www.xbrl.org/2003/role/exampleRef
-Topic 852
-SubTopic 10
-Name Accounting Standards Codification
-Section 55
-Paragraph 10
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481372/852-10-55-10

Reference 9: http://www.xbrl.org/2003/role/disclosureRef
-Topic 210
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.5-02(15))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480566/210-10-S99-1

Reference 10: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 45
-Paragraph 1
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482598/350-20-45-1

Reference 11: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (a)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 12: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 350
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (h)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147482573/350-20-50-1

Reference 13: http://www.xbrl.org/2003/role/disclosureRef
-Topic 942
-SubTopic 210
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.9-03(10)(1))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147478546/942-210-S99-1

Reference 14: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 805
-SubTopic 30
-Name Accounting Standards Codification
-Section 50
-Paragraph 4
-Subparagraph (b)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479581/805-30-50-4

+ Details

Lessor - Components of Operating Lease Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating lease income	$ 51	$ 51	$ 51
Variable lease income	$ 231	$ 244	$ 248

Intangible Assets - Schedule of Finite-Lived Intangible Assets, Future Amortization Expense (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Goodwill and Intangible Assets Disclosure [Abstract]
2026	$ 41
2027	33
2028	28
2029	20
2030	16
2031 and thereafter	63
Net	$ 201	$ 236

Stock-Based Compensation Plans

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Stock-Based Compensation Plans

Our LTIP grants cash and stock-based awards that primarily include performance share awards and restricted stock units. Our LTIP authorized 20,000,000 shares of common stock for these awards.

The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income:


	For the Years Ended December 31,
	2025		2024		2023
Total stock-based compensation expense included in Operating and maintenance expense	$	385	$	332	$	178
Income tax benefit	(99)		(85)		(45)
Total after-tax stock-based compensation expense	$	286	$	247	$	133

We receive a tax deduction based on the intrinsic value of the award on the distribution date for performance share awards and restricted stock units. The tax deduction related to performance share awards and restricted stock units was not material for the years ended December 31, 2025, 2024, and 2023. For each award, throughout the requisite service period, we recognize the tax benefit related to compensation costs. For performance share awards and restricted stock units, our realized tax benefit when distributed was not material for the years ended December 31, 2025, 2024, and 2023.

Performance Share Awards

Performance share awards are granted under the LTIP. The performance share awards are typically settled 50% in common stock and 50% in cash at the end of the three-year performance period, subject to certain ownership thresholds that, if met, may result in cash settlement of the entire award.

The common stock portion of the performance share awards is considered an equity award and is valued based on our stock price on the grant date. The cash portion of the performance share awards is considered a liability award which is remeasured each reporting period based on the current stock price. As the value of the common stock and cash portions of the awards are based on the stock price during the performance period, coupled with changes in the total expected payout of the award, the compensation costs are subject to volatility until payment is made.

For nonretirement-eligible employees, performance share awards are recognized over the vesting period of three years using the straight-line method. For performance share awards granted to retirement-eligible employees, the value of the performance shares is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes our unvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024	535,626	$	99.06
Granted	120,057	321.83
Change in performance	96,623	313.60

Forfeited	(3,812)	195.73
Undistributed vested awards(a)	(469,066)	332.97
Unvested at December 31, 2025	279,428	$	198.49

__________

(a)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2025 and 2024.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:


	December 31, 2025(a)		December 31, 2024(a)
Weighted average grant date fair value (per share)	$	321.83	$	127.03
Total fair value of performance shares vested	156		138

__________

(a)As of December 31, 2025 and 2024, total unrecognized compensation costs related to unvested performance shares of $41 million and $50 million, respectively, are expected to be recognized over the remaining weighted average period of 1.5 years.

Restricted Stock Units

Restricted stock units are granted under the LTIP with the majority being settled in a specific number of shares of common stock after the service condition has been met. The corresponding cost is measured based on the grant date fair value of the restricted stock unit issued.

The value of the restricted stock units is expensed over the requisite service period using the straight-line method. The requisite service period for restricted stock units is generally three to five years. However, certain restricted stock unit awards become fully vested upon the employee reaching retirement eligibility. The value of the restricted stock units granted to retirement-eligible employees is recognized ratably over the vesting period, which is the year of grant. We process forfeitures as they occur for employees who do not complete the requisite service period.

The following table summarizes our unvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024	809,093	$	96.53
Granted	265,512	312.97
Vested	(437,388)	82.45
Forfeited	(11,067)	197.23
Undistributed vested awards(a)	(76,272)	271.03
Unvested at December 31, 2025	549,878	$	181.54

__________

(a)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2025 and 2024.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:


	December 31, 2025(a)		December 31, 2024(a)
Weighted average grant date fair value (per share)	$	312.97	$	134.18
Total fair value of restricted stock units vested	57		42

__________

(a)As of December 31, 2025 and 2024, total unrecognized compensation costs related to unvested restricted stock units of $57 million and $41 million, respectively, are expected to be recognized over the remaining weighted average period of 1.9 years and 1.8 years, respectively.

Retirement Benefits

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Retirement Benefits

Defined Benefit Pension and OPEB

Approximately half of current employees participate in the defined benefit pension and OPEB plans that we sponsor. As the plan sponsor, our Consolidated Balance Sheets reflect underfunded pension and OPEB liabilities equal to an excess of either the PBO or APBO over the fair value of the plan assets, consistent with a single employer benefit plan. Newly hired employees are generally not eligible for either pension or OPEB benefits; instead, these employees are eligible to receive an enhanced non-discretionary fixed employer contribution under our sponsored defined contribution savings plan.

Benefit Obligations, Plan Assets, and Funded Status

We use a December 31 measurement date for our pension and OPEB obligations and the related plan assets. The actuarial losses experienced upon remeasurement as of December 31, 2025 were offset against AOCI, net of deferred taxes. See the table below for changes associated with the pension valuation.

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2025 and 2024 for all plans combined:


	Pension Benefits				OPEB
	2025		2024		2025		2024
Change in benefit obligation:
Benefit obligation as of the beginning of the year	$	7,397	$	7,770	$	1,422	$	1,443
Service cost	84		90		18		17
Interest cost	408		391		78		72
Plan participants' contributions	—		—		30		24
Actuarial loss (gain), net	289		(269)		120		12
Reclassification to liabilities held for sale	—		(9)		—		(1)
Settlements	(3)		(13)		—		—
Gross benefits paid	(582)		(563)		(147)		(145)
Benefit obligation as of the end of year	$	7,593	$	7,397	$	1,521	$	1,422


	Pension Benefits				OPEB
	2025		2024		2025		2024
Change in plan assets:
Plan assets as of the beginning of year	$	6,317	$	6,687	$	598	$	692
Employer contributions	174		177		—		—
Plan participants' contributions	—		—		24		18
Actual return (loss) on plan assets	593		37		45		22
Reclassification to assets held for sale	—		(8)		—		—
Settlements	(3)		(13)		—		—
Gross benefits paid	(582)		(563)		(103)		(134)
Fair value of plan assets as of the end of year	$	6,499	$	6,317	$	564	$	598

Over (under) funded status (Plan assets less benefit obligations)	$	(1,094)	$	(1,080)	$	(957)	$	(824)

We present our benefit obligations net of plan assets in our Consolidated Balance Sheets within the following line items:


	Pension Benefits				OPEB
	2025		2024		2025		2024

Other current liabilities	$	(22)	$	(9)	$	(52)	$	(20)
Pension and non-pension benefit obligations	(1,072)		(1,071)		(905)		(804)

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets.


ABO in Excess of Plan Assets	December 31, 2025		December 31, 2024
ABO	$	(7,436)	$	(7,225)
Fair value of plan assets	6,499		6,317

Components of Net Periodic Benefit (Credit) Cost

See Note 1 — Basis of Presentation for additional information on where we report the service cost and other non-service cost (credit) components for all plans.

The following table presents the components of our net periodic benefit (credit) cost for the years ended December 31, 2025, 2024, and 2023. The amounts below are shown prior to capitalization and co-owner allocations, the effects of which were not material for any of the periods presented.


	Pension Benefits						OPEB						Total Pension Benefits and OPEB
	2025		2024		2023		2025		2024		2023		2025		2024		2023
Components of net periodic benefit (credit) cost:
Service cost	$	84	$	90	$	89	$	18	$	17	$	16	$	102	$	107	$	105
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	408		391		404		78		72		76		486		463		480
Expected return on assets	(489)		(506)		(520)		(33)		(42)		(45)		(522)		(548)		(565)
Amortization of:
Prior service (credit) cost	1		1		1		(6)		(6)		(10)		(5)		(5)		(9)
Actuarial (gain) loss	103		102		48		(8)		(9)		(12)		95		93		36
Settlement charges	1		6		—		—		—		—		1		6		—

Non-service components of pension benefits & OPEB credit (cost)	24		(6)		(67)		31		15		9		55		9		(58)
Net periodic benefit (credit) cost	$	108	$	84	$	22	$	49	$	32	$	25	$	157	$	116	$	47

Components of AOCI

We recognize the overfunded or underfunded status of defined benefit pension and OPEB plans as an asset or liability on our balance sheet, with offsetting entries to AOCI. The following tables provide the pre-tax components of AOCI for the years ended December 31, 2025 and 2024, for all plans combined:


	Pension Benefits				OPEB
	2025		2024		2025		2024
Changes in plan assets and benefit obligations recognized in AOCI:
Current year actuarial (gain) loss	$	186	$	202	$	109	$	33
Amortization of actuarial (loss) gain	(103)		(102)		8		9

Amortization of prior service (cost) credit	(1)		(1)		6		6
Settlements	(1)		(6)		—		—
Total recognized in AOCI	$	81	$	93	$	123	$	48

The following table provides the components of gross accumulated other comprehensive income (loss) that have not been recognized as components of periodic benefit cost as of December 31, 2025 and 2024, for all plans combined:


	Pension Benefits				OPEB
	2025		2024		2025		2024
Prior service (credit) cost	$	8	$	8	$	(11)	$	(18)
Actuarial (gain) loss	3,162		3,080		73		(43)
Total	$	3,170	$	3,088	$	62	$	(61)

Average Remaining Service Period

For pension benefits, we amortize the unrecognized prior service (credits) costs and certain actuarial gains and losses reflected in AOCI, as applicable, based on participants’ average remaining service periods.

For OPEB, we amortize the unrecognized prior service (credits) costs reflected in AOCI over participants’ average remaining service period to benefit eligibility age, and amortize certain actuarial gains and losses reflected in AOCI over participants’ average remaining service period to expected retirement.

The resulting average remaining service periods (in years) for pension and OPEB as of December 31, 2025 and 2024 were as follows:


	December 31, 2025	December 31, 2024
Pension plans	10	11
OPEB plans:
Benefit Eligibility Age	8	8
Expected Retirement	9	9

Assumptions

The measurement of the plan obligations and costs of providing benefits under our defined benefit pension and OPEB plans involves various factors, including the development of valuation assumptions and inputs and accounting policy elections. The measurement of benefit obligations and costs is impacted by several assumptions and inputs, as shown below, among other factors. When developing the required assumptions, we consider historical information as well as future expectations.

Discount Rate. The discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality corporate bonds with similar maturities to the related pension and OPEB obligations. The spot rates are used to discount the estimated future benefit distribution amounts under the pension and OPEB plans. The discount rate is the single level rate that produces the same result as the spot rate curve. We utilize an analytical tool developed by our actuaries to determine the discount rates.

Expected Rate of Return. To determine the EROA, we use third-party expectations for future long-term capital market performance, weighted by our target asset class allocations.

Mortality. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2025 and December 31, 2024, we utilized the mortality tables and projection scales released by the SOA.

The following assumptions were used to determine the benefit obligations for the plans as of December 31, 2025 and December 31, 2024. Assumptions used to determine year-end benefit obligations are the assumptions used to estimate the subsequent year’s net periodic benefit costs.


	Pension Benefits				OPEB
	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024
Discount rate(a)	5.38	%	5.66	%	5.30	%	5.63	%
Investment crediting rate(b)	5.93	%	5.72	%	N/A		N/A
Rate of compensation increase(c)	4.25	%	4.25	%	4.25	%	4.25	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		9.00% initial, 5.00% ultimate		7.00% initial, 5.00% ultimate

__________

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Includes 4.25% average for the three-year period (2026-2028) and 3.75% average thereafter.

The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2025 and 2024.


	Pension Benefits				OPEB
	2025		2024		2025		2024
Discount rate(a)	5.66	%	5.17	%	5.63	%	5.15	%
Investment crediting rate(b)	5.72	%	5.07	%	N/A		N/A
Expected return on plan assets(c)	6.50	%	6.50	%	6.00	%	6.50	%
Rate of compensation increase(d)	4.25	%	4.25	%	4.25	%	4.25	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		7.00% initial, 5.00% ultimate		Initial and ultimate rate of 5.00%

__________

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average.

(d)Includes 4.25% average for the four-year period (2025-2028) and 3.75% average thereafter.

Contributions

We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively), and at-risk status (which triggers higher minimum contribution requirements and participant notification). The projected contributions below reflect a funding strategy to make annual contributions to offset some of the growth of the liability (e.g., from service cost). Qualified pension contributions made in February 2026 reflect our funding strategy and market conditions as of year-end.

Our non-qualified pension plans are not funded, given that they are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded some of our plans. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. Annually, we evaluate whether additional funding for those plans is needed, and the OPEB values below reflect both plan contributions (if applicable) and benefit payments for unfunded plans.

The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2025, 2024, and 2023:


	2025		2024		2023
Pension contributions(a)	$	174	$	177	$	26
OPEB contributions	37		7		28
Total contributions	$	211	$	184	$	54

__________

(a)Our annual qualified pension contributions were $161 million in 2025 and 2024. The benefit payments to the non-qualified pension plans in 2025 and 2024 were not material.

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2026 (including our benefit payments related to unfunded plans):


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB		Total
Planned contributions	$	162	$	22	$	64	$	248

Estimated Future Benefit Payments

Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2025 are as follows:


	Pension Benefits		OPEB
2026	$	595	$	125
2027	580		127
2028	598		127
2029	590		127
2030	590		126
2031 through 2035	2,848		608
Total estimated future benefits payments through 2035	$	5,801	$	1,240

Plan Assets

On a regular basis, we evaluate our investment strategy to ensure that plan assets will be sufficient to pay plan benefits when due. We have developed and implemented a liability hedging investment strategy for the majority of our qualified pension plans which has reduced the volatility of these pension assets relative to the associated pension obligations. We are likely to continue to gradually increase the liability hedging portfolios as the funded statuses of the plans improve. The overall objective is to achieve attractive risk-adjusted returns that will satisfy the liquidity requirements of the plans’ liabilities while striving to minimize the risk of significant losses. Trust assets for our OPEB plans are managed in a diversified investment strategy that prioritizes maximizing liquidity and returns while minimizing asset volatility.

Actual asset returns have an impact on the costs reported for the pension and OPEB plans. The actual asset returns across our pension and OPEB plans for the year ended December 31, 2025 were 10.10% and 10.10%, respectively, compared to an expected long-term return assumption of 6.50% and 6.00%, respectively. We used an EROA of 6.50% and 6.00% to estimate our 2026 pension and OPEB costs, respectively.

Our pension and OPEB plan target asset allocations as of December 31, 2025 and 2024 were as follows:


	December 31, 2025				December 31, 2024
Asset Category	Pension Benefits		OPEB		Pension Benefits		OPEB
Equity securities	21	%	24	%	21	%	20	%
Fixed income securities	54	%	59	%	54	%	66	%
Alternative investments(a)	25	%	17	%	25	%	14	%
Total	100	%	100	%	100	%	100	%

__________

(a)Alternative investments include private equity, hedge funds, real assets, and private credit.

We evaluated our pension and OPEB plans’ asset portfolios for the existence of significant concentrations of credit risk as of December 31, 2025. Types of concentrations that were evaluated include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, and individual fund. As of December 31, 2025, our pension and OPEB plans held no credit risk concentrations surpassing 10% of plan assets.

Fair Value Measurements

The following table presents pension and OPEB plan assets measured and recorded at fair value as a net component of Pension and non-pension postretirement benefit obligations in our Consolidated Balance Sheets on a recurring basis and their level within the fair value hierarchy as of December 31, 2025 and 2024. There were no plan assets classified as Level 3 as of December 31, 2025 and 2024.


	December 31, 2025				December 31, 2024
	Level 1		Level 2		Total		Level 1		Level 2		Total
Pension plan assets(a)
Cash equivalents	$	195	$	—	$	195	$	170	$	—	$	170
Equities(b)	1,053		—		1,053		1,041		—		1,041
Fixed income	847		1,862		2,709		675		1,795		2,470




Total assets measured at fair value	2,095		1,862		3,957		1,886		1,795		3,681
Assets measured at NAV	—		—		2,934		—		—		2,869
Pension plan assets subtotal	2,095		1,862		6,891		1,886		1,795		6,550

OPEB plan assets(a)
Cash equivalents	24		—		24		18		—		18
Equities	71		—		71		96		—		96





Fixed income	71		22		93		132		39		171




Total assets measured at fair value	166		22		188		246		39		285
Assets measured at NAV	—		—		374		—		—		309
OPEB plan assets subtotal	166		22		562		246		39		594
Total pension and OPEB plan assets(c)	$	2,261	$	1,884	$	7,453	$	2,132	$	1,834	$	7,144

__________

(a)See Note 17 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

(b)Includes total derivative assets and liabilities that are not material, which have total notional amounts of $2,509 million and $2,635 million as of December 31, 2025 and 2024, respectively. The notional principal amounts for these instruments provide one measure of the transaction volume outstanding as of the fiscal years ended and do not represent the amount of the company’s exposure to credit or market loss.

(c)Excludes net liabilities of $390 million and $229 million as of December 31, 2025 and 2024, respectively. These items are required to reconcile to the fair value of net plan assets and consist primarily of receivables or payables related to pending securities sales and purchases, and interest and dividends receivable.

Valuation Techniques Used to Determine Fair Value

The techniques used to determine the fair value of the pension and OPEB assets invested in cash equivalents, equities, fixed income, derivatives, private equity, real assets, and private credit investments are the same as the valuation techniques for these types of investments in the NDT funds. See Cash Equivalents and NDT Fund Investments in Note 17 — Fair Value of Financial Assets and Liabilities for further information.

Pension and OPEB assets also include investments in hedge funds. Hedge fund investments include those that employ a broad range of strategies to enhance returns and provide additional diversification. The fair value of hedge funds is determined using NAV or its equivalent as a practical expedient, and therefore, hedge funds are not classified within the fair value hierarchy. We have the ability to redeem these investments at NAV or its equivalent subject to certain restrictions, which may include a lock-up period or a gate.

Defined Contribution Savings Plan

We sponsor the Constellation Employee Savings Plan, a 401(k) defined contribution savings plan. The plan allows employees to contribute a portion of their pre-tax and/or after-tax income in accordance with specified guidelines. We match a percentage of the employee contributions up to certain limits. In addition, certain employees are eligible for a fixed non-discretionary employer contribution in lieu of a pension benefit. The employer contributions to the savings plan were $126 million, $117 million, and $106 million for the years ended December 31, 2025, 2024, and 2023, respectively.

- 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
-Subparagraph (p)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480506/715-20-50-1

Reference 3: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (q)
-Publisher FASB
-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
-Section 50
-Paragraph 1
-Subparagraph (d)(iv)(03)
-Publisher FASB
-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)
-Publisher FASB
-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
-Subparagraph (l)
-Publisher FASB
-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
-Publisher FASB
-URI https://asc.fasb.org/715/tableOfContent

Reference 12: http://www.xbrl.org/2003/role/disclosureRef
-Topic 715
-SubTopic 20
-Name Accounting Standards Codification
-Section 50
-Paragraph 1
-Subparagraph (d)(iii)
-Publisher FASB
-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
-Section 50
-Paragraph 1
-Subparagraph (r)(1)
-Publisher FASB
-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

Jointly-Owned Electric Plants

12 Months Ended

Dec. 31, 2025

Public Utilities, Property, Plant and Equipment [Abstract]

Jointly-Owned Electric Plants

Our material undivided ownership interests in jointly-owned plants as of December 31, 2025 and 2024 were as follows:


	NMP Unit 2			Quad Cities			Peach Bottom			STP(a)			Salem
Operator	Constellation			Constellation			Constellation			STPNOC			PSEG Nuclear
Ownership interest	82.00		%	75.00		%	50.00		%	44.00		%	42.59		%
Our share as of December 31, 2025
Plant in service	$	1,119		$	1,324		$	1,590		$	1,064		$	842
Accumulated depreciation	363			852			752			98			402
CWIP	53			29			25			23			101
Our share as of December 31, 2024
Plant in service	$	1,122		$	1,294		$	1,570		$	1,040		$	791
Accumulated depreciation	327			840			721			52			387
CWIP	27			13			15			25			68

__________

(a)Within the 44% undivided ownership interest in STP, 2% interest was recorded as held for sale as of December 31, 2025 and 2024. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Our undivided ownership interests are financed with our funds and all operations are proportionately consolidated consistent with our ownership interest in the Consolidated Statements of Operations and Comprehensive Income.

Retirement Benefits - Benefit Obligation and Plan Assets (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Change in benefit obligation:
Service cost	$ 102	$ 107	$ 105
Pension Benefits
Change in benefit obligation:
Beginning balance	7,397	7,770
Service cost	84	90	89
Interest cost	408	391
Plan participants' contributions	0	0
Actuarial loss (gain), net	289	(269)
Acquisition-related adjustment	0	(9)
Settlements	(3)	(13)
Gross benefits paid	(582)	(563)
Ending balance	7,593	7,397	7,770
Change in plan assets:
Beginning balance	6,317	6,687
Employer contributions	174	177
Plan participants' contributions	0	0
Actual return (loss) on plan assets	593	37
Acquisition-related adjustment	0	(8)
Settlements	(3)	(13)
Gross benefits paid	(582)	(563)
Ending balance	6,499	6,317	6,687
Over (under) funded status (Plan assets less benefit obligations)	(1,094)	(1,080)
OPEB
Change in benefit obligation:
Beginning balance	1,422	1,443
Service cost	18	17	16
Interest cost	78	72
Plan participants' contributions	30	24
Actuarial loss (gain), net	120	12
Acquisition-related adjustment	0	(1)
Settlements	0	0
Gross benefits paid	(147)	(145)
Ending balance	1,521	1,422	1,443
Change in plan assets:
Beginning balance	598	692
Employer contributions	0	0
Plan participants' contributions	24	18
Actual return (loss) on plan assets	45	22
Acquisition-related adjustment	0	0
Settlements	0	0
Gross benefits paid	(103)	(134)
Ending balance	564	598	$ 692
Over (under) funded status (Plan assets less benefit obligations)	$ (957)	$ (824)

Lessee - Lessee Future Minimum Operating Lease Maturity Payments (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Leases [Abstract]
2026	$ 104
2027	104
2028	105
2029	103
2030	63
2031 and thereafter	159
Total lease payments	638
Less: Imputed interest	133
Operating lease liabilities	$ 505	$ 583

Variable Interest Entities - Narrative (Details)	Dec. 31, 2025	Dec. 31, 2024
CRP
Variable Interest Entity [Line Items]
Ownership interest	51.00%	51.00%
Antelope Valley
Variable Interest Entity [Line Items]
Ownership interest	100.00%	100.00%
NER
Variable Interest Entity [Line Items]
Ownership interest	100.00%	100.00%
Constellation Energy Generation, LLC \| Solar project entities
Variable Interest Entity [Line Items]
Ownership interest	100.00%
Constellation Energy Generation, LLC \| Wind project entities
Variable Interest Entity [Line Items]
Ownership interest	100.00%

- 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

Income Taxes - Reconciliation to Effective Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Effective Income Tax Rate Reconciliation, Percent [Abstract]
U.S. federal statutory income tax	21.00%	21.00%	21.00%
State income taxes, net of federal income tax benefit	4.20%	1.50%	3.50%
Foreign tax effects	0.10%	0.10%	0.50%
PTC	(2.10%)	(9.40%)	0.00%
Amortization of ITC, including deferred taxes on basis differences	(0.30%)	(0.20%)	(0.50%)
Other	(0.30%)	(0.40%)	(0.60%)
Share-based payment awards	(1.20%)	(0.40%)	(0.30%)
Excess officers compensation	1.50%	0.70%	0.80%
Other	1.00%	0.20%	0.40%
Qualified NDT fund income and losses	9.90%	4.00%	10.30%
Effective income tax rate	33.80%	17.10%	35.10%
Income Tax Expense (Benefit), Effective Income Tax Rate Reconciliation, Amount [Abstract]
U.S. federal statutory income tax	$ 737	$ 948	$ 514
State income taxes, net of federal income tax benefit	147	69	86
Foreign tax effects	2	3	12
PTC	(74)	(425)	0
Amortization of ITC, including deferred taxes on basis differences	(12)	(11)	(12)
Other	(8)	(16)	(15)
Share-based payment awards	(44)	(17)	(7)
Excess officers compensation	51	34	20
Other	38	10	9
Other adjustments	350	179	252
Total Income tax (benefit) expense	1,187	774	859
State rate changes and tax positions	$ 21	$ (42)	$ (4)

Leases - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Cash paid for amounts included in the measurement of operating lease liabilities	$ 90	$ 87	$ 102
ROU assets obtained in exchange for operating lease obligations	$ 2	$ 6	$ 13

Leases

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Leases

Lessee

We have operating leases for which we are the lessee. The significant types of operating leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2025. We did not have material finance leases in 2025, 2024, or 2023.


			In Years
Remaining lease terms			1-30
Options to extend the term			2-30
Options to terminate within			2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease costs	$	104	$	105	$	96
Variable lease costs	109		145		146





Total lease costs(a)	$	213	$	250	$	242

__________

(a)Excludes $50 million of sublease income recorded for each of the years ended December 31, 2025, 2024, and 2023.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2025		2024
Operating lease ROU assets(a)
Other deferred debits and other assets	$	371	$	436

Operating lease liabilities(a)
Other current liabilities	72		72
Other deferred credits and other liabilities	433		511
Total operating lease liabilities	$	505	$	583

__________

(a)The operating ROU assets and lease liabilities include $141 million and $241 million, respectively, related to contracted generation as of December 31, 2025, and $176 million and $289 million, respectively, as of December 31, 2024.

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows:


	As of December 31,
	2025		2024		2023
Weighted average remaining lease term	6.7		7.4		8.4
Weighted average discount rate	5.1	%	5.0	%	5.0	%

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2025:


2026	$	104
2027	104
2028	105
2029	103
2030	63
2031 and thereafter	159
Total lease payments	638
Less: Imputed interest	133
Operating lease liabilities	$	505

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of operating lease liabilities	$	90	$	87	$	102
ROU assets obtained in exchange for operating lease obligations	2		6		13

Lessor

We have operating leases for which we are the lessor. The significant types of operating leases are contracted generation and real estate. The following table outlines other terms and conditions of the lease agreements as of December 31, 2025.


			In Years
Remaining lease terms			1-15
Options to extend the term			5-20

The components of lease income were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease income	$	51	$	51	$	51
Variable lease income	231		244		248

The following table presents the lease payments we expect to receive over the remaining terms as of December 31, 2025:


2026	$	50
2027	50
2028	50
2029	48
2030	9
2031 and thereafter	29
Total	$	236

Leases

Lessee


			In Years
Remaining lease terms			1-30
Options to extend the term			2-30
Options to terminate within			2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease costs	$	104	$	105	$	96
Variable lease costs	109		145		146





Total lease costs(a)	$	213	$	250	$	242

__________

(a)Excludes $50 million of sublease income recorded for each of the years ended December 31, 2025, 2024, and 2023.

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2025		2024
Operating lease ROU assets(a)
Other deferred debits and other assets	$	371	$	436

Operating lease liabilities(a)
Other current liabilities	72		72
Other deferred credits and other liabilities	433		511
Total operating lease liabilities	$	505	$	583

__________

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows:


	As of December 31,
	2025		2024		2023
Weighted average remaining lease term	6.7		7.4		8.4
Weighted average discount rate	5.1	%	5.0	%	5.0	%

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2025:


2026	$	104
2027	104
2028	105
2029	103
2030	63
2031 and thereafter	159
Total lease payments	638
Less: Imputed interest	133
Operating lease liabilities	$	505

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of operating lease liabilities	$	90	$	87	$	102
ROU assets obtained in exchange for operating lease obligations	2		6		13

Lessor


			In Years
Remaining lease terms			1-15
Options to extend the term			5-20

The components of lease income were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease income	$	51	$	51	$	51
Variable lease income	231		244		248

The following table presents the lease payments we expect to receive over the remaining terms as of December 31, 2025:


2026	$	50
2027	50
2028	50
2029	48
2030	9
2031 and thereafter	29
Total	$	236

Consolidated Balance Sheets, Parent (Parenthetical) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Accumulated depreciation and amortization

$ 19,072

$ 18,088

Common Stock, Shares Issued, Not Disclosed

true

Common stock, par value (in dollars per share)

$ 0

Common stock, shares authorized (in shares)

1,000,000,000

Common stock, shares outstanding (in shares)

312,000,000

313,000,000

Total assets

^[1]

$ 57,249

$ 52,926

Total liabilities

^[1]

42,396

39,387

Variable Interest Entity, Primary Beneficiary

Total assets

4,684

4,473

Total liabilities

914

968

Variable Interest Entity, Primary Beneficiary | Nonrecourse

Total liabilities

914

968

Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

Total assets

$ 4,551

$ 4,318

[1]

Accounts Receivable - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Unbilled customer revenues	$ 1,305	$ 1,109
Proceeds from Sale of DPP		10,574	$ 8,097
Collection of DPP, net	0	10,217	7,340
Receivables sold	$ 4,204	280	$ 356
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
DPP reclassified		$ 1,529

Consolidated Statements of Operations and Comprehensive Income, Parent - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating revenues
Operating revenues	$ 25,533	$ 23,568	$ 24,918
Operating expenses
Purchased power and fuel	14,681	11,419	16,001
Operating and maintenance	6,159	6,159	5,685
Depreciation and amortization	985	1,123	1,096
Taxes other than income taxes	622	586	553
Total operating expenses	22,447	19,287	23,335
Gain (loss) on sales of assets and businesses	0	71	27
Operating income (loss)	3,086	4,352	1,610
Other income and (deductions)
Interest expense, net	(511)	(506)	(431)
Other, net	936	670	1,268
Total other income and (deductions)	425	164	837
Income (loss) before income taxes	3,511	4,516	2,447
Income tax (benefit) expense	1,187	774	859
Equity in income (losses) of unconsolidated affiliates	(1)	(4)	(11)
Net income (loss)	2,323	3,738	1,577
Net income (loss) attributable to noncontrolling interests	4	(11)	(46)
Net income (loss) attributable to membership interest	2,319	3,749	1,623
Other comprehensive income (loss), net of income taxes
Net income (loss)	2,323	3,738	1,577
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)	(4)	(4)
Actuarial loss reclassified to periodic cost	72	75	25
Pension and non-pension postretirement benefit plans valuation adjustment	(219)	(176)	(453)
Unrealized gain (loss) on cash flow hedges	7	4	(1)
Unrealized gain (loss) on foreign currency translation	21	(10)	2
Other comprehensive income (loss), net of income taxes	(123)	(111)	(431)
Comprehensive income (loss)	2,200	3,627	1,146
Comprehensive income (loss) attributable to noncontrolling interests	4	(11)	(46)
Comprehensive income (loss) attributable to membership interest	$ 2,196	$ 3,638	$ 1,192
Average shares of common stock outstanding:
Basic (in shares)	313	315	323
Assumed exercise and/or distributions of stock-based awards (in shares)	1	0	1
Diluted (in shares)	314	315	324
Earnings per average common share
Basic (in dollars per share)	$ 7.40	$ 11.91	$ 5.02
Diluted (in dollars per share)	$ 7.40	$ 11.89	$ 5.01

Government Assistance	12 Months Ended
Government Assistance	Dec. 31, 2025
Government Assistance [Abstract]
Government Assistance	Government Assistance Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. We evaluated and expect to meet the annual prevailing wage requirements at all of our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. In July 2025, Congress passed the OBBBA which affirmed the provisions of the nuclear PTC with no material changes. For the years ended December 31, 2025 and 2024, our Consolidated Statements of Operations and Comprehensive Income included an estimated nuclear PTC benefit in Operating revenues of approximately $320 million and $2,080 million, respectively. Our estimates require the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. The nuclear PTC continues to be the subject of additional guidance, from the U.S. Treasury and IRS, and may materially impact the total amount of the benefits we receive. Nuclear PTCs are initially recorded within Other deferred debits and other assets within the Consolidated Balance Sheets and reclassified as a reduction to Accounts payable and accrued expenses when used to reduce our federal income tax payable, or an increase in Cash and cash equivalents or Other current assets when sold, depending on the specific payment terms of each contract. There were no sales agreements for nuclear PTCs in 2025. In 2024, we executed agreements for the sale of $1,750 million of nuclear PTCs to unaffiliated third parties at a nominal discount, with approximately $1,570 million of cash proceeds received upon sale that were included within Cash flows from operating activities in our Consolidated Statements of Cash Flows. Cash received in 2025 on sale agreements executed in 2024 was approximately $95 million. Our Consolidated Balance Sheets reflected estimated nuclear PTCs of approximately $120 million within Other deferred debits and other assets as of December 31, 2025, and $185 million and $95 million within Other deferred debits and other assets, and within Other current assets, respectively, as of December 31, 2024. Additionally, during the years ended December 31, 2025 and 2024, we recognized a reduction to Accounts payable and accrued expenses of $375 million and $150 million, respectively, for estimated nuclear PTCs that we have utilized as a credit against our current federal income taxes payable. Many of the state-sponsored programs providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. As of December 31, 2025 and 2024, we have recognized approximately $1,190 million and $1,030 million, respectively, of estimated payables within Other deferred credits and other liabilities, Accounts payable and accrued expenses or as offsets to Accounts receivable, net in our Consolidated Balance Sheets associated with programs requiring refunds or pass through of the nuclear PTC. In general, we expect to remit refunds or pass-throughs of state-sponsored program compensation related to nuclear PTCs in the year following the filing of the related tax return. We recognized a reduction to net operating revenue of approximately $125 million and $50 million, respectively, associated with these programs in our Consolidated Statements of Operations and Comprehensive Income for the years ended December 31, 2025 and 2024. As with the actual amount of the nuclear PTC earned, any change resulting from additional guidance received may materially impact amounts due under state-sponsored programs.

Retirement Benefits - Target Allocation (Details)	Dec. 31, 2025	Dec. 31, 2024
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	100.00%	100.00%
OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	100.00%	100.00%
Equities \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	21.00%	21.00%
Equities \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	24.00%	20.00%
Fixed income \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	54.00%	54.00%
Fixed income \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	59.00%	66.00%
Alternative investments \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Total	25.00%	25.00%
Alternative investments \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Total	17.00%	14.00%

- 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

Debt and Credit Agreements - Summary of Outstanding Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Debt Instrument [Line Items]
Total long-term debt	$ 7,403	$ 8,474
Unamortized debt discount and premium, net	(1)	(4)
Unamortized debt issuance costs	(60)	(58)
Long-term debt due within one year	(92)	(1,028)
Long-term debt	7,250	7,384
Senior unsecured notes
Debt Instrument [Line Items]
Total long-term debt	$ 5,688	6,588
Senior unsecured notes \| Minimum
Debt Instrument [Line Items]
Rates	5.60%
Senior unsecured notes \| Maximum
Debt Instrument [Line Items]
Rates	6.50%
Tax-exempt notes
Debt Instrument [Line Items]
Total long-term debt	$ 412	435
Tax-exempt notes \| Minimum
Debt Instrument [Line Items]
Rates	4.10%
Tax-exempt notes \| Maximum
Debt Instrument [Line Items]
Rates	4.45%
Notes payable and other
Debt Instrument [Line Items]
Total long-term debt	$ 53	51
Notes payable and other \| Minimum
Debt Instrument [Line Items]
Rates	1.71%
Notes payable and other \| Maximum
Debt Instrument [Line Items]
Rates	6.10%
Fixed rates
Debt Instrument [Line Items]
Total long-term debt	$ 653	720
Fixed rates \| Minimum
Debt Instrument [Line Items]
Rates	2.29%
Fixed rates \| Maximum
Debt Instrument [Line Items]
Rates	6.00%
Variable rates
Debt Instrument [Line Items]
Total long-term debt	$ 597	$ 680
Variable rates \| Minimum
Debt Instrument [Line Items]
Rates	5.82%
Variable rates \| Maximum
Debt Instrument [Line Items]
Rates	6.76%

Income Taxes - Components of Income Tax Expense (Benefit) from Continuing Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Federal
Current	$ 764	$ 451	$ 392
Deferred	238	229	302
ITC amortization	(15)	(14)	(15)
State
Current	136	127	142
Deferred	50	(39)	(34)
Foreign
Current	14	(25)	72
Deferred	0	45	0
Total Income tax (benefit) expense	$ 1,187	$ 774	$ 859

Retirement Benefits - Remaining Service Period (Details)	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Pension Benefits
Defined Contribution Plan Disclosure [Line Items]
Pension plans	10 years	11 years
OPEB
Defined Contribution Plan Disclosure [Line Items]
Benefit Eligibility Age	8 years	8 years
Expected Retirement	9 years	9 years

Mergers, Acquisitions, and Dispositions	12 Months Ended
Mergers, Acquisitions, and Dispositions	Dec. 31, 2025
Mergers, Acquisitions, and Dispositions [Abstract]
Mergers, Acquisitions, and Dispositions	Mergers, Acquisitions, and Dispositions Acquisition of Calpine Corporation On January 7, 2026, we acquired all the outstanding equity interest of Calpine in a cash and stock transaction for a purchase price of approximately $22 billion. The merger consideration consisted of an aggregate of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash. In connection with the merger, the newly issued shares will be subject to a lock-up period which expires on June 30, 2026 for 50% of the shares and on June 30, 2027 for the remaining 50%. For information on the debt assumed as part of the transaction, see Note 16 — Debt and Credit Agreements. Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction, including the DOJ resolution. This resolution was the final regulatory clearance to complete the merger of Calpine and Constellation. The DOJ resolution requires that we divest five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. Four of these assets were already subject to FERC divestiture requirements. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the Calpine acquisition, i.e., by September 4, 2026. In January 2026, Calpine completed the divestiture of its minority ownership interest in the Gregory Power Plant as required under the terms of the DOJ resolution. We are taking steps to divest the remaining six power plants. In addition to operating a large generation fleet, Calpine also operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. The transaction will be accounted for as a business combination using the acquisition method of accounting and we will record the fair value of the assets acquired and liabilities assumed as of the acquisition date. We expect that the consideration transferred is greater than the fair value of the net assets acquired, and therefore we anticipate recording goodwill on the opening balance sheet. Due to the recency of the acquisition date, the preliminary acquisition valuation for the business combination is incomplete at this time. Disclosures related to the acquisition date fair value of the assets acquired and liabilities assumed, among other acquisition-related disclosures, will be included in our March 31, 2026 Form 10-Q. Fees incurred as part of the acquisition were not material to the Consolidated Statements of Operations and Comprehensive Income for the twelve months ended December 31, 2025. Acquisition of Joint Ownership in South Texas Project In November 2023, we completed the acquisition of NRG South Texas LP (renamed and converted as Constellation South Texas, LLC), which owns a 44% undivided ownership interest in the jointly-owned STP, a 2,645 MW, dual-unit nuclear plant located in Bay City, Texas. The consideration transferred was $1.66 billion. Other owners include City Public Service Board of San Antonio (CPS, 40%) and the City of Austin, Texas (Austin, 16%). This acquisition is complementary to and aligned strategically with our existing clean energy business operations. The operating revenues and results of operations for STP have been included in the Consolidated Statements of Operations and Comprehensive Income from the date of acquisition and were not material for the year ended December 31, 2023. The pro forma effects of this acquisition were not significant to our reported results for the period of acquisition. Accordingly, no pro forma financial information has been presented herein. In May 2024, we executed a settlement agreement with all parties (CPS/City of San Antonio, Austin, and NRG Energy, Inc.), resolving all litigation involving our purchase of the ownership interest in STP. The terms of the settlement include us selling a 2% ownership interest in STP to CPS at the same price and terms that we paid NRG Energy Inc. for our 44% interest. We are working towards closing the transaction which has already received regulatory approvals (including the NRC and PUCT). The terms of settlement are not expected to have a material impact on our results of operations and financial condition.

Audit Information	12 Months Ended
Audit Information	Dec. 31, 2025
Audit Information [Abstract]
Auditor Name	PricewaterhouseCoopers LLP
Auditor Location	Baltimore, Maryland
Auditor Firm ID	238

Property, Plant, and Equipment - Summary of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 41,546	$ 39,323
Less: accumulated depreciation	19,072	18,088
Property, plant, and equipment, net	22,474	21,235
Nuclear fuel - work in progress	1,674	1,485
Electric
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	33,253	32,156
Nuclear Fuel [Member]
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	6,298	5,894
Less: accumulated depreciation	2,622	2,447
CWIP
Property, Plant and Equipment [Line Items]
Total property, plant, and equipment	$ 1,995	$ 1,273

Supplemental Financial Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Depreciation, Amortization and Accretion, Net [Abstract]
PP&E	$ 967	$ 1,101	$ 1,073
Nuclear fuel	952	884	787
ARO accretion	647	655	596
Amortization of intangible assets, net(a)	18	22	23
Amortization of energy contract assets and liabilities	17	38	35
Total depreciation, amortization, and accretion	2,601	2,700	2,514
Cash paid during the year
Interest (net of amount capitalized)	412	375	264
Other non-cash operating activities
Other decommissioning-related activity	(463)	(485)	(534)
Energy-related options	(103)	32	183
Pension and non-pension postretirement benefit costs	152	107	47
Other	191	174	322
Total other non-cash operating activities	(223)	(172)	18
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	3,641	3,022	368
Restricted cash and cash equivalents	107	107	86
Total cash, restricted cash, and cash equivalents	3,748	3,129	454	$ 528
Constellation Energy Generation, LLC
Depreciation, Amortization and Accretion, Net [Abstract]
Total depreciation, amortization, and accretion	2,601	2,700	2,514
Other non-cash operating activities
Other decommissioning-related activity	(463)	(485)	(534)
Energy-related options	(103)	32	183
Pension and non-pension postretirement benefit costs	152	107	47
Other	110	128	260
Total other non-cash operating activities	(304)	(218)	(44)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents [Abstract]
Cash and cash equivalents	3,641	3,018	366
Restricted cash and cash equivalents	79	97	74
Total cash, restricted cash, and cash equivalents	$ 3,720	$ 3,115	$ 440	$ 501

Retirement Benefits (Tables)

12 Months Ended

Dec. 31, 2025

Retirement Benefits [Abstract]

Defined Benefit Plan, Plan with Projected Benefit Obligation in Excess of Plan Assets

The following tables provide a rollforward of the changes in the benefit obligations and plan assets for the years ended December 31, 2025 and 2024 for all plans combined:


	Pension Benefits				OPEB
	2025		2024		2025		2024
Change in benefit obligation:
Benefit obligation as of the beginning of the year	$	7,397	$	7,770	$	1,422	$	1,443
Service cost	84		90		18		17
Interest cost	408		391		78		72
Plan participants' contributions	—		—		30		24
Actuarial loss (gain), net	289		(269)		120		12
Reclassification to liabilities held for sale	—		(9)		—		(1)
Settlements	(3)		(13)		—		—
Gross benefits paid	(582)		(563)		(147)		(145)
Benefit obligation as of the end of year	$	7,593	$	7,397	$	1,521	$	1,422


	Pension Benefits				OPEB
	2025		2024		2025		2024
Change in plan assets:
Plan assets as of the beginning of year	$	6,317	$	6,687	$	598	$	692
Employer contributions	174		177		—		—
Plan participants' contributions	—		—		24		18
Actual return (loss) on plan assets	593		37		45		22
Reclassification to assets held for sale	—		(8)		—		—
Settlements	(3)		(13)		—		—
Gross benefits paid	(582)		(563)		(103)		(134)
Fair value of plan assets as of the end of year	$	6,499	$	6,317	$	564	$	598

Over (under) funded status (Plan assets less benefit obligations)	$	(1,094)	$	(1,080)	$	(957)	$	(824)

Schedule of Defined Benefit Plans Disclosures

We present our benefit obligations net of plan assets in our Consolidated Balance Sheets within the following line items:


	Pension Benefits				OPEB
	2025		2024		2025		2024

Other current liabilities	$	(22)	$	(9)	$	(52)	$	(20)
Pension and non-pension benefit obligations	(1,072)		(1,071)		(905)		(804)

The following table provides the ABO and fair value of plan assets for all pension plans with an ABO in excess of plan assets.


ABO in Excess of Plan Assets	December 31, 2025		December 31, 2024
ABO	$	(7,436)	$	(7,225)
Fair value of plan assets	6,499		6,317


	Pension Benefits				OPEB
	2025		2024		2025		2024
Changes in plan assets and benefit obligations recognized in AOCI:
Current year actuarial (gain) loss	$	186	$	202	$	109	$	33
Amortization of actuarial (loss) gain	(103)		(102)		8		9

Amortization of prior service (cost) credit	(1)		(1)		6		6
Settlements	(1)		(6)		—		—
Total recognized in AOCI	$	81	$	93	$	123	$	48


	Pension Benefits				OPEB
	2025		2024		2025		2024
Prior service (credit) cost	$	8	$	8	$	(11)	$	(18)
Actuarial (gain) loss	3,162		3,080		73		(43)
Total	$	3,170	$	3,088	$	62	$	(61)

The resulting average remaining service periods (in years) for pension and OPEB as of December 31, 2025 and 2024 were as follows:


	December 31, 2025	December 31, 2024
Pension plans	10	11
OPEB plans:
Benefit Eligibility Age	8	8
Expected Retirement	9	9


	Pension Benefits				OPEB
	December 31, 2025		December 31, 2024		December 31, 2025		December 31, 2024
Discount rate(a)	5.38	%	5.66	%	5.30	%	5.63	%
Investment crediting rate(b)	5.93	%	5.72	%	N/A		N/A
Rate of compensation increase(c)	4.25	%	4.25	%	4.25	%	4.25	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		9.00% initial, 5.00% ultimate		7.00% initial, 5.00% ultimate

__________

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Includes 4.25% average for the three-year period (2026-2028) and 3.75% average thereafter.

The following assumptions were used to determine the net periodic benefit cost for the plans for the years ended December 31, 2025 and 2024.


	Pension Benefits				OPEB
	2025		2024		2025		2024
Discount rate(a)	5.66	%	5.17	%	5.63	%	5.15	%
Investment crediting rate(b)	5.72	%	5.07	%	N/A		N/A
Expected return on plan assets(c)	6.50	%	6.50	%	6.00	%	6.50	%
Rate of compensation increase(d)	4.25	%	4.25	%	4.25	%	4.25	%
Mortality table	Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)		Pri-2012 table with MP-2021 improvement scale (adjusted)
Healthcare cost trend on covered charges	N/A		N/A		7.00% initial, 5.00% ultimate		Initial and ultimate rate of 5.00%

__________

(a)The discount rates above represent the blended rates used to calculate the majority of Constellation's pension and OPEB costs.

(b)The investment crediting rate above represents a weighted average rate.

(c)Applicable to our pension and OPEB plans with plan assets, with the OPEB rate representing a weighted average.

(d)Includes 4.25% average for the four-year period (2025-2028) and 3.75% average thereafter.

Estimated future benefit payments to participants over the next ten years in all pension and OPEB plans as of December 31, 2025 are as follows:


	Pension Benefits		OPEB
2026	$	595	$	125
2027	580		127
2028	598		127
2029	590		127
2030	590		126
2031 through 2035	2,848		608
Total estimated future benefits payments through 2035	$	5,801	$	1,240

Our pension and OPEB plan target asset allocations as of December 31, 2025 and 2024 were as follows:


	December 31, 2025				December 31, 2024
Asset Category	Pension Benefits		OPEB		Pension Benefits		OPEB
Equity securities	21	%	24	%	21	%	20	%
Fixed income securities	54	%	59	%	54	%	66	%
Alternative investments(a)	25	%	17	%	25	%	14	%
Total	100	%	100	%	100	%	100	%

__________

(a)Alternative investments include private equity, hedge funds, real assets, and private credit.

Calculation of Net Periodic Benefit Costs


	Pension Benefits						OPEB						Total Pension Benefits and OPEB
	2025		2024		2023		2025		2024		2023		2025		2024		2023
Components of net periodic benefit (credit) cost:
Service cost	$	84	$	90	$	89	$	18	$	17	$	16	$	102	$	107	$	105
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	408		391		404		78		72		76		486		463		480
Expected return on assets	(489)		(506)		(520)		(33)		(42)		(45)		(522)		(548)		(565)
Amortization of:
Prior service (credit) cost	1		1		1		(6)		(6)		(10)		(5)		(5)		(9)
Actuarial (gain) loss	103		102		48		(8)		(9)		(12)		95		93		36
Settlement charges	1		6		—		—		—		—		1		6		—

Non-service components of pension benefits & OPEB credit (cost)	24		(6)		(67)		31		15		9		55		9		(58)
Net periodic benefit (credit) cost	$	108	$	84	$	22	$	49	$	32	$	25	$	157	$	116	$	47

Schedule of Allocation of Plan Assets


	December 31, 2025				December 31, 2024
	Level 1		Level 2		Total		Level 1		Level 2		Total
Pension plan assets(a)
Cash equivalents	$	195	$	—	$	195	$	170	$	—	$	170
Equities(b)	1,053		—		1,053		1,041		—		1,041
Fixed income	847		1,862		2,709		675		1,795		2,470




Total assets measured at fair value	2,095		1,862		3,957		1,886		1,795		3,681
Assets measured at NAV	—		—		2,934		—		—		2,869
Pension plan assets subtotal	2,095		1,862		6,891		1,886		1,795		6,550

OPEB plan assets(a)
Cash equivalents	24		—		24		18		—		18
Equities	71		—		71		96		—		96





Fixed income	71		22		93		132		39		171




Total assets measured at fair value	166		22		188		246		39		285
Assets measured at NAV	—		—		374		—		—		309
OPEB plan assets subtotal	166		22		562		246		39		594
Total pension and OPEB plan assets(c)	$	2,261	$	1,884	$	7,453	$	2,132	$	1,834	$	7,144

__________

(a)See Note 17 — Fair Value of Financial Assets and Liabilities for a description of levels within the fair value hierarchy.

Pension And Other Postretirement Benefit Contributions

The following table provides our contributions paid to our qualified pension plans, non-qualified pension plans, and OPEB plans for the years ended December 31, 2025, 2024, and 2023:


	2025		2024		2023
Pension contributions(a)	$	174	$	177	$	26
OPEB contributions	37		7		28
Total contributions	$	211	$	184	$	54

__________

(a)Our annual qualified pension contributions were $161 million in 2025 and 2024. The benefit payments to the non-qualified pension plans in 2025 and 2024 were not material.

The following table provides our planned contributions to our qualified pension plans, non-qualified pension plans, and OPEB plans in 2026 (including our benefit payments related to unfunded plans):


	Qualified Pension Plans		Non-Qualified Pension Plans		OPEB		Total
Planned contributions	$	162	$	22	$	64	$	248

Stock-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2025

Share-Based Payment Arrangement [Abstract]

Share-based Payment Arrangement, Cost by Plan

The following table presents the stock-based compensation expense included in the Consolidated Statements of Operations and Comprehensive Income:


	For the Years Ended December 31,
	2025		2024		2023
Total stock-based compensation expense included in Operating and maintenance expense	$	385	$	332	$	178
Income tax benefit	(99)		(85)		(45)
Total after-tax stock-based compensation expense	$	286	$	247	$	133

Share-Based Payment Arrangement, Performance Shares, Activity

The following table summarizes our unvested performance share awards activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024	535,626	$	99.06
Granted	120,057	321.83
Change in performance	96,623	313.60

Forfeited	(3,812)	195.73
Undistributed vested awards(a)	(469,066)	332.97
Unvested at December 31, 2025	279,428	$	198.49

__________

(a)Represents performance share awards that vested but were not distributed to retirement-eligible employees during 2025 and 2024.

The following table summarizes the weighted average grant date fair value and the total fair value of performance share awards vested:


	December 31, 2025(a)		December 31, 2024(a)
Weighted average grant date fair value (per share)	$	321.83	$	127.03
Total fair value of performance shares vested	156		138

__________

The following table summarizes our unvested restricted stock unit activity:


	Shares	Weighted Average Grant Date Fair Value (per share)
Unvested at December 31, 2024	809,093	$	96.53
Granted	265,512	312.97
Vested	(437,388)	82.45
Forfeited	(11,067)	197.23
Undistributed vested awards(a)	(76,272)	271.03
Unvested at December 31, 2025	549,878	$	181.54

__________

(a)Represents restricted stock units that vested but were not distributed to retirement-eligible employees during 2025 and 2024.

The following table summarizes the weighted average grant date fair value and the total fair value of restricted stock units vested:


	December 31, 2025(a)		December 31, 2024(a)
Weighted average grant date fair value (per share)	$	312.97	$	134.18
Total fair value of restricted stock units vested	57		42

__________

Derivative Financial Instruments - Commodity Derivatives (Details)	12 Months Ended
	Dec. 31, 2025 MWh MMBTU shortTon	Dec. 31, 2024 MWh MMBTU shortTon
Electricity
Derivative [Line Items]
Total Volume \| MWh	(260)	(130)
Natural Gas
Derivative [Line Items]
Total Volume \| MMBTU	33	33
Emissions
Derivative [Line Items]
Total Volume \| shortTon	(35)	(18)

Asset Retirement Obligations - Non-Nuclear Asset Retirement Obligations Rollforward (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Accretion expense	$ 647	$ 655	$ 596
Nonnuclear Decommissioning Asset Retirement Obligation
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning balance	288	257
Other one-time charges	12	19
Accretion expense	17	15
Costs incurred related to decommissioning plants	0	(3)
Ending balance	$ 317	$ 288	$ 257

Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2025

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation Rollforward

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:


	2025		2024
Beginning balance as of January 1	$	12,186	$	13,891
Net increase (decrease) due to changes in, and timing of, estimated future cash flows	108		(2,299)
Accretion expense	630		640
Costs incurred related to decommissioning plants	(16)		(24)
Reclassification to liabilities held for sale(a)	—		(22)
Ending balance as of December 31	$	12,908	$	12,186

__________

The following table provides a rollforward of the non-nuclear AROs reflected in the Consolidated Balance Sheets from January 1, 2024 to December 31, 2025:


	2025		2024
Beginning balance as of January 1	$	288	$	257
Net increase due to changes in, and timing of, estimated future cash flows	12		19
Accretion expense	17		15

Costs incurred related to decommissioning plants	—		(3)

Ending balance as of December 31	$	317	$	288


	As of December 31,
	2025		2024
ComEd	$	4,313	$	3,780
PECO	442		247
CenterPoint	430		365
AEP Texas	149		126
Payables related to Regulatory Agreement Units	$	5,334	$	4,518

Consolidated Balance Sheets (Parenthetical) - USD ($)
$ in Millions

Dec. 31, 2025

Dec. 31, 2024

Accumulated depreciation and amortization

$ 19,072

$ 18,088

Total assets

^[1]

57,249

52,926

Total liabilities

^[1]

42,396

39,387

Variable Interest Entity, Primary Beneficiary

Total assets

4,684

4,473

Total liabilities

914

968

Variable Interest Entity, Primary Beneficiary | Nonrecourse

Total liabilities

914

968

Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

Total assets

4,551

4,318

Constellation Energy Generation, LLC

Accumulated depreciation and amortization

19,072

18,088

Total assets

^[2]

57,198

52,893

Total liabilities

^[2]

42,335

39,310

Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Nonrecourse

Total liabilities

914

968

Constellation Energy Generation, LLC | Variable Interest Entity, Primary Beneficiary | Asset Pledged as Collateral

Total assets

$ 4,551

$ 4,318

[1]

[2]

- Definition

Amount of asset recognized for present right to economic benefit.

+ References

+ Details

- Definition

Amount of liability recognized for present obligation requiring transfer or otherwise providing economic benefit to others.

+ References

+ Details

Consolidated Statements of Operations and Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Operating revenues
Operating revenues	$ 25,533	$ 23,568	$ 24,918
Operating expenses
Purchased power and fuel	14,681	11,419	16,001
Operating and maintenance	6,159	6,159	5,685
Depreciation and amortization	985	1,123	1,096
Taxes other than income taxes	622	586	553
Total operating expenses	22,447	19,287	23,335
Gain (loss) on sales of assets and businesses	0	71	27
Operating income (loss)	3,086	4,352	1,610
Other income and (deductions)
Interest expense, net	(511)	(506)	(431)
Other, net	936	670	1,268
Total other income and (deductions)	425	164	837
Income (loss) before income taxes	3,511	4,516	2,447
Income tax (benefit) expense	1,187	774	859
Equity in income (losses) of unconsolidated affiliates	(1)	(4)	(11)
Net income (loss)	2,323	3,738	1,577
Net income (loss) attributable to noncontrolling interests	4	(11)	(46)
Net income (loss) attributable to membership interest	2,319	3,749	1,623
Comprehensive income (loss), net of income taxes
Net income (loss)	2,323	3,738	1,577
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)	(4)	(4)
Actuarial loss reclassified to periodic benefit cost	72	75	25
Pension and non-pension postretirement benefit plans valuation adjustment	(219)	(176)	(453)
Unrealized gain (loss) on cash flow hedges	7	4	(1)
Unrealized gain (loss) on foreign currency translation	21	(10)	2
Other comprehensive income (loss), net of income taxes	(123)	(111)	(431)
Comprehensive income (loss)	2,200	3,627	1,146
Comprehensive income (loss) attributable to noncontrolling interests	4	(11)	(46)
Comprehensive income (loss) attributable to membership interest	2,196	3,638	1,192
Constellation Energy Generation, LLC
Operating revenues
Operating revenues	25,533	23,568	24,918
Operating expenses
Purchased power and fuel	14,681	11,419	16,001
Operating and maintenance	6,159	6,159	5,685
Depreciation and amortization	985	1,123	1,096
Taxes other than income taxes	622	586	553
Total operating expenses	22,447	19,287	23,335
Gain (loss) on sales of assets and businesses	0	71	27
Operating income (loss)	3,086	4,352	1,610
Other income and (deductions)
Interest expense, net	(511)	(506)	(431)
Other, net	936	670	1,268
Total other income and (deductions)	425	164	837
Income (loss) before income taxes	3,511	4,516	2,447
Income tax (benefit) expense	1,187	774	859
Equity in income (losses) of unconsolidated affiliates	(1)	(4)	(11)
Net income (loss)	2,323	3,738	1,577
Net income (loss) attributable to noncontrolling interests	4	(11)	(46)
Net income (loss) attributable to membership interest	2,319	3,749	1,623
Comprehensive income (loss), net of income taxes
Net income (loss)	2,323	3,738	1,577
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	(4)	(4)	(4)
Actuarial loss reclassified to periodic benefit cost	72	75	25
Pension and non-pension postretirement benefit plans valuation adjustment	(219)	(176)	(453)
Unrealized gain (loss) on cash flow hedges	7	4	(1)
Unrealized gain (loss) on foreign currency translation	21	(10)	2
Other comprehensive income (loss), net of income taxes	(123)	(111)	(431)
Comprehensive income (loss)	2,200	3,627	1,146
Comprehensive income (loss) attributable to noncontrolling interests	4	(11)	(46)
Comprehensive income (loss) attributable to membership interest	$ 2,196	$ 3,638	$ 1,192

Asset Retirement Obligations - Noncurrent Related Party Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	$ 5,334	$ 4,518
Affiliated Entities
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	5,334	4,518
Affiliated Entities \| ComEd
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	4,313	3,780
Affiliated Entities \| PECO
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	442	247
Affiliated Entities \| CenterPoint
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	430	365
Affiliated Entities \| AEP Texas
Asset Retirement Obligations [Line Items]
Payables related to Regulatory Agreement Units	$ 149	$ 126

Property, Plant, and Equipment

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2025 and 2024:


Asset Category	December 31, 2025		December 31, 2024
Electric	$	33,253	$	32,156
Nuclear fuel(a)	6,298		5,894
CWIP	1,995		1,273

Total property, plant, and equipment	41,546		39,323
Less: accumulated depreciation(b)	19,072		18,088
Property, plant, and equipment, net	$	22,474	$	21,235

__________

(a)Includes nuclear fuel that is in the fabrication and installation phase of $1,674 million and $1,485 million as of December 31, 2025 and 2024, respectively.

(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,622 million and $2,447 million as of December 31, 2025 and 2024, respectively.

The estimated useful lives of our generating facilities are based on a combination of depreciation studies, historical retirements, site licenses and management estimates of operating costs and expected energy market conditions. The estimated useful lives of our nuclear stations generally include expectations for an additional 20-year term beyond current license expiration, except for Calvert Cliffs, FitzPatrick, Limerick, NMP Unit 2, and STP where depreciation provisions correspond with the expiration of the current NRC operating license. The estimated useful lives of our hydroelectric facilities also generally align with their FERC operating licenses. Conowingo depreciation provisions are based on an estimated useful life through 2071, in anticipation that a 50-year license will be issued. Generally, our oil and gas plants have estimated useful lives of 40 to 45 years with wind and solar generating facilities having estimated useful lives of 25 and 35 years, respectively. See Note 3 — Regulatory Matters for additional information regarding license renewals for Peach Bottom and Conowingo.

Annual depreciation rates for electric generation were 2.91%, 3.43%, and 3.26% for the years ended December 31, 2025, 2024, and 2023, respectively. Nuclear fuel amortization is charged to fuel expense using the unit-of-production method based on the expected consumption period of the fuel, generally ranging from 1 to 8 years, and is excluded from the annual depreciation rates. See Note 22 — Supplemental Financial Information for additional information on nuclear fuel amortization.

Property, Plant, and Equipment (Tables)

12 Months Ended

Dec. 31, 2025

Property, Plant and Equipment [Abstract]

Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment by asset category as of December 31, 2025 and 2024:


Asset Category	December 31, 2025		December 31, 2024
Electric	$	33,253	$	32,156
Nuclear fuel(a)	6,298		5,894
CWIP	1,995		1,273

Total property, plant, and equipment	41,546		39,323
Less: accumulated depreciation(b)	19,072		18,088
Property, plant, and equipment, net	$	22,474	$	21,235

__________

(a)Includes nuclear fuel that is in the fabrication and installation phase of $1,674 million and $1,485 million as of December 31, 2025 and 2024, respectively.

(b)Includes accumulated amortization of nuclear fuel in the reactor core of $2,622 million and $2,447 million as of December 31, 2025 and 2024, respectively.

Leases (Tables)

12 Months Ended

Dec. 31, 2025

Leases [Abstract]

Components of Lease Cost

The following table outlines other terms and conditions of the lease agreements as of December 31, 2025. We did not have material finance leases in 2025, 2024, or 2023.


			In Years
Remaining lease terms			1-30
Options to extend the term			2-30
Options to terminate within			2

The components of operating lease costs were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease costs	$	104	$	105	$	96
Variable lease costs	109		145		146





Total lease costs(a)	$	213	$	250	$	242

__________

(a)Excludes $50 million of sublease income recorded for each of the years ended December 31, 2025, 2024, and 2023.

The weighted average remaining lease terms, in years, and the weighted average discount rates for operating leases were as follows:


	As of December 31,
	2025		2024		2023
Weighted average remaining lease term	6.7		7.4		8.4
Weighted average discount rate	5.1	%	5.0	%	5.0	%

The following table outlines other terms and conditions of the lease agreements as of December 31, 2025.


			In Years
Remaining lease terms			1-15
Options to extend the term			5-20

Supplemental Balance Sheet Information Related to Lessee Right-of-Use Assets and Lease Liabilities

The following table provides additional information regarding the presentation of operating lease ROU assets and lease liabilities in the Consolidated Balance Sheets:


	As of December 31,
	2025		2024
Operating lease ROU assets(a)
Other deferred debits and other assets	$	371	$	436

Operating lease liabilities(a)
Other current liabilities	72		72
Other deferred credits and other liabilities	433		511
Total operating lease liabilities	$	505	$	583

__________

Lessee, Operating Lease, Liability, Maturity

The following table reconciles the undiscounted cash flows for our operating leases to the operating lease liabilities recorded on our consolidated balance sheet as of December 31, 2025:


2026	$	104
2027	104
2028	105
2029	103
2030	63
2031 and thereafter	159
Total lease payments	638
Less: Imputed interest	133
Operating lease liabilities	$	505

Lessee, Operating Lease, Supplemental Cash Flow Information

Supplemental cash flow information related to operating leases was as follows:


	For the Years Ended December 31,
	2025		2024		2023
Cash paid for amounts included in the measurement of operating lease liabilities	$	90	$	87	$	102
ROU assets obtained in exchange for operating lease obligations	2		6		13

Components of Operating Lease Income

The components of lease income were as follows:


	For the Years Ended December 31,
	2025		2024		2023
Operating lease income	$	51	$	51	$	51
Variable lease income	231		244		248

Lessor, Operating Lease, Payment to be Received, Fiscal Year Maturity

The following table presents the lease payments we expect to receive over the remaining terms as of December 31, 2025:


2026	$	50
2027	50
2028	50
2029	48
2030	9
2031 and thereafter	29
Total	$	236

Property, Plant, and Equipment - Narrative (Details)		1 Months Ended
Property, Plant, and Equipment - Narrative (Details)	Mar. 06, 2020	Mar. 31, 2020	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Peach Bottom Units 2 and 3
Property, Plant and Equipment [Line Items]
Operating license renewal period	20 years	20 years
Conowingo Hydroelectric Project
Property, Plant and Equipment [Line Items]
Operating license renewal period		50 years
Oil and Gas Plant \| Minimum
Property, Plant and Equipment [Line Items]
Expected life			40 years
Oil and Gas Plant \| Maximum
Property, Plant and Equipment [Line Items]
Expected life			45 years
Wind and Solar Facilities \| Minimum
Property, Plant and Equipment [Line Items]
Expected life			25 years
Wind and Solar Facilities \| Maximum
Property, Plant and Equipment [Line Items]
Expected life			35 years
Electric
Property, Plant and Equipment [Line Items]
Annual depreciation rate			2.91%	3.43%	3.26%
Electric \| Minimum
Property, Plant and Equipment [Line Items]
Expected life			1 year
Electric \| Maximum
Property, Plant and Equipment [Line Items]
Expected life			8 years

Income Taxes - Tax Effects of Temporary Differences and Carryforwards (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Plant basis differences	$ (3,321)	$ (3,138)
Accrual-based contracts	(35)	(30)
Derivatives and other financial instruments	1,090	700
Deferred pension and postretirement obligation	(359)	(336)
Nuclear decommissioning activities	(187)	(256)
Tax loss carryforward	23	19
Tax loss carryforward valuation allowances	(3)	(3)
Investment in partnerships	(283)	(204)
Other, net	(160)	242
Deferred income tax liabilities (net)	(3,235)	(3,006)
Unamortized ITCs	(309)	(325)
Total deferred income tax liabilities (net) and unamortized ITCs	$ (3,544)	$ (3,331)

Consolidated Statements of Changes in Shareholders Equity, Parent - USD ($) $ in Millions	Total	Common Stock	Retained Earnings (Deficit)	Accumulated Other Comprehensive Income (Loss), net	Noncontrolling Interests
Beginning Balance (in shares) at Dec. 31, 2022		327,130,000
Beginning Balance at Dec. 31, 2022	$ 11,372	$ 13,274	$ (496)	$ (1,760)	$ 354
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	1,577		1,623		(46)
Employee incentive plans (in shares)		902,000
Employee incentive plans	81	$ 81
Changes in equity of noncontrolling interest	53				53
Common stock dividends	(366)		(366)
Common stock repurchased (in shares)		(10,560,000)
Common stock repurchased	(1,000)	$ (1,000)
Other comprehensive income (loss), net of income taxes	(431)			(431)
Ending Balance (in shares) at Dec. 31, 2023		317,472,000
Ending Balance at Dec. 31, 2023	11,286	$ 12,355	761	(2,191)	361
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	3,738		3,749		(11)
Employee incentive plans (in shares)		885,000
Employee incentive plans	56	$ 56
Changes in equity of noncontrolling interest	23				23
Common stock dividends	(444)		(444)
Common stock repurchased (in shares)		(5,519,000)
Common stock repurchased	(1,009)	$ (1,009)
Other comprehensive income (loss), net of income taxes	$ (111)			(111)
Ending Balance (in shares) at Dec. 31, 2024	313,000,000	312,838,000
Ending Balance at Dec. 31, 2024	$ 13,539	$ 11,402	4,066	(2,302)	373
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)	2,323		2,319		4
Employee incentive plans (in shares)		799,000
Employee incentive plans	39	$ 39
Changes in equity of noncontrolling interest	(41)				(41)
Common stock dividends	(486)		(486)
Common stock repurchased (in shares)		(1,282,000)
Common stock repurchased	(404)	$ (404)
Capped call option contracts	6	$ 6
Other comprehensive income (loss), net of income taxes	$ (123)			(123)
Ending Balance (in shares) at Dec. 31, 2025	312,000,000	312,355,000
Ending Balance at Dec. 31, 2025	$ 14,853	$ 11,043	$ 5,899	$ (2,425)	$ 336

Retirement Benefits - Accumulated Benefit Obligation (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Retirement Benefits [Abstract]
ABO	$ (7,436)	$ (7,225)
Fair value of plan assets	$ 6,499	$ 6,317

Commitments and Contingencies

12 Months Ended

Dec. 31, 2025

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commercial Commitments. Commercial commitments as of December 31, 2025, representing commitments potentially triggered by future events, were as follows:


	Expiration within
	2026		2027		2028		2029		2030		2031 and beyond		Total
Letters of credit	$	1,784	$	190	$	122	$	—	$	1	$	3	$	2,100
Surety bonds(a)	603		—		214		—		—		—		817
Total commercial commitments	$	2,387	$	190	$	336	$	—	$	1	$	3	$	2,917

__________

(a)Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.

Nuclear Insurance

We are subject to liability, property damage and other risks associated with major incidents at any of our nuclear stations. Our financial exposure to these risks is mitigated through insurance and other industry risk-sharing provisions.

The Price-Anderson Act was enacted to ensure the availability of funds for public liability claims arising from an incident at any of the U.S. licensed nuclear facilities and to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2025, the current liability limit per incident is $16.3 billion and is subject to change to account for the effects of inflation and changes in the number of licensed reactors at least once every five years with the last adjustment effective January 1, 2024. In accordance with the Price-Anderson Act, we maintain financial protection at levels equal to the amount of liability insurance available from private sources through the purchase of private nuclear energy liability insurance for public liability claims that could arise in the event of an incident. Effective January 1, 2024, the required amount of nuclear energy liability insurance purchased is $500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool, as required by the Price Anderson-Act, which could provide up to approximately an additional $15.8 billion per incident at any U.S. nuclear power reactor in funds available for public liability claims. Participation in this secondary financial protection pool requires the operator of each reactor to fund its proportionate share of costs for any single incident at any U.S. nuclear power reactor that exceeds the primary layer of financial protection. Our share of this secondary layer would be approximately $3.5 billion, based on our ownership interest in the insured nuclear reactors, however, any amounts payable under this secondary layer would be capped at $520 million per incident within one calendar year.

In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay public liability claims exceeding the $16.3 billion limit for a single incident.

We are required by the NRC to maintain minimal levels of property insurance that demonstrates to the satisfaction of the NRC that we possess an equivalent amount of protection covering the licensee's obligation, in the event of an accident at the licensee's reactor, to stabilize and decontaminate the reactor and the reactor station site at which the reactor experiencing the accident is located. The insurance maintained for each facility is currently provided through insurance policies purchased from NEIL, an industry mutual insurance company of which we are a member. Currently, the NRC requires that we maintain a minimum coverage limit for each reactor site of $1.06 billion, and we currently have coverage of $1.5 billion for each site.

NEIL may declare distributions to its members as a result of favorable operating experience. In recent years, NEIL has made distributions to its members. Our portion of the annual distribution declared by NEIL is estimated to be $114 million for 2025, and was $44 million and $59 million for 2024 and 2023, respectively. The distributions were recorded as a reduction to Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.

Premiums paid to NEIL by its members are also subject to a potential assessment for adverse loss experience in the form of a retrospective premium obligation. NEIL has never assessed this retrospective premium since its formation in 1973, and we cannot predict the level of future assessments, if any. The current maximum aggregate annual retrospective premium obligation for our interests is approximately $297 million. NEIL requires its

members to maintain an investment grade credit rating or to ensure collectability of their annual retrospective premium obligation by providing a financial guarantee, letter of credit, deposit premium, or some other means of assurance.

NEIL provides “all risk” property damage, decontamination, and premature decommissioning insurance for each station for losses resulting from damage to its nuclear plants, either due to accidents or acts of terrorism. If the decision is made to decommission the facility, a portion of the insurance proceeds will be allocated to a fund, which we are required by the NRC to maintain, to provide for decommissioning the facility. In the event of an insured loss, we are unable to predict the timing of the availability of insurance proceeds to us and the amount of such proceeds that would be available. In the event that one or more acts of terrorism cause accidental property damage within a twelve-month period from the first accidental property damage under one or more policies for all insured plants, the maximum recovery by us will be an aggregate of $3.2 billion plus such additional amounts as the insurer may recover for all such losses from reinsurance, indemnity and any other source, applicable to such losses.

For our insured losses, we are self-insured to the extent that losses are within the policy deductible or exceed the amount of insurance maintained. Uninsured losses and other expenses, to the extent not recoverable from insurers or the nuclear industry, could also be borne by us. Any such losses could have a material adverse effect on our consolidated financial statements.

Spent Nuclear Fuel Obligation

Under the Nuclear Waste Policy Act of 1982 (NWPA), the DOE is responsible for the development of a geologic repository for and the disposal of SNF and high-level radioactive waste. As required by the NWPA, we are a party to contracts with the DOE (Standard Contracts) to provide for disposal of SNF from our nuclear generating stations. In accordance with the NWPA and the Standard Contracts, we had previously paid the DOE one mill ($0.001) per kWh of net nuclear generation for the cost of SNF disposal. The DOE reduced the SNF disposal fee to zero in May 2014. Until a new fee structure is in effect, we will not accrue any further costs related to SNF disposal fees. This fee may be adjusted prospectively to ensure full cost recovery.

We currently assume the DOE will begin accepting SNF in 2040 and use that date for purposes of estimating the nuclear decommissioning AROs. The SNF acceptance date assumption is based on management’s estimate of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage.

The NWPA and the Standard Contracts required the DOE to begin taking possession of SNF generated by nuclear generating units no later than January 31, 1998. The DOE, however, failed to meet that deadline and its performance has been, and is expected to remain, delayed. In August 2004, we and the DOJ, in close consultation with the DOE, reached a settlement under which the government agreed to reimburse us, subject to certain damage limitations based on the extent of the government’s breach, for costs associated with storage of SNF at our nuclear stations pending the DOE’s fulfillment of its obligations. That settlement agreement does not expire until all SNF has been collected from the sites that it covers. Calvert Cliffs, Ginna, NMP, Fitzpatrick, and STP each have separate settlement agreements in place with the DOE which were extended during 2023 to provide for the reimbursement of SNF storage costs through December 31, 2025, and we are currently seeking a further extension. We and the DOE have the option to extend those settlements every three years upon mutual consent.

Under the settlement agreements, we received total cumulative cash reimbursements of $2,238 million through December 31, 2025 for costs incurred. After considering the amounts due to co-owners of certain nuclear stations and to the current owner of Oyster Creek Nuclear Generating Station, we received net cumulative cash reimbursements of $1,955 million. As of December 31, 2025 and 2024, the amount of SNF storage costs for

which reimbursement has been or will be requested from the DOE under the DOE settlement agreements is as follows:


	December 31, 2025		December 31, 2024
DOE receivable - current(a)	$	117	$	124
DOE receivable - noncurrent(b)	28		42
Amounts owed to co-owners(c)	(20)		(40)

__________

(a)Recorded in Accounts receivable, net.

(b)Recorded in Other deferred debits and other assets.

The Standard Contracts with the DOE also required the payment to the DOE of a one-time fee applicable to nuclear plants that generated SNF prior to April 7, 1983. The below table outlines the SNF liability, which is recorded within Other deferred credits and other liabilities, as of December 31, 2025 and 2024:


	December 31, 2025		December 31, 2024
Former ComEd units(a)	$	1,271	$	1,219
Fitzpatrick(b)	155		147
Total SNF Obligation	$	1,426	$	1,366

__________

Interest for our SNF liabilities accrues at the 13-week Treasury Rate. The 13-week Treasury Rate in effect for calculation of the interest accrual at December 31, 2025 and 2024 was 3.906% and 4.553%, respectively for the deferred amount transferred from ComEd, and 3.953% and 4.615%, respectively, for the deferred FitzPatrick amount.

The following table summarizes sites for which we do not have an outstanding SNF Obligation:


Description			Sites
Fees have been paid or began operations after April 7, 1983			Former PECO units, Braidwood, Byron, Calvert Cliffs, Clinton, LaSalle Unit 2, NMP Unit 2, and STP
Outstanding SNF Obligation remains with former owners			NMP Unit 1, Ginna, and Crane

Environmental Remediation Matters

General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us,

environmental agencies or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.

As of December 31, 2025 and 2024, we had accrued undiscounted amounts for environmental liabilities of $9 million and $60 million, respectively, in Accounts payable and accrued expenses and $169 million for both periods in Other deferred credits and other liabilities in the Consolidated Balance Sheets.

Cotter Corporation. The EPA has advised Cotter Corporation (N.S.L.) (Cotter), a former ComEd subsidiary, that it is potentially liable in connection with radiological contamination at two sites in Missouri. In 2000, ComEd sold Cotter to an unaffiliated third-party. As part of the sale, ComEd agreed to indemnify Cotter for any liability arising from these two Missouri superfund sites, West Lake Landfill and Latty Avenue. In connection with Exelon’s 2001 corporate restructuring, this responsibility to indemnify Cotter was transferred to us, and ultimately retained by us per the terms of our separation from Exelon. Refer to Note 1 — Basis of Presentation for additional information on the separation.

West Lake Landfill. Including Cotter, there are three PRPs currently participating in the West Lake Landfill remediation proceeding.

West Lake Landfill; Operable Unit 1 (OU1); Landfill Remediation. In September 2018, the EPA issued its Record of Decision Amendment (RODA) for the selection of a final remedy that requires partial excavation of the radiological materials and capping the landfill. The EPA and the PRPs have entered into a Consent Agreement to perform the Remedial Design, which is now expected to be completed in 2026. In March 2019, the PRPs received Special Notice Letters from the EPA to perform the Remedial Action work. The total estimated cost of the design, remedy, and operation and maintenance, considering the current EPA technical requirements, is approximately $560 million, including cost escalation on an undiscounted basis.

West Lake Landfill; Operable Unit 3 (OU3); Groundwater Study. In September 2018, the three identified PRPs, including Cotter, signed an Administrative Settlement Agreement and Order on Consent for the performance by the PRPs of the groundwater Remedial Investigation Feasibility Study (RI/FS). The purpose of this RI/FS is to define the nature and extent of any groundwater contamination from the West Lake Landfill site and evaluate remedial alternatives. We estimate the undiscounted cost for the groundwater RI/FS to be approximately $60 million. At this time we cannot predict the likelihood, or the extent to which remediation activities, if any, may be required and therefore cannot estimate a reasonably possible range of loss for response costs beyond those associated with the RI/FS component.

We determined a loss associated with the EPA's partial excavation and landfill cover remedy and the groundwater RI/FS is probable and have recorded a liability for each, both of which are included in the total amount as discussed above, that reflects management’s best estimate of Cotter’s allocable share of the cost among the PRPs. Given the joint and several nature of these two liabilities, the amount of our ultimate liability will depend on the actual costs incurred to implement the required remedy at OU1 and the required study at OU3, as well as on the nature and terms of any cost-sharing arrangements with the final group of PRPs. It is reasonably possible that the ultimate cost and Cotter's associated allocable share could differ significantly once these uncertainties are resolved, which could have a material impact on our results of operations and financial condition.

Latty Avenue and Vicinity Properties. In August 2011, Cotter was notified by the DOJ that Cotter is considered a PRP with respect to the government’s clean-up costs for contamination attributable to low-level radioactive residues at a former storage and reprocessing facility named Latty Avenue near St. Louis, Missouri.

Latty Avenue was investigated and remediated by the United States Army Corps of Engineers pursuant to funding under the Formerly Utilized Sites Remedial Action Program. The PRPs reached a settlement of this matter and the government filed a motion for entry of a Consent Decree, which was entered by the Court on January 24, 2025. Payment of $50 million plus statutory interest was made on January 30, 2025. The consent decree settles past and future responses costs incurred by the United States Army Corp of Engineers and DOE for their response actions conducted in connection with the release or threatened release of hazardous substances, including radioactive substances at Latty Avenue and certain additional adjacent properties.

Litigation

We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Beginning on February 15, 2021, our Texas-based generating assets within the ERCOT market, specifically Colorado Bend II, Wolf Hollow II, and Handley, experienced outages as a result of extreme cold weather conditions.

Various lawsuits have been filed against us since the February 2021 event and outages. In March 2021, we, along with more than 150 power generators and transmission and distribution companies, were sued by approximately 160 individually named plaintiffs, purportedly on behalf of all Texans who allegedly suffered loss of life or sustained personal injury, property damage, or other losses as a result of the weather events. The plaintiffs alleged that the defendants failed to properly prepare for the cold weather and failed to properly conduct their operations, seeking compensatory as well as punitive damages. Thereafter, numerous other plaintiffs filed multiple lawsuits against more than 300 defendants, including us, involving similar allegations of liability and claims of personal injury and property damage all arising out of the February weather events. These additional lawsuits allege wrongful death, property damage, or other losses. Co-defendants in these lawsuits include ERCOT, transmission and distribution utilities and other generators.

In December 2021, approximately 130 insurance companies which insured Texas homeowners and businesses filed a subrogation lawsuit against multiple defendants alleging that defendants were at fault for the energy failure that resulted from the winter storm, causing significant property damage to the insureds. Subsequently, several hundred other insurance companies filed similar claims. All of these cases were combined in a Multi-District-Litigation (MDL) pending in Texas state court, which established a bellwether process to consider initial motions to dismiss by the different industry groups of defendants. Defendants filed motions to dismiss the amended complaints in five bellwether cases in July 2022. In February 2023, the court granted the motions to dismiss pertaining to us in part and denied them in part, leaving the plaintiffs' negligence and nuisance claims to proceed. Since the motions to dismiss were partially denied, thousands of new claimants, many in multiple mass tort actions, filed lawsuits in various Texas state courts naming us, among hundreds of other defendants. The majority of these cases were transferred to the MDL. The MDL involves over 200 cases brought by approximately 30,000 plaintiffs, including more than 1,300 insurance companies, and we are defendants in the majority of them. We had also been named in an alleged class action that sought to assert claims on behalf of over 4.1 million Texans within ERCOT who lost power during Winter Storm Uri. The court subsequently denied certification of the class, and plaintiffs have not presently pursued on appeal.

In December 2023, the Court of Appeals for the First District of Texas granted the power generator defendants' Petition for a Writ of Mandamus in the five bellwether cases and ordered the MDL court to dismiss the remaining claims against the power generator defendants, including our entities. The motions to dismiss in the five bellwether cases are expected to be applied to all the claims against the power generator defendants in the MDL. In January 2024, plaintiffs filed motions for en banc reconsideration of the order with the full court of appeals in all five bellwether cases. In November 2024, the court denied plaintiffs' motions. In January 2025, plaintiffs petitioned the Supreme Court of Texas for mandamus review, requesting that the court reinstate the MDL court's denial of the generator defendants' motions to dismiss and thereby permit plaintiffs' claims to proceed. In June 2025, the court requested consolidated briefing on the merits in each of the five bellwether cases. The briefing concluded in February 2026, and the parties now await a decision from the court.

In addition to the cases pending in the MDL in Texas state court, in January 2025, the Attorney General of the State of Oklahoma filed a lawsuit in state court against us, along with 10 other defendants, alleging antitrust and consumer protection act violations as well as unjust enrichment in connection with the sale, transport and marketing of natural gas to state agencies, municipalities and the people of the state of Oklahoma during the extreme cold weather event. The Attorney General seeks compensatory and punitive damages. In March 2025,

defendants filed multiple motions to dismiss the lawsuit, which were denied by the court in August 2025. The parties are now engaged in discovery with trial likely to be scheduled in 2027.

We dispute liability and deny that we are responsible for any of plaintiffs’ alleged claims and are vigorously contesting them. No loss contingencies have been reflected in the consolidated financial statements with respect to these matters, nor can we currently estimate a range of loss. It is reasonably possible, however, that resolution of these matters could have a material, unfavorable impact on our consolidated financial statements.

Asbestos Personal Injury Claims. We maintain a reserve for claims associated with asbestos-related personal injury actions at certain facilities that are currently owned by us or were previously owned by ComEd, PECO, or BGE. The estimated liabilities are recorded on an undiscounted basis and exclude the estimated legal costs associated with handling these matters, which could be material.

At December 31, 2025 and 2024, we recorded estimated liabilities of approximately $120 million and $125 million, respectively, in total for asbestos-related bodily injury claims. These amounts are primarily included in Other deferred credits and other liabilities in the Consolidated Balance Sheets. Current amounts included in Accounts payable and accrued expenses are not material in either of the periods presented. As of December 31, 2025, approximately $17 million of this amount related to 251 open claims presented to us, while the remaining $103 million is for estimated future asbestos-related bodily injury claims anticipated to arise through 2055, based on actuarial assumptions and analyses, which are updated on an annual basis. On a quarterly basis, we monitor actual experience against the number of forecasted claims to be received and expected claim payments and evaluate whether adjustments to the estimated liabilities are necessary.

Commitments and Contingencies - Narrative (Details) $ in Millions		12 Months Ended
	Jan. 30, 2025 USD ($)	Dec. 31, 2025 USD ($) counterparty Open_claim	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Mar. 31, 2019 USD ($)	Sep. 30, 2018 USD ($)	Jan. 01, 2017 USD ($)
Commitments and Contingencies [Line Items]
Nuclear financial protection pool value							$ 500
Maximum recovery limit from a nuclear industry mutual insurance company in the event of multiple losses							15,800
Maximum annual assessment payment mandated by Price-Anderson Act for a nuclear incident							3,500
Maximum aggregate annual retrospective premium obligation		$ 297
Maximum recovery, aggregate		3,200
Total cumulative cash reimbursements		2,238
Net cumulative cash reimbursements		1,955
Asbestos-related bodily injury claims		120	$ 125
Accounts Payable and Accrued Liabilities
Commitments and Contingencies [Line Items]
Accrued undiscounted amounts, environmental liabilities		9	60
Other Liabilities
Commitments and Contingencies [Line Items]
Accrued undiscounted amounts, environmental liabilities		$ 169	$ 169
Former ComEd units
Commitments and Contingencies [Line Items]
Treasury interest rate		3.906%	4.553%
Fitzpatrick
Commitments and Contingencies [Line Items]
Treasury interest rate		3.953%	4.615%
West Lake
Commitments and Contingencies [Line Items]
Accrued undiscounted amounts, environmental liabilities					$ 560	$ 60
Number of potentially responsible parties \| counterparty		3
Payments	$ 50
Open Claims
Commitments and Contingencies [Line Items]
Asbestos-related bodily injury claims		$ 17
Open claims \| Open_claim		251
Estimated Future Claims
Commitments and Contingencies [Line Items]
Asbestos-related bodily injury claims		$ 103
Nuclear Insurance Premiums
Commitments and Contingencies [Line Items]
Nuclear insurance liability limit per incident		16,300
Minimum coverage limit		1,060
Limits purchased		1,500
Nuclear Insurance Premiums \| Maximum
Commitments and Contingencies [Line Items]
Nuclear financial protection pool value							$ 520
Guarantees Other Than Letters Of Credit and Nuclear Insurance Premiums
Commitments and Contingencies [Line Items]
Annual distribution, portion		$ 114	$ 44	$ 59

Derivative Financial Instruments - Narrative (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024
Economic Hedges
Derivative [Line Items]
Notational amount	$ 1,439	$ 592

Regulatory Matters (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
Regulatory Matters (Details) - USD ($) $ in Millions	Mar. 06, 2020	Mar. 31, 2020	Dec. 31, 2025
Regulatory Matters Additional Narrative Information [Line Items]
Cash benefits			$ 200
Minimum
Regulatory Matters Additional Narrative Information [Line Items]
Estimated financial impact			15
Maximum
Regulatory Matters Additional Narrative Information [Line Items]
Estimated financial impact			$ 20
Conowingo Hydroelectric Project
Regulatory Matters Additional Narrative Information [Line Items]
Operating license renewal period		50 years
Peach Bottom Units 2 and 3
Regulatory Matters Additional Narrative Information [Line Items]
Operating license renewal period	20 years	20 years

Retirement Benefits - Changes in Plan Assets Recognized in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	$ 186	$ 202
Amortization of actuarial (loss) gain	(103)	(102)
Amortization of prior service (cost) credit	(1)	(1)
Settlements	(1)	(6)
Total recognized in AOCI	81	93
Prior service (credit) cost	8	8
Actuarial (gain) loss	3,162	3,080
Total	3,170	3,088
OPEB
Defined Benefit Plan Disclosure [Line Items]
Current year actuarial (gain) loss	109	33
Amortization of actuarial (loss) gain	8	9
Amortization of prior service (cost) credit	6	6
Settlements	0	0
Total recognized in AOCI	123	48
Prior service (credit) cost	(11)	(18)
Actuarial (gain) loss	73	(43)
Total	$ 62	$ (61)

Supplemental Financial Information (Tables)

12 Months Ended

Dec. 31, 2025

Supplemental Financial Information [Abstract]

Schedule Of Taxes Excluding Income And Excise Taxes

The following tables provide additional information about material items recorded in the Consolidated Statements of Operations and Comprehensive Income.


	For the Years Ended December 31,
Taxes other than income taxes	2025		2024		2023
Property	$	289	$	285	$	253
Gross receipts(a)	163		134		139
Payroll	161		152		142
Other	9		15		19
Total	$	622	$	586	$	553

__________

Schedule of Other Nonoperating Income, by Component


	For the Years Ended December 31,
Other, net	2025		2024		2023
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	672	$	553	$	657
Non-Regulatory Agreement Units	322		266		335
Net unrealized gains (losses) on NDT funds
Regulatory Agreement Units	764		184		397
Non-Regulatory Agreement Units	506		156		259
Regulatory offset to NDT fund-related activities(b)	(1,152)		(592)		(845)
Total Decommissioning-related activities	1,112		567		803
Net unrealized gains (losses) from equity investments(c)	(304)		11		307

Other	128		92		158
Total Other, net	$	936	$	670	$	1,268

__________

(a)Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.

(b)Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units.

Cash Flow Supplemental Disclosures

The following tables provide additional information about material items recorded in the Consolidated Statements of Cash Flows.


		For the Years Ended December 31,
Depreciation, amortization and accretion	Income statement location	2025		2024		2023
PP&E	Depreciation and amortization	$	967	$	1,101	$	1,073
Nuclear fuel	Purchased power and fuel	952		884		787
ARO accretion	Operating and maintenance	647		655		596
Amortization of intangible assets, net(a)	Depreciation and amortization	18		22		23
Amortization of UECs	Operating revenues or Purchased power and fuel	17		38		35
Total depreciation, amortization, and accretion		$	2,601	$	2,700	$	2,514

__________

(a)Primarily related to the amortization of customer relationships and trade names. Excludes UEC amortization, which is shown separately in the table.


	For the Years Ended December 31,
Cash paid during the year	2025		2024		2023
Interest (net of amount capitalized)	$	412	$	375	$	264


	CEG Parent						Constellation
	For the Years Ended December 31,						For the Years Ended December 31,
Other non-cash operating activities	2025		2024		2023		2025		2024		2023
Other decommissioning-related activity(a)	$	(463)	$	(485)	$	(534)	$	(463)	$	(485)	$	(534)
Energy-related options(b)	(103)		32		183		(103)		32		183
Pension and non-pension postretirement benefit costs	152		107		47		152		107		47














Other	191		174		322		110		128		260
Total other non-cash operating activities	$	(223)	$	(172)	$	18	$	(304)	$	(218)	$	(44)

__________

(b)Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.


December 31, 2025	CEG Parent		Constellation
Cash and cash equivalents	$	3,641	$	3,641
Restricted cash and cash equivalents	107		79

Total cash, restricted cash, and cash equivalents	$	3,748	$	3,720


December 31, 2024
Cash and cash equivalents	$	3,022	$	3,018
Restricted cash and cash equivalents	107		97
Total cash, restricted cash, and cash equivalents	$	3,129	$	3,115


December 31, 2023
Cash and cash equivalents	$	368	$	366
Restricted cash and cash equivalents	86		74

Total cash, restricted cash, and cash equivalents	$	454	$	440

For additional information on restricted cash, see Note 1 — Basis of Presentation.

Supplemental Balance Sheet Information

The following tables provide additional information about material items recorded in the Consolidated Balance Sheets.


Inventories, net	December 31, 2025		December 31, 2024
Materials and supplies	$	1,485	$	1,357
Natural gas, oil, and emission allowances	251		243
Total	$	1,736	$	1,600


	Accounts payable and accrued expenses
December 31, 2025	CEG Parent		Constellation
Accounts payable	$	2,813	$	2,801
Compensation-related accruals(a)	920		672
Taxes accrued(b)	246		245
Other accrued expenses	315		315
Total	$	4,294	$	4,033


December 31, 2024
Accounts payable	$	2,369	$	2,348
Compensation-related accruals(a)	907		689
Taxes accrued(b)	232		223
Other accrued expenses	435		436
Total	$	3,943	$	3,696

__________

(a)Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.

The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets.


Investments	December 31, 2025		December 31, 2024
Equity method investments	$	3	$	2
Other investments:
Employee benefit trusts and investments(a)	112		100
Equity investments with readily determinable fair values(b)	82		387
Equity investments without readily determinable fair values	109		150
Other available for sale debt security investments	1		1
Total	$	307	$	640

__________

(a)Debt and equity security investments are recorded at fair market value.

Accounts Receivable

12 Months Ended

Dec. 31, 2025

Receivables [Abstract]

Accounts Receivable

The following table provides additional information on the disaggregation of customer and other accounts receivable:


	Accounts receivable, net
December 31, 2025	CEG Parent		Constellation
Customer accounts receivable (net of allowance for credit losses of $158 for CEG Parent and Constellation)	$	3,577	$	3,577
Other accounts receivable (net of allowance for credit losses of $9 for CEG Parent and Constellation)	689		674
Total	$	4,266	$	4,251


December 31, 2024
Customer accounts receivable (net of allowance for credit losses of $190 for CEG Parent and Constellation)	$	3,116	$	3,116
Other accounts receivable (net of allowance for credit losses of $6 for CEG Parent and Constellation)	602		587
Total	$	3,718	$	3,703

Allowance for Credit Losses on Accounts Receivable

The following table presents the rollforward of allowance for credit losses on customer accounts receivable from January 1, 2024 to December 31, 2025:


	2025		2024
Balance as of January 1	$	190	$	56
Current period provision for expected credit losses	47		17
Write-offs, net of recoveries(a)	(79)		(21)
Facility amendment impact(b)	—		138
Balance as of December 31	$	158	$	190

__________

(a)Recoveries were not material.

(b)Impact as a result of the December 2024 amendment of our revolving accounts receivable financing arrangement. See below for details.

The allowance for credit losses on other accounts receivable was not material as of the balance sheet dates, therefore, a rollforward is not presented.

Unbilled Customer Revenue

We recorded $1,305 million and $1,109 million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of December 31, 2025 and 2024, respectively.

Sales of Customer Accounts Receivable

In 2020, NER, a bankruptcy remote, special purpose entity, which is wholly owned by us, entered a revolving accounts receivable financing arrangement with a number of financial institutions and a commercial paper conduit (Purchasers) to sell certain customer accounts receivables (Facility). On December 31, 2024, we amended the Facility. We will no longer sell receivables to the Purchasers and all outstanding receivables were assigned back to us. Under the Facility's prior terms, NER sold eligible short-term customer accounts receivable to the Purchasers in exchange for cash and subordinated interest. The transfers were reported as sales of receivables in the consolidated financial statements. The subordinated interest in collections upon the receivables sold to the Purchasers is referred to as the DPP. As a result of the receivables being assigned back to NER under the amended Facility, NER forgave any and all remaining DPP owed by the Purchasers. The reassignment of receivables resulted in the recognition of $1,529 million of Accounts receivable, net as of December 31, 2024. See Note 16 — Debt and Credit Agreements for terms of the amended Facility.

The following table summarizes our cash proceeds associated with the Facility prior to the amendment:


	For the Years Ended December 31,
	2024		2023
Proceeds from new transfers(a)	$	1,688	$	3,649
Cash collections received on DPP(b)	10,517		8,140
Cash collections reinvested in the Facility	$	12,205	$	11,789

_________

(a)Customer accounts receivable sold into the Facility were $12,262 million and $11,746 million for the years ended December 31, 2024, and 2023, respectively.

(b)Does not include the $300 million and $800 million net cash payments to the Purchasers in 2024 and 2023, respectively, in order to reduce the outstanding borrowing amount under the Facility.

We previously recognized the cash proceeds received upon sale in Cash flows from operating activities within the Changes in Other assets and liabilities line in the Consolidated Statements of Cash Flows, which were ($10,574) million and ($8,097) million for the years ended December 31, 2024, and 2023, respectively. The collection and reinvestment of DPP was recognized in Cash flows from investing activities in the Collection of DPP, net line in the Consolidated Statements of Cash Flows, which was $10,217 million, and $7,340 million for the years ended December 31, 2024, and 2023, respectively.

See Note 21 — Variable Interest Entities for additional information on NER.

Other Sales of Customer Accounts Receivables

We are required, under supplier tariffs, to sell customer receivables to certain utility companies at a nominal discount. The total gross receivables sold were $4,204 million, $280 million, and $356 million for the years ended December 31, 2025, 2024, and 2023, respectively. Prior to the Facility amendment discussed in the preceding paragraphs, certain accounts receivable subject to these supplier tariffs were sold to the Purchasers under the Facility.

Variable Interest Entities (Tables)

12 Months Ended

Dec. 31, 2025

Variable Interest Entity [Abstract]

Consolidated VIEs - Assets and Liabilities

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of December 31, 2025 and 2024. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.


	December 31, 2025		December 31, 2024
Cash and cash equivalents	$	52	$	59
Restricted cash and cash equivalents	48		50
Accounts receivable, net	2,477		2,146
Inventories, net	13		13
Other current assets	29		38
Total current assets	2,619		2,306
Property, plant and equipment, net	1,942		2,025
Other deferred debits and other assets	123		142
Total assets(a)	$	4,684	$	4,473

Long-term debt due within one year	$	66	$	64
Accounts payable and accrued expenses	34		54
Other current liabilities	3		—
Total current liabilities	103		118
Long-term debt	578		642
Asset retirement obligations	231		206
Other deferred credits and other liabilities	2		2
Total deferred credits and other liabilities	233		208
Total liabilities	$	914	$	968

__________

(a)Our balances include unrestricted assets for current UEC assets of $17 million and $22 million, disclosed within other current assets in the table above and noncurrent UEC assets of $116 million and $133 million, disclosed within other noncurrent assets in the table above as of December 31, 2025 and 2024, respectively.

Schedule of Variable Interest Entities

As of December 31, 2025 and 2024, our consolidated VIEs included the following:

Consolidated VIE or VIE groups:

Reason entity is a VIE:

Reason we are the primary beneficiary:

CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.

The PPA contract absorbs variability through a performance guarantee.

We conduct all activities.

NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables.

Equity capitalization is insufficient to support its operations.

We conduct all activities.

As of December 31, 2025 and 2024, the unconsolidated VIEs consist of:

Unconsolidated VIE groups:

Reason entity is a VIE:

Reason we are not the primary beneficiary:

Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.

PPA contracts that absorb variability through fixed pricing.

We do not conduct the operational activities.

Schedule of Variable Interest Entities

The following table presents summary information about our unconsolidated VIE entities:


Commercial Agreement VIEs	December 31, 2025		December 31, 2024
Total assets(a)	$	711	$	617
Total liabilities(a)	95		42

Other ownership interests in VIE(a)	616		575

__________

(a)These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs. We do not have any exposure to loss as we do not have a carrying amount in the equity investment VIEs as of December 31, 2025 and 2024.

- Definition

Tabular disclosure of the significant judgments and assumptions made in determining whether a variable interest (as defined) held by the entity requires the variable interest entity (VIE) (as defined) to be consolidated and (or) disclose information about its involvement with the VIE, individually or in aggregate (as applicable); the nature of restrictions, if any, on the consolidated VIE's assets and on the settlement of its liabilities reported by an entity in its statement of financial position, including the carrying amounts of such assets and liabilities; the nature of, and changes in, the risks associated with involvement in the VIE; how involvement with the VIE affects the entity's financial position, financial performance, and cash flows; the lack of recourse if creditors (or beneficial interest holders) of the consolidated VIE have no recourse to the general credit of the primary beneficiary (if applicable); the terms of arrangements, giving consideration to both explicit arrangements and implicit variable interests, if any, that could require the entity to provide financial support to the VIE, including events or circumstances that could expose the entity to a loss; the methodology used by the entity for determining whether or not it is the primary beneficiary of the variable interest entity; the significant factors considered and judgments made in determining that the power to direct the activities of a VIE that most significantly impact the VIE's economic performance are shared (as defined); the carrying amounts and classification of assets and liabilities of the VIE included in the statement of financial position; the entity's maximum exposure to loss, if any, as a result of its involvement with the VIE, including how the maximum exposure is determined and significant sources of the entity's exposure to the VIE; a comparison of the carrying amounts of the assets and liabilities and the entity's maximum exposure to loss; information about any liquidity arrangements, guarantees, and (or) other commitments by third parties that may affect the fair value or risk of the entity's variable interest in the VIE; whether or not the entity has provided financial support or other support (explicitly or implicitly) to the VIE that it was not previously contractually required to provide or whether the entity intends to provide that support, including the type and amount of the support and the primary reasons for providing the support; and supplemental information the entity determines necessary to provide.

+ References + Details

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

Revenue from Contracts with Customers - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Jun. 30, 2025	Jun. 30, 2023	Dec. 31, 2025
Revenue from Contract with Customer [Abstract]
Average contract term			18 months
ZEC revenue recognized	$ 201	$ 218

Accounts Receivable - Balance Sheet Supplemental Information (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	$ 4,266	$ 3,718
Allowance for credit losses	158	190	$ 56
Customer accounts receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	3,577	3,116
Allowance for credit losses	158	190
Other accounts receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	689	602
Allowance for credit losses	9	6
Constellation Energy Generation, LLC
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	4,251	3,703
Constellation Energy Generation, LLC \| Customer accounts receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	3,577	3,116
Allowance for credit losses	158	190
Constellation Energy Generation, LLC \| Other accounts receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Total	674	587
Allowance for credit losses	$ 9	$ 6

Schedule II - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2025

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Valuation and Qualifying Accounts

Constellation Energy Corporation and Subsidiary Companies

Constellation Energy Generation, LLC and Subsidiary Companies

Schedule II – Valuation and Qualifying Accounts


			Additions and adjustments
Description	Balance at Beginning of Period		Charged to Costs and Expenses		Charged to Other Accounts		Deductions			Balance at End of Period
(In millions)
For the year ended December 31, 2025
Allowance for credit losses	$	196	$	49	$	1	$	(79)	(a)	$	167
Deferred tax valuation allowance	3		—		—		—			3
Reserve for obsolete materials	238		—		(1)		(22)			215
For the year ended December 31, 2024
Allowance for credit losses	$	61	$	18	$	138	$	(21)	(a)	$	196
Deferred tax valuation allowance	10		(7)		—		—			3
Reserve for obsolete materials	246		(4)		(4)		—			238
For the year ended December 31, 2023
Allowance for credit losses	$	51	$	25	$	—	$	(15)	(a)	$	61
Deferred tax valuation allowance	11		—		(1)		—			10
Reserve for obsolete materials	238		8		9		(9)			246

__________

(a)Write-offs, net of recoveries of individual accounts receivable.

Retirement Benefits - Narrative (Details) $ in Millions	12 Months Ended
Retirement Benefits - Narrative (Details) $ in Millions	Dec. 31, 2025 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2026
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Matching contributions to savings plan	$ 126	$ 117	$ 106
Pension Benefits
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Acquisition-related adjustment	$ 0	(9)
Actual long-term rate of return on plan assets	0.1010
Expected long-term rate of return on plan assets	0.0650
Pension Benefits \| Forecast
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term rate of return on plan assets				0.0650
OPEB
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Acquisition-related adjustment	$ 0	$ (1)
Actual long-term rate of return on plan assets	0.1010
Expected long-term rate of return on plan assets	0.0600
OPEB \| Forecast
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Expected long-term rate of return on plan assets				0.0600

Accounts Receivable - Purchases and Sales of Accounts Receivable (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Accounts, Notes, Loans and Financing Receivable [Line Items]
Proceeds from new transfers	$ 1,688	$ 3,649
Cash collections received on DPP and reinvested in the Facility	10,517	8,140
Cash collections reinvested in the Facility	12,205	11,789
Purchasers
Accounts, Notes, Loans and Financing Receivable [Line Items]
Cash collections received on DPP and reinvested in the Facility	300	800
Sale of Accounts Receivable
Accounts, Notes, Loans and Financing Receivable [Line Items]
Customer accounts receivable sold into the Facility	$ 12,262	$ 11,746

Asset Retirement Obligations - Narrative (Details) - USD ($) $ in Millions	1 Months Ended		12 Months Ended
	Jul. 31, 2023	Mar. 31, 2022	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Asset Retirement Obligations [Line Items]
Shortfall of decommissioning funds with recourse			$ 50
Percent of additional decommissioning shortfall with recourse			5.00%
Nuclear decommissioning trust funds			$ 19,336	$ 17,305
Historical five-year annual average pre-tax return on NDT funds			6.80%
Minimum
Asset Retirement Obligations [Line Items]
Number of years used in present value measurement			10 years
Estimated targeted annual pre-tax return on nuclear decommissioning funds			6.20%
Maximum
Asset Retirement Obligations [Line Items]
Number of years used in present value measurement			70 years
Estimated targeted annual pre-tax return on nuclear decommissioning funds			7.10%
Constellation Energy Generation, LLC
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			$ 19,336	17,305
Estimated annual after-tax return on nuclear decommissioning funds			2.00%
PECO Energy Co
Asset Retirement Obligations [Line Items]
Estimated annual after-tax return on nuclear decommissioning funds			3.00%
Nuclear Decommissioning
Asset Retirement Obligations [Line Items]
Net increase (decrease) due to changes in, and timing of, estimated future cash flows			$ 108	(2,299)
Net increase (decrease) due to changes in assumed retirement dates				(3,036)
Net decrease related to changes in timing assumptions				(154)
Net increase due to updated cost escalation rates and discount rates				891
Asset retirement obligation			$ 12,908	12,186	$ 13,891
NMP Unit 2
Asset Retirement Obligations [Line Items]
Percent of additional decommissioning shortfall with recourse			50.00%
Zion Station
Asset Retirement Obligations [Line Items]
Asset retirement obligation			$ 170	163
Nonnuclear Decommissioning Asset Retirement Obligation
Asset Retirement Obligations [Line Items]
Asset retirement obligation			317	288	$ 257
Nuclear Decommissioning Trust Fund Investments
Asset Retirement Obligations [Line Items]
Annual recovery	$ 1	$ 4
Assets, Total
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			19,396	17,321
Assets, Total \| Zion Station
Asset Retirement Obligations [Line Items]
Nuclear decommissioning trust funds			$ 67	$ 63

Shareholders' Equity - Schedule of Changes in AOCI (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	$ 13,539	$ 11,286	$ 11,372
Other comprehensive income (loss), net of income taxes	(123)	(111)	(431)
Ending Balance	14,853	13,539	11,286
Total
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(2,302)	(2,191)	(1,760)
OCI before reclassifications	(198)	(186)	(453)
Amounts reclassified from AOCI	75	75	22
Other comprehensive income (loss), net of income taxes	(123)	(111)	(431)
Ending Balance	(2,425)	(2,302)	(2,191)
Losses on Cash Flow Hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(6)	(10)	(9)
OCI before reclassifications	0	0	(2)
Amounts reclassified from AOCI	7	4	1
Other comprehensive income (loss), net of income taxes	7	4	(1)
Ending Balance	1	(6)	(10)
Pension and Non-Pension Postretirement Benefit Plan Items
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(2,262)	(2,157)	(1,725)
OCI before reclassifications	(219)	(176)	(453)
Amounts reclassified from AOCI	68	71	21
Other comprehensive income (loss), net of income taxes	(151)	(105)	(432)
Ending Balance	(2,413)	(2,262)	(2,157)
Foreign Currency Items
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Beginning Balance	(34)	(24)	(26)
OCI before reclassifications	21	(10)	2
Amounts reclassified from AOCI	0	0	0
Other comprehensive income (loss), net of income taxes	21	(10)	2
Ending Balance	$ (13)	$ (34)	$ (24)

- Definition

Amount after tax, before reclassification adjustments of other comprehensive income (loss).

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Amount after tax and reclassification adjustments of other comprehensive income (loss).

+ References

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Amount after tax of reclassification adjustments of other comprehensive income (loss).

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Amount of equity (deficit) attributable to parent and noncontrolling interest. Excludes temporary equity.

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-Paragraph 1
-Subparagraph (SX 210.6-04(19))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479170/946-210-S99-1

Reference 46: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 210
-Name Accounting Standards Codification
-Section S99
-Paragraph 2
-Subparagraph (SX 210.6-05(4))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479170/946-210-S99-2

Reference 47: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-09(4)(b))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-3

Reference 48: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-09(6))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-3

Reference 49: http://www.xbrl.org/2003/role/disclosureRef
-Topic 946
-SubTopic 220
-Name Accounting Standards Codification
-Section S99
-Paragraph 3
-Subparagraph (SX 210.6-09(7))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147479134/946-220-S99-3

Reference 50: http://www.xbrl.org/2003/role/disclosureRef
-Topic 505
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480008/505-10-S99-1

Reference 51: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 235
-SubTopic 10
-Name Accounting Standards Codification
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08(g)(1)(ii))
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147480678/235-10-S99-1

Reference 52: http://www.xbrl.org/2009/role/commonPracticeRef
-Topic 323
-SubTopic 10
-Name Accounting Standards Codification
-Section 50
-Paragraph 3
-Subparagraph (c)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481687/323-10-50-3

Reference 53: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 54: http://fasb.org/us-gaap/role/ref/legacyRef
-Name Accounting Standards Codification
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Reference 55: http://fasb.org/us-gaap/role/ref/legacyRef
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Reference 56: http://www.xbrl.org/2003/role/disclosureRef
-Topic 350
-SubTopic 60
-Name Accounting Standards Codification
-Section 65
-Paragraph 1
-Subparagraph (b)
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Reference 57: http://www.xbrl.org/2003/role/disclosureRef
-Topic 470
-SubTopic 20
-Name Accounting Standards Codification
-Section 65
-Paragraph 4
-Subparagraph (f)(3)
-Publisher FASB
-URI https://asc.fasb.org/1943274/2147481538/470-20-65-4

+ Details

Fair Value of Financial Assets and Liabilities - Fair Value Assets and Liabilities Measure on a Recurring Basis Gain Loss Included in Earnings (Details) - Level 3 - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	$ 317	$ 856
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(47)	(121)
Operating Revenues
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	(340)	(539)	$ 706
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	(172)	207	1,673
Purchased Power and Fuel
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	65	(293)	(503)
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	116	(333)	(479)
Other, net
Fair Value Assets and Liabilities Measured on a Recurring Basis Gain Loss Included in Earnings [Line Items]
Total gains (losses) included in net income	9	5	2
The amount of total gains (losses) included in income attributed to the change in unrealized losses related to assets and liabilities	$ 9	$ 5	$ 2

Retirement Benefits - Fair Value of Plan Assets (Details) - USD ($) $ in Millions	Dec. 31, 2025	Dec. 31, 2024	Dec. 31, 2023
Defined Benefit Plan Disclosure [Line Items]
Net liabilities excluded	$ 390	$ 229
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6,499	6,317	$ 6,687
Notational amount	2,509	2,635
OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	564	598	$ 692
Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	7,453	7,144
Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	6,891	6,550
Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	562	594
Total assets measured at fair value \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	3,957	3,681
Total assets measured at fair value \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	188	285
Level 1 \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,261	2,132
Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,095	1,886
Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	166	246
Level 2 \| Fair Value, Recurring
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,884	1,834
Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,862	1,795
Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	22	39
Assets measured at NAV \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,934	2,869
Assets measured at NAV \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	374	309
Cash equivalents \| Total assets measured at fair value \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	195	170
Cash equivalents \| Total assets measured at fair value \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	24	18
Cash equivalents \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	195	170
Cash equivalents \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	24	18
Cash equivalents \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Cash equivalents \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Equities \| Total assets measured at fair value \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,053	1,041
Equities \| Total assets measured at fair value \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	71	96
Equities \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,053	1,041
Equities \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	71	96
Equities \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Equities \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	0	0
Fixed income \| Total assets measured at fair value \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	2,709	2,470
Fixed income \| Total assets measured at fair value \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	93	171
Fixed income \| Level 1 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	847	675
Fixed income \| Level 1 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	71	132
Fixed income \| Level 2 \| Fair Value, Recurring \| Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	1,862	1,795
Fixed income \| Level 2 \| Fair Value, Recurring \| OPEB
Defined Benefit Plan Disclosure [Line Items]
Pension plan assets	$ 22	$ 39

Fair Value of Financial Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2025

Fair Value Disclosures [Abstract]

Fair Value of Financial Liabilities Recorded at Amortized Cost


	December 31, 2025								December 31, 2024
	Carrying Amount		Fair Value						Carrying Amount		Fair Value
			Level 2		Level 3		Total				Level 2		Level 3		Total
Long-Term Debt, including amounts due within one year	$	7,342	$	6,995	$	666	$	7,661	$	8,412	$	7,805	$	716	$	8,521
SNF Obligation(a)	1,426		1,406		—		1,406		1,366		1,278		—		1,278

__________

(a)SNF Obligation is included in Other deferred credits and other liabilities in the Consolidated Balance Sheets.

Assets and Liabilities Measured and Recorded at Fair Value on Recurring Basis


	As of December 31, 2025						As of December 31, 2024
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	42	$	—	$	—	$	42	$	120	$	—	$	—	$	120
NDT fund investments
Cash equivalents(b)	72		165		—		237		187		163		—		350
Equities	6,245		1,426		—		7,671		5,230		1,897		—		7,127






Fixed income	2,201		1,566		395		4,162		2,089		1,462		368		3,919
Private credit	—		—		132		132		—		—		134		134
Assets measured at NAV	—		—		—		7,194		—		—		—		5,791



NDT fund investments subtotal(c)	8,518		3,157		527		19,396		7,506		3,522		502		17,321
Rabbi trust investments	66		45		1		112		58		41		1		100




Investments in equities	87		—		—		87		389		—		—		389
Derivative assets
Economic hedges	1,114		7,449		3,830		12,393		1,278		5,306		2,641		9,225

Effect of netting and allocation of collateral	(889)		(6,853)		(3,256)		(10,998)		(1,097)		(4,790)		(2,123)		(8,010)
Derivative assets subtotal	225		596		574		1,395		181		516		518		1,215

Total assets measured at fair value	8,938		3,798		1,102		21,032		8,254		4,079		1,021		19,145

Liabilities
Derivative liabilities
Economic hedges	(1,148)		(8,021)		(4,062)		(13,231)		(1,222)		(5,462)		(2,778)		(9,462)

Effect of netting and allocation of collateral	1,065		7,657		3,628		12,350		1,180		5,157		2,259		8,596
Derivative liabilities subtotal	(83)		(364)		(434)		(881)		(42)		(305)		(519)		(866)
Deferred compensation obligation	—		(124)		—		(124)		—		(93)		—		(93)
Total liabilities measured at fair value	(83)		(488)		(434)		(1,005)		(42)		(398)		(519)		(959)
Total net assets	$	8,855	$	3,310	$	668	$	20,027	$	8,212	$	3,681	$	502	$	18,186

__________

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis

The following tables present the fair value reconciliation of Level 3 assets and liabilities measured at fair value on a recurring basis during the years ended December 31, 2025 and 2024:


	For the Year Ended December 31, 2025
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2025	$	502	$	(1)		$	1	$	502
Total realized / unrealized gains (losses)
Included in net income (loss)	9		(326)		(a)	—		(317)
Included in Payables related to Regulatory Agreement Units	19		—			—		19
Change in collateral	—		236			—		236
Purchases	—		84			—		84
Sales	—		(5)			—		(5)
Settlements	(4)		51			—		47
Transfers into Level 3	1		(47)		(b)	—		(46)
Transfers out of Level 3	—		148		(b)	—		148
Balance as of December 31, 2025	$	527	$	140		$	1	$	668
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2025	$	9	$	(56)		$	—	$	(47)


	For the Year Ended December 31, 2024
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2024	$	429	$	869		$	1	$	1,299
Total realized / unrealized gains (losses)
Included in net income (loss)	5		(861)		(a)	—		(856)
Included in Payables related to Regulatory Agreement Units	16		—			—		16
Change in collateral	—		(325)			—		(325)
Purchases	66		61			—		127
Sales	—		(83)			—		(83)
Settlements	(15)		29			—		14
Transfers into Level 3	1		44		(b)	—		45
Transfers out of Level 3	—		265		(b)	—		265
Balance as of December 31, 2024	$	502	$	(1)		$	1	$	502
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of December 31, 2024	$	5	$	(126)		$	—	$	(121)

__________

(a)Includes a reduction of ($219) million and ($706) million for realized gains due to the settlement of derivative contracts for the years ended December 31, 2025 and 2024, respectively.

Total Realized and Unrealized Gains (Losses) Included in Income for Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis


	Operating Revenues						Purchased Power and Fuel						Other, net
	2025		2024		2023		2025		2024		2023		2025		2024		2023
Total gains (losses) included in net income	$	(340)	$	(539)	$	706	$	65	$	(293)	$	(503)	$	9	$	5	$	2
Total unrealized gains (losses)	(172)		207		1,673		116		(333)		(479)		9		5		2

Fair Value Reconciliation of Level 3 Assets and Liabilities Measured at Fair Value on a Recurring Basis, Valuation Technique

The following table presents the significant inputs to the forward curve used to value these positions:


Type of trade	Fair Value as of December 31, 2025		Fair Value as of December 31, 2024		Valuation Technique	Unobservable Input	2025 Range & Arithmetic Average		2024 Range & Arithmetic Average
Level 3 Derivatives—Economic hedges(a)(b)	$	(232)	$	(137)	Discounted Cash Flow	Forward power price	$1.89 - $154	$52	$2.57 - $140	$49
						Forward gas price	$(0.46) - $15	$3.52	$2.09 - $15	$3.68
					Option Model	Volatility percentage	14% - 197%	59%	23% - 141%	57%

__________

(a)The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.

(b)The fair values do not include cash collateral posted (received) on Level 3 positions of $372 million and $136 million as of December 31, 2025 and 2024, respectively.

Variable Interest Entities

12 Months Ended

Dec. 31, 2025

Variable Interest Entity [Abstract]

Variable Interest Entities

As of December 31, 2025 and 2024, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.

Consolidated VIEs


	December 31, 2025		December 31, 2024
Cash and cash equivalents	$	52	$	59
Restricted cash and cash equivalents	48		50
Accounts receivable, net	2,477		2,146
Inventories, net	13		13
Other current assets	29		38
Total current assets	2,619		2,306
Property, plant and equipment, net	1,942		2,025
Other deferred debits and other assets	123		142
Total assets(a)	$	4,684	$	4,473

Long-term debt due within one year	$	66	$	64
Accounts payable and accrued expenses	34		54
Other current liabilities	3		—
Total current liabilities	103		118
Long-term debt	578		642
Asset retirement obligations	231		206
Other deferred credits and other liabilities	2		2
Total deferred credits and other liabilities	233		208
Total liabilities	$	914	$	968

__________

As of December 31, 2025 and 2024, our consolidated VIEs included the following:

Consolidated VIE or VIE groups:

Reason entity is a VIE:

Reason we are the primary beneficiary:

CRP - A collection of wind and solar project entities. We have a 51% equity ownership in CRP. See additional discussion below.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP.

Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.

We conduct the operational activities.

Antelope Valley - A solar generating facility, which is 100% owned by us. Antelope Valley sells all of its output to PG&E through a PPA.

The PPA contract absorbs variability through a performance guarantee.

We conduct all activities.

NER - A bankruptcy remote, special purpose entity which is 100% owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables.

Equity capitalization is insufficient to support its operations.

We conduct all activities.

CRP - CRP is a collection of wind and solar project entities and some of these project entities are VIEs that are consolidated by CRP. While we or CRP own 100% of the solar entities and 100% of the majority of the wind entities, it has been determined that the wholly owned solar and wind entities are VIEs because the entities' customers absorb price variability from the entities through fixed price power and/or REC purchase agreements. Additionally, for the wind entities that have minority interests, it has been determined that these entities are VIEs because the governance rights of some investors are not proportional to their financial rights. We are the primary beneficiary of these solar and wind entities that qualify as VIEs because we control operations and direct all activities of the facilities. There is limited recourse to us related to certain solar and wind entities.

In 2017, our interests in CRP were contributed to and are pledged for the CR nonrecourse debt project financing structure. Refer to Note 16 — Debt and Credit Agreements for additional information.

Unconsolidated VIEs

Our variable interests in unconsolidated VIEs generally include energy purchase and sale contracts. The carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to us for the deliveries associated with the current billing cycles under the commercial agreements.

As of December 31, 2025 and 2024, we had unconsolidated variable interests in several VIEs for which we were not the primary beneficiary.

The following table presents summary information about our unconsolidated VIE entities:


Commercial Agreement VIEs	December 31, 2025		December 31, 2024
Total assets(a)	$	711	$	617
Total liabilities(a)	95		42

Other ownership interests in VIE(a)	616		575

__________

As of December 31, 2025 and 2024, the unconsolidated VIEs consist of:

Unconsolidated VIE groups:

Reason entity is a VIE:

Reason we are not the primary beneficiary:

Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities.

PPA contracts that absorb variability through fixed pricing.

We do not conduct the operational activities.

Jointly-Owned Electric Plants (Tables)

12 Months Ended

Dec. 31, 2025

Public Utilities, Property, Plant and Equipment [Abstract]

Schedule of Jointly Owned Utility Plants

Our material undivided ownership interests in jointly-owned plants as of December 31, 2025 and 2024 were as follows:


	NMP Unit 2			Quad Cities			Peach Bottom			STP(a)			Salem
Operator	Constellation			Constellation			Constellation			STPNOC			PSEG Nuclear
Ownership interest	82.00		%	75.00		%	50.00		%	44.00		%	42.59		%
Our share as of December 31, 2025
Plant in service	$	1,119		$	1,324		$	1,590		$	1,064		$	842
Accumulated depreciation	363			852			752			98			402
CWIP	53			29			25			23			101
Our share as of December 31, 2024
Plant in service	$	1,122		$	1,294		$	1,570		$	1,040		$	791
Accumulated depreciation	327			840			721			52			387
CWIP	27			13			15			25			68