Constellation Energy - 10-Q quarterly report FY2026 Q2

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q


☒			QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended June 30, 2026


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission
File Number

Name of Registrant; State or Other Jurisdiction of Incorporation; Address of Principal Executive Offices; and Telephone Number

IRS Employer Identification Number

001-41137

CONSTELLATION ENERGY CORPORATION

87-1210716

(a Pennsylvania corporation)

1310 Point Street

Baltimore, Maryland 21231-3380

(833) 883-0162

333-85496

CONSTELLATION ENERGY GENERATION, LLC

23-3064219

(a Pennsylvania limited liability company)

200 Energy Way

Kennett Square, Pennsylvania 19348-2473

(833) 883-0162

Securities registered pursuant to Section 12(b) of the Act:

Title of each class

Trading Symbol(s)

Name of each exchange on which registered

CONSTELLATION ENERGY CORPORATION:

Common Stock, without par value

CEG

The Nasdaq Stock Market LLC

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Constellation Energy Corporation

Yes

☐

Constellation Energy Generation, LLC

Yes

☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ý No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Constellation Energy Corporation

Large Accelerated Filer

Accelerated Filer

☐

Non-accelerated Filer

☐

Smaller Reporting Company

☐

Emerging Growth Company

☐

Constellation Energy Generation, LLC

Large Accelerated Filer

☐

Accelerated Filer

☐

Non-accelerated Filer

Smaller Reporting Company

☐

Emerging Growth Company

☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x

The number of shares outstanding of each registrant’s common stock as of July 31, 2026 was as follows:


Constellation Energy Corporation Common Stock, without par value			354,307,379
Constellation Energy Generation, LLC			Not applicable

TABLE OF CONTENTS


		Page No.
GLOSSARY OF TERMS AND ABBREVIATIONS		1
FILING FORMAT		4
CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION		4
AVAILABLE INFORMATION		4
PART I	FINANCIAL INFORMATION	4
ITEM 1.	FINANCIAL STATEMENTS	4
	Constellation Energy Corporation
	Consolidated Statements of Operations and Comprehensive Income	5
	Consolidated Statements of Cash Flows	6
	Consolidated Balance Sheets	7
	Consolidated Statements of Changes in Equity	8
	Constellation Energy Generation, LLC
	Consolidated Statements of Operations and Comprehensive Income	10
	Consolidated Statements of Cash Flows	11
	Consolidated Balance Sheets	12
	Consolidated Statements of Changes in Equity	13
	Combined Notes to Consolidated Financial Statements
	1. Basis of Presentation	14
	2. Mergers, Acquisitions, and Dispositions	14
	3. Regulatory Matters	18
	4. Revenue from Contracts with Customers	19
	5. Segment Information	21
	6. Government Assistance	23
	7. Accounts Receivable	24
	8. Property, Plant, and Equipment	26
	9. Asset Retirement Obligations	26
	10. Income Taxes	28
	11. Retirement Benefits	30
	12. Derivative Financial Instruments	30
	13. Debt and Credit Agreements	35
	14. Fair Value of Financial Assets and Liabilities	41
	15. Commitments and Contingencies	46

	16. Shareholders' Equity	47
	17. Variable Interest Entities	49
	18. Supplemental Financial Information	51

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Constellation Energy Corporation and Related Entities
CEG Parent						Constellation Energy Corporation
Constellation						Constellation Energy Generation, LLC
Registrants						CEG Parent and Constellation, collectively
Antelope Valley						Antelope Valley Solar Ranch One
Calpine						Calpine Corporation
Calvert Cliffs						Calvert Cliffs nuclear generating station
CCFC						Calpine Construction Finance Company, L.P.
CDHI						Calpine Development Holdings, LLC

Continental Wind						Continental Wind LLC

Crane						Crane Clean Energy Center (formerly known as Three Mile Island Unit 1)
CRP						Constellation Renewables Partners, LLC
FitzPatrick						James A. FitzPatrick nuclear generating station

GPC						Geysers Power Company, LLC
Greenfield L.P.						Greenfield Energy Centre L.P.
LaSalle						LaSalle nuclear generating station
Limerick						Limerick nuclear generating station
NER						NewEnergy Receivables LLC
Nine Mile Point						Nine Mile Point nuclear generating station
Nova Power						Nova Power, LLC
Pin Oak Creek						Pin Oak Creek Energy Center
RPG						Renewable Power Generation, LLC

STP						South Texas Project nuclear generating station


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
AB						Assembly Bill



AEP Texas						American Electric Power Texas
AESO						Alberta Electric Systems Operator

AOCI						Accumulated Other Comprehensive Income (Loss)

ARC						Asset Retirement Cost
ARO						Asset Retirement Obligation


ASR						Accelerated Share Repurchase











CAISO						California ISO










CenterPoint						CenterPoint Energy Houston Electric, LLC











CMC						Carbon Mitigation Credit
CO2						Carbon Dioxide
CODM						Chief Operating Decision Maker








ComEd						Commonwealth Edison Company
CORRA						Canadian Overnight Repo Rate Average
CWIP						Construction Work In Progress


DOE						United States Department of Energy


DOJ						United States Department of Justice





EGU						Electric Generating Units



EFOF						Equivalent Forced Outage Factor


ERCOT						Electric Reliability Council of Texas
ERISA						Employee Retirement Income Security Act of 1974, as amended







Exchange Act						Securities Exchange Act of 1934, as amended

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
Exelon						Exelon Corporation



FERC						Federal Energy Regulatory Commission
Former ComEd Units						Braidwood, Byron, Dresden, LaSalle and Quad Cities nuclear generating units
Former PECO Units						Limerick, Peach Bottom, and Salem nuclear generating units
FRCC						Florida Reliability Coordinating Council

GAAP						Generally Accepted Accounting Principles in the United States
GDP						Gross Domestic Product
Geysers Assets						Geothermal power plant assets acquired through Calpine, including steam extraction and gathering assets
GHG						Greenhouse Gas

GW						Gigawatt
GWh						Gigawatt hour
Heat Rate						A measure of the amount of fuel required to produce a unit of power


ICE						Intercontinental Exchange
IPA						Illinois Power Agency
IRA						Inflation Reduction Act of 2022

IRS						Internal Revenue Service
ISO						Independent System Operator
ISO-NE						ISO New England Inc.
ITC						Investment Tax Credit











MISO						Midcontinent Independent System Operator, Inc.
MMBtu						Million British thermal units
Moody's						Moody’s Investors Service, Inc.



MW						Megawatt
MWh						Megawatt hour



NASDAQ						Nasdaq Stock Market, LLC
NAV						Net Asset Value
NDT						Nuclear Decommissioning Trust


NERC						North American Electric Reliability Corporation
NGX						Natural Gas Exchange, Inc.



Non-Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are not subject to contractual elimination under regulatory accounting

NOx						Nitrogen oxide


NPNS						Normal Purchase Normal Sale scope exception
NRC						Nuclear Regulatory Commission


NYISO						New York ISO
NYMEX						New York Mercantile Exchange


OCI						Other Comprehensive Income
OIESO						Ontario Independent Electricity System Operator
OPEB						Other Postretirement Employee Benefits





PECO						PECO Energy Company
Pension Protection Act						Pension Protection Act of 2006
PG&E						Pacific Gas and Electric Company
PJM						PJM Interconnection, LLC
PPA						Power Purchase Agreement
PP&E						Property, Plant, and Equipment

Table of Contents


GLOSSARY OF TERMS AND ABBREVIATIONS
Other Terms and Abbreviations
PSDAR						Post-shutdown Decommissioning Activities Report
PSEG						Public Service Enterprise Group Incorporated
PTC						Production Tax Credit







Regulatory Agreement Units						Nuclear generating units or portions thereof whose decommissioning-related activities are subject to contractual elimination under regulatory accounting (includes the Former ComEd Units, the Former PECO Units and STP)






RNF						Operating Revenues Net of Purchased Power and Fuel Expense





RPM						Reliability Pricing Model
RTO						Regional Transmission Organization
S&P						S&P Global Ratings, a Standard & Poor’s Financial Services LLC business
SB						Senate Bill

SEC						United States Securities and Exchange Commission
SERC						SERC Reliability Corporation (formerly Southeast Electric Reliability Council)

SNF						Spent Nuclear Fuel
SO2						Sulfur dioxide

SOFR						Secured Overnight Financing Rate




SPP						Southwest Power Pool


STPNOC						STP Nuclear Operating Company

TMA						Tax Matters Agreement




TWh						Terawatt-hour

U.S. Treasury						U.S. Department of the Treasury
UEC						Unamortized Energy Contract



VIE						Variable Interest Entity
WECC						Western Electric Coordinating Council
ZEC						Zero Emission Credit

Table of Contents

FILING FORMAT

This combined Form 10-Q is being filed separately by Constellation Energy Corporation and Constellation Energy Generation, LLC, (the Registrants). Information contained herein relating to any individual Registrant is filed by the Registrant on its own behalf. Neither Registrant makes any representation as to information relating to the other Registrant.

CAUTIONARY STATEMENTS REGARDING FORWARD-LOOKING INFORMATION

This report contains certain forward-looking statements within the meaning of the Private Securities Litigation Reform Act of 1995 that are subject to risks and uncertainties. Words such as “could,” “may,” “expects,” “anticipates,” “will,” “targets,” “goals,” “projects,” “intends,” “plans,” “believes,” “seeks,” “estimates,” “predicts,” and variations on such words, and similar expressions that reflect our current views with respect to future events and operational, economic, and financial performance, are intended to identify such forward-looking statements. These forward-looking statements include, but are not limited to, statements regarding the acquisition of Calpine Corporation, the pro forma combined company and its operations, strategies and plans, enhancements to investment-grade credit profile, synergies, opportunities and anticipated future performance and capital structure, and expected accretion to earnings per share and free cash flow. Information adjusted for the acquisition should not be considered a forecast of future results.

Forward-looking statements are based on current expectations, estimates and assumptions that involve a number of risks and uncertainties that could cause actual results to differ materially from those projected. The factors that could cause actual results to differ materially from the forward-looking statements made by us include those factors discussed herein, as well as the items discussed in (1) the Registrants' combined 2025 Annual Report on Form 10-K in (a) Part I, ITEM 1A. Risk Factors, (b) Part II, ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part II, ITEM 8. Financial Statements and Supplementary Data: Note 18 — Commitments and Contingencies; (2) this Quarterly Report on Form 10-Q in (a) Part II, ITEM 1A. Risk Factors, (b) Part I, ITEM 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations, and (c) Part I, ITEM 1. Financial Statements: Note 15 — Commitments and Contingencies; and (3) other factors discussed in filings with the SEC by the Registrants.

Readers are cautioned not to place undue reliance on these forward-looking statements, which apply only as of the date of this report. Neither Registrant undertakes any obligation to publicly release any revision to its forward-looking statements to reflect events or circumstances after the date of this report.

AVAILABLE INFORMATION

The SEC maintains an Internet site at www.sec.gov that contains reports, proxy and information statements, and other information that we file electronically with the SEC. We file our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports with the SEC. In addition, as soon as reasonably practicable after such materials are furnished to the SEC, we make copies of these documents available to the public free of charge through our website at www.ConstellationEnergy.com. Information contained on our website shall not be deemed incorporated into, or to be a part of, this report.

PART I. FINANCIAL INFORMATION


ITEM 1. FINANCIAL STATEMENTS

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions, except per share data)	2026		2025		2026		2025
Operating revenues	$	7,504	$	6,101	$	18,626	$	12,889



Operating expenses
Purchased power and fuel	4,023		3,132		10,375		7,516

Operating and maintenance	2,253		1,617		4,033		3,162

Depreciation and amortization	443		254		886		502
Taxes other than income taxes	207		147		436		307
Total operating expenses	6,926		5,150		15,730		11,487

Gain (loss) on sales of assets	2		—		16		—

Operating income (loss)	580		951		2,912		1,402
Other income and (deductions)
Interest expense, net	(283)		(118)		(536)		(264)

Other, net	603		440		649		286
Total other income and (deductions)	320		322		113		22
Income (loss) before income taxes	900		1,273		3,025		1,424
Income tax (benefit) expense	398		440		928		462
Equity in income (losses) of unconsolidated affiliates	6		—		14		—
Net income (loss)	508		833		2,111		962
Net income (loss) attributable to noncontrolling interests	(5)		(6)		8		5
Net income (loss) attributable to common shareholders	$	513	$	839	$	2,103	$	957
Comprehensive income (loss), net of income taxes
Net income (loss)	$	508	$	833	$	2,111	$	962
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	—		(2)		(1)		(2)
Actuarial loss reclassified to periodic cost	26		18		54		35
Pension and non-pension postretirement benefit plan valuation adjustment	—		—		(25)		(34)
Unrealized gain (loss) on cash flow hedges	2		1		3		3
Unrealized gain (loss) on foreign currency translation	(1)		20		(4)		28
Other comprehensive income (loss), net of income taxes	27		37		27		30
Comprehensive income (loss)	535		870		2,138		992
Comprehensive income (loss) attributable to noncontrolling interests	(5)		(6)		8		5
Comprehensive income (loss) attributable to common shareholders	$	540	$	876	$	2,130	$	987

Average shares of common stock outstanding:
Basic	360		314		357		314
Assumed exercise and/or distributions of stock-based awards	—		—		—		—
Diluted	360		314		357		314

Earnings per average common share
Basic	$	1.42	$	2.67	$	5.89	$	3.05
Diluted	$	1.42	$	2.67	$	5.88	$	3.05

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
(In millions)	2026		2025
Cash flows from operating activities
Net income (loss)	$	2,111	$	962
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and contract amortization	2,368		1,300


Deferred income taxes and amortization of ITCs	740		14
Net fair value changes related to derivatives	(589)		188
Net realized and unrealized (gains) losses on NDT funds	(419)		(336)
Net realized and unrealized (gains) losses on equity investments	24		275
Other non-cash operating activities	(240)		(21)
Changes in assets and liabilities:
Accounts receivable	307		208

Inventories	(63)		17
Accounts payable and accrued expenses	(1,277)		(229)
Option premiums received (paid), net	(52)		18
Collateral received (posted), net	(357)		(242)
Income taxes	13		209
Pension and non-pension postretirement benefit contributions	(200)		(181)
Other assets and liabilities	(813)		(598)
Net cash flows provided by (used in) operating activities	1,553		1,584
Cash flows from investing activities
Capital expenditures	(2,521)		(1,573)
Proceeds from NDT fund sales	4,737		3,830
Investment in NDT funds	(4,911)		(3,999)
Acquisition of Calpine, net of cash and restricted cash acquired	(2,537)		—



Other investing activities	131		(16)
Net cash flows provided by (used in) investing activities	(5,101)		(1,758)
Cash flows from financing activities
Change in short-term borrowings	2,586		—
Proceeds from short-term borrowings with maturities greater than 90 days	4,500		900
Repayments of short-term borrowings with maturities greater than 90 days	(3,500)		—
Issuance of long-term debt	5,001		—
Retirement of long-term debt	(5,352)		(1,008)
Dividends paid on common stock	(309)		(244)
Repurchases of common stock	(1,971)		(400)
Other financing activities	(78)		(141)
Net cash flows provided by (used in) financing activities	877		(893)
Increase (decrease) in cash, restricted cash, and cash equivalents	(2,671)		(1,067)
Cash, restricted cash, and cash equivalents at beginning of period	3,748		3,129
Cash, restricted cash, and cash equivalents at end of period	$	1,077	$	2,062

Supplemental disclosure of non-cash investing and financing activities
Common stock issued for acquisition of Calpine	$	17,507	$	—

Exchange of Calpine senior notes for Constellation senior notes	2,290		—

Decrease in PP&E related to ARO update	(868)		(6)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	June 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	697	$	3,641
Restricted cash and cash equivalents	380		107
Accounts receivable, net	4,661		4,266


Derivative assets	2,167		945


Inventories, net	3,368		1,736




Renewable energy credits	784		789
Assets held for sale	5,743		126
Other	1,165		509
Total current assets	18,965		12,119
Property, plant, and equipment (net of accumulated depreciation and amortization of $19,589 and $19,072, respectively)	41,228		22,474
Deferred debits and other assets

Nuclear decommissioning trust funds	20,492		19,336

Goodwill	11,527		420
Derivative assets	1,741		450





Other	4,300		2,450
Total deferred debits and other assets	38,060		22,656
Total assets(a)	$	98,253	$	57,249

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	5,226	$	1,650
Long-term debt due within one year	363		92

Accounts payable and accrued expenses	4,432		4,294



Derivative liabilities	716		467

Renewable energy credit obligation	927		1,075


Other	1,368		366
Total current liabilities	13,032		7,944
Long-term debt	19,111		7,250


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	8,513		3,544
Asset retirement obligations	12,612		13,193
Pension and non-pension postretirement benefit obligations	1,844		1,977



Payables related to Regulatory Agreement Units	5,914		5,334
Derivative liabilities	601		414


Other	4,304		2,740
Total deferred credits and other liabilities	33,788		27,202
Total liabilities(a)	65,931		42,396
Commitments and contingencies (Note 15)

Shareholders' equity
Common stock (No par value, 1,000 shares authorized, 355 and 312 shares outstanding, respectively)	26,683		11,043
Retained earnings (deficit)	7,692		5,899
Accumulated other comprehensive income (loss), net	(2,398)		(2,425)
Total shareholders' equity	31,977		14,517
Noncontrolling interests	345		336
Total equity	32,322		14,853
Total liabilities and shareholders' equity	$	98,253	$	57,249

__________

(a)Our consolidated assets include $4,197 million and $4,551 million at June 30, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,287 million and $914 million at June 30, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity

(Unaudited)


	Six Months Ended June 30, 2026
	Shareholders' Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2025	312,355	$	11,043	$	5,899	$	(2,425)	$	336	$	14,853
Net income (loss)	—	—		1,590		—		13		1,603
Employee incentive plans	628	24		—		—		—		24
Changes in equity of noncontrolling interests	—	—		—		—		(12)		(12)
Common stock dividends ($0.4265/common share)	—	—		(155)		—		—		(155)

Common stock issued to acquire Calpine	49,376	17,507		—		—		—		17,507

Balance, March 31, 2026	362,359	$	28,574	$	7,334	$	(2,425)	$	337	$	33,820
Net income (loss)	—	—		513		—		(5)		508
Employee incentive plans	81	71		—		—		—		71
Changes in equity of noncontrolling interests	—	—		—		—		(21)		(21)
Common stock dividends ($0.4265/common share)	—	—		(155)		—		—		(155)
Common stock repurchased	(7,138)	(1,971)		—		—		—		(1,971)

Sale of noncontrolling interests	—	9		—		—		34		43
Other comprehensive income (loss), net of income taxes	—	—		—		27		—		27
Balance, June 30, 2026	355,302	$	26,683	$	7,692	$	(2,398)	$	345	$	32,322

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Corporation and Subsidiary Companies

Consolidated Statements of Changes in Equity

(Unaudited)


	Six Months Ended June 30, 2025
	Shareholders' Equity
(In millions, shares in thousands)	Issued Shares	Common Stock		Retained Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2024	312,838	$	11,402	$	4,066	$	(2,302)	$	373	$	13,539
Net income (loss)	—	—		118		—		11		129
Employee incentive plans	547	(49)		—		—		—		(49)
Changes in equity of noncontrolling interests	—	—		—		—		(6)		(6)
Common stock dividends ($0.3878/common share)	—	—		(122)		—		—		(122)

Capped call option contracts	—	(150)		—		—		—		(150)
Other comprehensive income (loss), net of income taxes	—	—		—		(7)		—		(7)
Balance, March 31, 2025	313,385	$	11,203	$	4,062	$	(2,309)	$	378	$	13,334
Net income (loss)	—	—		839		—		(6)		833
Employee incentive plans	117	37		—		—		—		37
Changes in equity of noncontrolling interests	—	—		—		—		(15)		(15)
Common stock dividends ($0.3878/common share)	—	—		(122)		—		—		(122)
Common stock repurchased	(1,099)	(404)		—		—		—		(404)
Capped call option contracts	—	103		—		—		—		103
Other comprehensive income (loss), net of income taxes	—	—		—		37		—		37
Balance, June 30, 2025	312,403	$	10,939	$	4,779	$	(2,272)	$	357	$	13,803

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Operations and Comprehensive Income

(Unaudited)


	Three Months Ended June 30,				Six Months Ended June 30,
(In millions)	2026		2025		2026		2025
Operating revenues	$	7,504	$	6,101	$	18,626	$	12,889



Operating expenses
Purchased power and fuel	4,023		3,132		10,375		7,516

Operating and maintenance	2,253		1,617		4,033		3,162

Depreciation and amortization	443		254		886		502
Taxes other than income taxes	207		147		436		307
Total operating expenses	6,926		5,150		15,730		11,487

Gain (loss) on sales of assets	2		—		16		—


Operating income (loss)	580		951		2,912		1,402
Other income and (deductions)
Interest expense, net	(283)		(118)		(536)		(264)

Other, net	603		440		649		286
Total other income and (deductions)	320		322		113		22
Income (loss) before income taxes	900		1,273		3,025		1,424
Income tax (benefit) expense	398		440		928		462
Equity in income (losses) of unconsolidated affiliates	6		—		14		—
Net income (loss)	508		833		2,111		962
Net income (loss) attributable to noncontrolling interests	(5)		(6)		8		5
Net income (loss) attributable to membership interest	$	513	$	839	$	2,103	$	957
Comprehensive income (loss), net of income taxes
Net income (loss)	$	508	$	833	$	2,111	$	962
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost	—		(2)		(1)		(2)
Actuarial loss reclassified to periodic cost	26		18		54		35
Pension and non-pension postretirement benefit plan valuation adjustment	—		—		(25)		(34)
Unrealized gain (loss) on cash flow hedges	2		1		3		3
Unrealized gain (loss) on foreign currency translation	(1)		20		(4)		28
Other comprehensive income (loss), net of income taxes	27		37		27		30
Comprehensive income (loss)	535		870		2,138		992
Comprehensive income (loss) attributable to noncontrolling interests	(5)		(6)		8		5
Comprehensive income (loss) attributable to membership interest	$	540	$	876	$	2,130	$	987

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended June 30,
(In millions)	2026		2025
Cash flows from operating activities
Net income (loss)	$	2,111	$	962
Adjustments to reconcile net income (loss) to net cash flows provided by (used in) operating activities
Depreciation, amortization, and accretion, including nuclear fuel and contract amortization	2,368		1,300


Deferred income taxes and amortization of ITCs	740		14
Net fair value changes related to derivatives	(589)		188
Net realized and unrealized (gains) losses on NDT funds	(419)		(336)
Net realized and unrealized (gains) losses on equity investments	24		275
Other non-cash operating activities	(304)		(70)
Changes in assets and liabilities:
Accounts receivable	310		208
Receivables from and payables to affiliates, net	(240)		(118)
Inventories	(63)		17
Accounts payable and accrued expenses	(1,291)		(238)
Option premiums received (paid), net	(52)		18
Collateral received (posted), net	(357)		(242)
Income taxes	13		209
Pension and non-pension postretirement benefit contributions	(200)		(181)
Other assets and liabilities	(536)		(504)
Net cash flows provided by (used in) operating activities	1,515		1,502
Cash flows from investing activities
Capital expenditures	(2,521)		(1,573)
Proceeds from NDT fund sales	4,737		3,830
Investment in NDT funds	(4,911)		(3,999)


Acquisition of Calpine, net of cash and restricted cash acquired	(2,537)		—

Other investing activities	133		(16)
Net cash flows provided by (used in) investing activities	(5,099)		(1,758)
Cash flows from financing activities
Change in short-term borrowings	2,586		—
Proceeds from short-term borrowings with maturities greater than 90 days	4,500		900
Repayments of short-term borrowings with maturities greater than 90 days	(3,500)		—
Issuance of long-term debt	5,001		—
Retirement of long-term debt	(5,352)		(1,008)
Distributions to member	(2,280)		(793)
Contributions from member	—		103
Other financing activities	(57)		(21)
Net cash flows provided by (used in) financing activities	898		(819)
Increase (decrease) in cash, restricted cash, and cash equivalents	(2,686)		(1,075)
Cash, restricted cash, and cash equivalents at beginning of period	3,720		3,115
Cash, restricted cash, and cash equivalents at end of period	$	1,034	$	2,040

Supplemental disclosure of non-cash investing and financing activities

Acquisition of Calpine	$	17,503	$	—
Exchange of Calpine senior notes for Constellation senior notes	2,290		—
Decrease in PP&E related to ARO update	(868)		(6)

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Balance Sheets

(Unaudited)


(In millions)	June 30, 2026		December 31, 2025
ASSETS
Current assets
Cash and cash equivalents	$	681	$	3,641
Restricted cash and cash equivalents	353		79
Accounts receivable, net	4,643		4,251


Derivative assets	2,167		945



Inventories, net	3,368		1,736




Renewable energy credits	784		789
Assets held for sale	5,743		126
Other	1,173		508
Total current assets	18,912		12,075
Property, plant, and equipment (net of accumulated depreciation and amortization of $19,589 and $19,072, respectively)	41,228		22,474
Deferred debits and other assets

Nuclear decommissioning trust funds	20,492		19,336

Goodwill	11,527		420
Derivative assets	1,741		450





Other	4,293		2,443
Total deferred debits and other assets	38,053		22,649
Total assets(a)	$	98,193	$	57,198

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings	$	5,226	$	1,650
Long-term debt due within one year	363		92

Accounts payable and accrued expenses	4,315		4,033
Payables to affiliates	134		365



Derivative liabilities	716		467

Renewable energy credit obligation	927		1,075

Other	1,366		358
Total current liabilities	13,047		8,040
Long-term debt	19,111		7,250


Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs	8,513		3,544
Asset retirement obligations	12,612		13,193
Pension and non-pension postretirement benefit obligations	1,844		1,977


Payables related to Regulatory Agreement Units	5,914		5,334
Derivative liabilities	601		414


Other	4,265		2,583
Total deferred credits and other liabilities	33,749		27,045
Total liabilities(a)	65,907		42,335
Commitments and contingencies (Note 15)

Equity
Member’s equity
Membership interest	25,737		10,144
Undistributed earnings (deficit)	8,602		6,808
Accumulated other comprehensive income (loss), net	(2,398)		(2,425)
Total member’s equity	31,941		14,527
Noncontrolling interests	345		336
Total equity	32,286		14,863
Total liabilities and equity	$	98,193	$	57,198

__________

(a)Our consolidated assets include $4,197 million and $4,551 million as of June 30, 2026 and December 31, 2025, respectively, of certain VIEs that can only be used to settle the liabilities of the VIE. Our consolidated liabilities include $1,287 million and $914 million as of June 30, 2026 and December 31, 2025, respectively, of certain VIEs for which the VIE creditors do not have recourse to us. See Note 17 — Variable Interest Entities for additional information.

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies

Consolidated Statements of Changes in Equity
(Unaudited)


	Six Months Ended June 30, 2026
	Member's Equity
(In millions)	Membership Interest		Undistributed Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2025	$	10,144	$	6,808	$	(2,425)	$	336	$	14,863
Net income (loss)	—		1,590		—		13		1,603
Changes in equity of noncontrolling interests	—		—		—		(12)		(12)
Distributions to member	—		(155)		—		—		(155)
Contribution from member	30		—		—		—		30
Acquisition of Calpine	17,503		—		—		—		17,503

Balance, March 31, 2026	$	27,677	$	8,243	$	(2,425)	$	337	$	33,832
Net income (loss)	—		513		—		(5)		508
Changes in equity of noncontrolling interests	—		—		—		(21)		(21)
Contribution from member	22		—		—		—		22
Distributions to member	(1,971)		(154)		—		—		(2,125)
Sale of noncontrolling interests	9		—		—		34		43
Other comprehensive income (loss), net of income taxes	—		—		27		—		27
Balance, June 30, 2026	$	25,737	$	8,602	$	(2,398)	$	345	$	32,286


	Six Months Ended June 30, 2025
	Member's Equity
(In millions)	Membership Interest		Undistributed Earnings (Deficit)		Accumulated Other Comprehensive Income (Loss), net		Noncontrolling Interests		Total Equity
Balance, December 31, 2024	$	10,538	$	4,974	$	(2,302)	$	373	$	13,583
Net income (loss)	—		118		—		11		129
Changes in equity of noncontrolling interests	—		—		—		(6)		(6)
Distributions to member	(150)		(122)		—		—		(272)
Other comprehensive income (loss), net of income taxes	—		—		(7)		—		(7)
Balance, March 31, 2025	$	10,388	$	4,970	$	(2,309)	$	378	$	13,427
Net income (loss)	—		839		—		(6)		833
Changes in equity of noncontrolling interests	—		—		—		(15)		(15)
Contribution from member	103		—		—		—		103
Distributions to member	(400)		(121)		—		—		(521)
Other comprehensive income (loss), net of income taxes	—		—		37		—		37
Balance, June 30, 2025	$	10,091	$	5,688	$	(2,272)	$	357	$	13,864

See the Combined Notes to Consolidated Financial Statements

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

1. Basis of Presentation

Description of Business

We are the nation's largest producer of clean and reliable energy and a leading supplier of energy products and services. Our fleet of generation assets includes nuclear, natural gas, oil, hydroelectric, geothermal, wind, and solar facilities. 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 six reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine.

Basis of Presentation

The accompanying Consolidated Financial Statements as of June 30, 2026 and for the three and six months ended June 30, 2026 and 2025 are unaudited but, in our opinion, include all adjustments that are considered necessary for a fair statement of the results for the periods reported herein in accordance with GAAP. All adjustments are of a normal, recurring nature, unless otherwise disclosed. The Consolidated Financial Statements include the accounts of our subsidiaries and all intercompany transactions have been eliminated in consolidation. Our December 31, 2025 Consolidated Balance Sheet was derived from audited financial statements. The interim financial statements are to be read in conjunction with prior annual financial statements and notes. Financial results for interim periods are not necessarily indicative of results that may be expected for any other interim period or for the fiscal year ending December 31, 2026. These Combined Notes to Consolidated Financial Statements have been prepared pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q. Certain information and note disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted pursuant to such rules and regulations. 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.

Summary of Significant Accounting Policies

See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on significant accounting policies.

2. Mergers, Acquisitions, and Dispositions

Acquisition of Calpine Corporation

On January 7, 2026 (the “Acquisition Date”), we acquired all of the outstanding equity interests in Calpine in a cash and stock transaction. Pursuant to the Merger Agreement and related transaction steps, Calpine was converted into a limited liability company, Calpine LLC, and became a wholly owned subsidiary of Constellation.

This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy in the United States with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broad array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will improve our position to pursue investments in new and existing technologies to meet growing demand.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

The merger consideration consisted 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, certain of the newly issued shares are subject to a lock-up period, with 50% of the shares released on June 30, 2026, and the remaining 50% scheduled for release on June 30, 2027. In June 2026, the lock-up restrictions were waived for 11 million of these shares to permit their sale in an underwritten secondary public offering, which included two million shares that were repurchased by the Company. We did not sell any shares or receive any proceeds from the offering.

Calpine operates a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. Calpine also owns and operates a generation fleet of natural gas, oil, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, after considering divestitures required by certain regulatory approvals for the transaction. The final regulatory clearance for the merger was the DOJ resolution, which requires the divestiture of five generating assets located in PJM, one in ERCOT, and Calpine's minority interest in the Gregory Power Plant, also in ERCOT. The DOJ resolution requires us to enter into definitive agreement(s) to divest these assets within 240 days of closing the acquisition, by September 4, 2026.

The transaction was accounted for as a business combination using the acquisition method of accounting where we are considered the acquirer for accounting purposes. We recognized the identifiable assets acquired and liabilities assumed at their estimated fair values as of January 7, 2026, with any excess of the consideration transferred over the fair value of net identifiable assets recognized as goodwill.

In January 2026, we completed the divestiture of Calpine's minority ownership interest in the Gregory Power Plant, as required under the terms of the DOJ resolution. In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC (LS Power) whereby we will sell five generation assets in PJM to LS Power, which comprise approximately 4.4 GW of predominantly natural gas-fired generation capacity located in Delaware and Pennsylvania, for aggregate consideration of $5.0 billion before closing adjustments. In August 2026, we entered into an agreement with LS Power to divest the Brazos Valley Energy Center (f/k/a Jack A. Fusco Energy Center), a 606 MW natural gas-fired plant in ERCOT for $860 million before closing adjustments, which is the last asset sale required to satisfy our regulatory commitments under the acquisition. Closing of these sales is subject to receipt of applicable regulatory approvals and other customary closing conditions. We expect the transactions to close by the end of this year. The Brazos Valley Energy Center is currently secured under a project financing arrangement, see Note 13 — Debt and Credit Agreements for additional information.

Consideration Transferred

The following table summarizes the components of the total merger consideration transferred. There was no contingent consideration associated with the acquisition.


Fair value of CEG Parent common stock issued(a)	$	17,603
Cash consideration(b)	4,342
Fair value of common stock subject to vesting period attributable to post-combination expense(c)	(96)
Effective settlement of preexisting relationships	(14)
Total merger consideration	$	21,835

__________

(a)Represents the fair value of approximately 50 million shares of CEG Parent common stock issued in connection with the acquisition, calculated using CEG Parent’s closing stock price of $354.58 on January 6, 2026, the last trading day prior to the Acquisition Date. The fair value of the stock consideration is based on an observable market price and represents a Level 1 fair value measurement.

(b)Represents cash paid to Calpine shareholders in connection with the acquisition. The amount reflects the $4.5 billion base cash consideration per the Merger Agreement, reduced by certain adjustments based on contractual terms also specified in the Merger Agreement.

(c)Certain CEG Parent common stock issued to Calpine employees in exchange for their equity interests is subject to a vesting period of up to 26 months and has been excluded from merger consideration. These amounts will be recognized as stock-based compensation expense over the applicable vesting period in accordance with authoritative guidance.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Purchase Price Allocation

The following table summarizes the acquisition date fair value of the consideration transferred and the identifiable assets acquired and liabilities assumed. Accounting guidance provides that the allocation of the purchase price may be modified up to one year from the date of acquisition to the extent that additional information is obtained about the facts and circumstances that existed as of the acquisition date. Any change could result in a change in the amount of goodwill recognized.


Assets acquired:
Cash and cash equivalents	$	1,540
Restricted cash and cash equivalents	261
Accounts receivable	761
Derivative assets	2,140
Inventories	989
Assets held for sale(a)	5,603
Property, plant, and equipment	18,481
Renewable energy credits	180
Unamortized energy contracts(b)	2,133
Other assets	700
Total assets acquired	$	32,788

Liabilities assumed:
Accounts payable and accrued expenses	$	1,601
Long-term debt (including amounts due within one year)(c)	12,551
Derivative liabilities	644
Renewable energy credit obligation	258
Deferred income taxes and unamortized ITCs	4,083
Asset retirement obligations	350
Unamortized energy contracts(b)	1,815
Other liabilities	758
Total liabilities assumed	22,060
Net identifiable assets acquired	10,728
Goodwill(d)	11,107
Total consideration transferred	$	21,835

(a) Assets Held for Sale. Reflects the Acquisition Date fair value, less costs to sell, for the six generating assets required to be divested. Depreciation and amortization of these assets ceased upon classification as held for sale. No impairment has been recognized subsequent to initial classification. The following table presents the carrying amounts of the major classes of assets and liabilities classified as held for sale as of the Acquisition Date:


Assets held for sale:
Property, plant and equipment	$	5,454
Inventories	136
Other assets	13
Total assets held for sale	$	5,603

Liabilities associated with assets held for sale:
Asset retirement obligations	$	16
Other liabilities	82
Total liabilities associated with assets held for sale	$	98

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

(b) Unamortized Energy Contracts. The following table summarizes the classification and amounts of UECs in the Consolidated Balance Sheets as of the Acquisition Date:


Other current assets	$	517
Other deferred debits and other assets	1,616
Other current liabilities	367
Other deferred credits and other liabilities	1,448

(c) Long-term Debt (including amounts due within one year). We assumed total debt of $12,551 million at estimated fair value as of the Acquisition Date, comprising $279 million classified as Long-term debt due within one year and $12,272 million classified as Long-term debt, in the Consolidated Balance Sheets. See Note 13 — Debt and Credit Agreements for additional information.

(d) Goodwill. Represents the excess of the purchase price over the estimated fair value of the net assets acquired. Goodwill recognized primarily reflects the expected benefits from increased scale and meaningful market diversification, complementary generation, development activities, retail capabilities, and an enhanced ability to meet growing demand with a broader array of energy and sustainability products, to the extent such benefits are not separately recognizable as identifiable intangible assets. Because the design, restructuring, and integration activities of the combined organization are still ongoing, the $11.1 billion of goodwill has been provisionally allocated to the Calpine segment as of June 30, 2026. This provisional allocation may be revised as future organizational, restructuring, and integration activities are completed. The goodwill recognized in connection with the acquisition is not expected to be deductible for income tax purposes.

Valuation of Significant Assets and Liabilities

The fair values assigned to the assets acquired and liabilities assumed were determined based on significant estimates and assumptions that are judgmental in nature, including projected future cash flows; discount rates reflecting the risks inherent in the future cash flows; and future market prices, among others. These estimates and assumptions were applied to the valuation of significant acquired assets and assumed liabilities, including property, plant and equipment, assets held for sale, and unamortized energy contracts, and required assessments of current and projected market conditions and operating strategies. Forecasting future cash flows requires assumptions regarding, among other things, forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of the assets, and judgments are also made to determine the expected useful lives assigned to each class of assets acquired and the duration of liabilities assumed.

Other Key Accounting Impacts & Judgments

Identifiable intangible assets acquired and liabilities assumed in connection with the acquisition include customer relationships, trade names, and energy contracts, recorded at estimated fair value. The weighted average amortization periods reflect weighted average useful lives of 15 years for customer relationships, five years for trade names, and six years for energy contracts.

We also recognized the fair value of acquired commodity and interest rate derivatives and related hedging relationships as of the Acquisition Date; related gains or losses subsequent to acquisition will be recognized in earnings consistent with our accounting policies. For additional information on derivative instruments, see Note 12 — Derivative Financial Instruments.

The amounts recognized for property, plant and equipment, identifiable intangible assets and liabilities (including customer relationships, trade names, and unamortized energy contracts) and their useful lives, lease assets and liabilities, asset retirement and environmental obligations, contingencies, and income taxes (including deferred taxes) are provisional and subject to revision during the measurement period.

Acquisition-related costs (e.g., advisory, legal, valuation, and other professional fees) are expensed as incurred and reflected within Operating and maintenance expenses in the Consolidated Statements of Operations and Comprehensive Income. These costs, which are not included in the consideration transferred, were not material for the three and six months ended June 30, 2026.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Unaudited Pro Forma Results

The following unaudited pro forma financial information for the three and six months ended June 30, 2026 and 2025 assumes that the acquisition occurred on January 1, 2025. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the acquisition been completed on January 1, 2025. The unaudited pro forma financial information is not indicative of the future results of operations, which may differ materially from the pro forma financial information presented here.


	Three Months Ended June 30,				Six Months Ended June 30,
Unaudited pro forma financial information	2026		2025		2026		2025
Operating revenues	$	7,504	$	8,479	$	18,856	$	17,800
Net income(a)	513		985		2,103		1,116

__________

(a)Reflects Net income attributable to common shareholders for CEG Parent and Net income attributable to membership interest for Constellation.

The unaudited pro forma financial information presented above includes adjustments for incremental depreciation and amortization as a result of the fair value determination of the net assets acquired, the effects of the acquisition on tax expense (benefit), and other acquisition accounting adjustments.

As discussed in Note 5 — Segment Information, Calpine is now presented as a reportable segment, and RNF is the segment performance metric, a component of which includes revenue. Operating revenues attributable to Calpine following the Acquisition Date were $1,907 million and $5,043 million for the three and six months ended June 30, 2026. However, as a result of the commencement of integration activities for certain functions and the consolidation of financing activities (see Note 13 — Debt and Credit Agreements), it is impracticable to determine Calpine’s earnings since the Acquisition Date.

3. Regulatory Matters

As discussed in Note 3 — Regulatory Matters of our 2025 Form 10-K, we are involved in various regulatory and legislative proceedings. The following discusses developments in 2026 and updates to the 2025 Form 10-K.

Capacity Interconnection Rights for Crane Clean Energy Center

In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center. The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies.

PJM's Phase I System Impact Study for Crane identified contingent transmission upgrades that would need to be completed for Crane to be fully deliverable to the grid, some of which suggested projected in-service dates extending as late as December 2030.

In March 2026, we filed a waiver request with FERC to allow the transfer of capacity interconnection rights (CIRs) from Eddystone to Crane with the aim of reducing the number of contingent upgrades that would need to be completed prior to Crane being fully deliverable to the grid. Eddystone Units 3 and 4 were previously announced as having a planned retirement date of May 31, 2025, but have been required to continue operating as energy-only resources under DOE emergency orders issued in 2025 and 2026 for grid reliability. Transferring the Eddystone CIRs to Crane will not affect PJM's ability to operate and dispatch Eddystone for reliability in compliance with the DOE's orders. In June 2026, FERC granted the waiver request.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

4. 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.

See Note 4 — Revenue from Contracts with Customers of our 2025 Form 10-K for additional information regarding the performance obligations, revenue recognition, and payment terms associated with these sources of revenue.

Transaction Price Allocated to Remaining Performance Obligations

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 June 30, 2026. This disclosure only includes components of contracts for which consideration is fixed and determinable. The average contract term varies by customer type and commodity but ranges from one month to several years. This disclosure excludes 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	$	1,051	$	1,797	$	1,541	$	1,420	$	891	$	5,155	$	11,855

Transaction Price Allocated to Previously Satisfied Performance Obligations

Our Clinton and Quad Cities units contract with certain utilities in Illinois which requires 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 2026 through May 2027 planning year, the final year of the program, the ZEC price has been established at $1.02 per ZEC, subject to an annual cap of $228 million. ZECs generated and delivered during the current planning year will not exceed the annual cap, and as a result we recognized $85 million of revenue during the second quarter of 2026 as a receivable for all remaining ZECs delivered in prior planning years, with payment expected in the third quarter of 2027. As of June 30, 2026, this receivable is included within Other deferred debits and other assets in the Consolidated Balance Sheets.

For the June 2025 through May 2026 planning year, the ZEC price was established at $1.17 per ZEC, subject to an annual cap of $224 million. ZECs generated and delivered during this planning year did 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 June 30, 2026, this receivable is included within Accounts receivable, net in the Consolidated Balance Sheets.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

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. The following tables disaggregate the revenue recognized from contracts with customers between power revenues, capacity revenues, natural gas revenues, and other revenues. Power revenues and capacity revenues are further disaggregated by ISO/RTO and/or geographic location, which include PJM, MISO, ERCOT, NYISO, ISO-NE, West (which includes operations in CAISO, Arizona and Oregon), SERC (which includes operations in SERC not included in MISO or PJM), SPP, and International Power (which includes operations in the United Kingdom and Canada).


Three Months Ended June 30, 2026	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	2,744	$	124	$	—	$	2,868
MISO	264		8		—		272
ERCOT	422		97		—		519
NYISO	515		13		—		528
ISO-NE	655		2		—		657
West	247		151		—		398
SERC/SPP	27		1		—		28
International Power	85		—		—		85
Total Power revenues	4,959		396		—		5,355
Gas revenues(c)	—		—		327		327
Other revenues(d)	—		—		161		161
Total revenue from contracts with customers	4,959		396		488		5,843
Other revenue sources(e)	—		—		1,661		1,661
Total Operating revenues	$	4,959	$	396	$	2,149	$	7,504

Three Months Ended June 30, 2025	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	2,547	$	37	$	—	$	2,584
MISO	291		—		—		291
ERCOT	328		—		—		328
NYISO	514		—		—		514
ISO-NE	783		—		—		783
West	178		1		—		179
SERC/SPP	25		4		—		29
International Power	42		—		—		42
Total Power revenues	4,708		42		—		4,750
Gas revenues(c)	—		—		321		321
Other revenues(d)	—		—		90		90
Total revenue from contracts with customers	4,708		42		411		5,161
Other revenue sources(e)	—		—		940		940
Total Operating revenues	$	4,708	$	42	$	1,351	$	6,101

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers


Six Months Ended June 30, 2026	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	6,074	$	254	$	—	$	6,328
MISO	516		14		—		530
ERCOT	782		196		—		978
NYISO	1,260		26		—		1,286
ISO-NE	1,669		6		—		1,675
West	415		311		—		726
SERC/SPP	86		5		—		91
International Power	194		—		—		194
Total Power revenues	10,996		812		—		11,808
Gas revenues(c)	—		—		1,270		1,270
Other revenues(d)	—		—		306		306
Total revenue from contracts with customers	10,996		812		1,576		13,384
Other revenue sources(e)	—		—		5,242		5,242
Total Operating revenues	$	10,996	$	812	$	6,818	$	18,626

Six Months Ended June 30, 2025	Power and Power-related Revenues(a)		Capacity Revenues(b)		Other Revenues		Total
PJM	$	5,245	$	45	$	—	$	5,290
MISO	505		—		—		505
ERCOT	630		—		—		630
NYISO	1,189		—		—		1,189
ISO-NE	1,892		—		—		1,892
West	324		2		—		326
SERC/SPP	60		7		—		67
International Power	90		—		—		90
Total Power revenues	9,935		54		—		9,989
Gas revenues(c)	—		—		1,103		1,103
Other revenues(d)	—		—		175		175
Total revenue from contracts with customers	9,935		54		1,278		11,267
Other revenue sources(e)	—		—		1,622		1,622
Total Operating revenues	$	9,935	$	54	$	2,900	$	12,889

__________

(a)Represents power and power-related revenues, including state-sponsored program revenues, ancillary revenues, and revenues from bundled contracts with customers.

(b)Represents revenues from regulated capacity auctions as well as bilateral capacity revenues recognized at negotiated contract prices.

(c)Represents natural gas sales and other gas-related revenues.

(d)Other revenues primarily includes the sales of other energy-related products and sustainable solutions.

(e)Other revenue sources primarily includes revenues accounted for as derivatives, leases, and amortization of intangible assets and liabilities related to commodity contracts recorded at fair value from acquisitions.

5. Segment Information

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

Following the acquisition of Calpine on January 7, 2026, Calpine's operations are being reported as a new reportable segment given the results of its operations are currently reviewed by the CODM separately from our historical reporting segments.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

With the exception of Calpine, 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 six 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.

•Calpine represents operations acquired through the merger with Calpine on January 7, 2026, which are located throughout the country, including CAISO, ERCOT, PJM, ISO-NE, NYISO, MISO, SERC, Arizona, Oregon, as well as Canada.

Our 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 nor 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 geographic regional level, with the exception of Calpine which is currently reviewed on a standalone basis. Our operating revenues include all sales to third parties as well as government assistance. Purchased power and fuel expenses are considered the most 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 nor included in the reportable segment amounts. These activities include wholesale and retail sales of natural gas, with the exception of Calpine's natural gas sales which are included in the Calpine segment, 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 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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

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 three and six months ended June 30, 2026 and 2025.



	2026						2025
Three Months Ended June 30,	Total Operating revenues		Total Purchased power and fuel expenses		Total RNF		Total Operating revenues		Total Purchased power and fuel expenses		Total RNF
Mid-Atlantic	$	1,555	$	(567)	$	988	$	1,448	$	(666)	$	782
Midwest	1,568		(589)		979		1,524		(488)		1,036
New York	564		(174)		390		535		(138)		397
ERCOT	446		(162)		284		464		(193)		271
Other Power Regions	964		(677)		287		1,178		(997)		181
Calpine	2,147		(1,119)		1,028		—		—		—
Total Reportable Segments	7,244		(3,288)		3,956		5,149		(2,482)		2,667
Other(a)	260		(735)		(475)		952		(650)		302
Total Consolidated Results	$	7,504	$	(4,023)	$	3,481	$	6,101	$	(3,132)	$	2,969




Six Months Ended June 30,
Mid-Atlantic	$	3,402	$	(1,602)	$	1,800	$	3,113	$	(1,522)	$	1,591
Midwest	3,300		(1,469)		1,831		2,928		(1,042)		1,886
New York	1,133		(335)		798		1,097		(299)		798
ERCOT	816		(323)		493		862		(377)		485
Other Power Regions	2,450		(1,896)		554		2,734		(2,359)		375
Calpine	4,541		(2,388)		2,153		—		—		—
Total Reportable Segments	15,642		(8,013)		7,629		10,734		(5,599)		5,135
Other(b)	2,984		(2,362)		622		2,155		(1,917)		238
Total Consolidated Results	$	18,626	$	(10,375)	$	8,251	$	12,889	$	(7,516)	$	5,373

__________

(a)Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized losses of $320 million and gains of $86 million for the three months ended June 30, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $120 million and gains of $81 million for the three months ended June 30, 2026 and 2025, respectively.

(b)Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized gains of $995 million and losses of $201 million for the six months ended June 30, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $373 million and gains of $46 million for the six months ended June 30, 2026 and 2025, respectively.

6. Government Assistance

Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. See Note 1 — Basis of Presentation and Note 6 — Government Assistance of our 2025 Form 10-K for additional information on nuclear PTCs.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 6 — Government Assistance

For the three and six months ended June 30, 2026 and 2025, we did not record a material nuclear PTC benefit as the estimate of full year gross receipts exceeded the phase-out for annual gross receipts per MWh for most units. As of June 30, 2026 and December 31, 2025, our Consolidated Balance Sheets reflect approximately $150 million and $120 million, respectively, of nuclear PTCs within Other deferred debits and other assets. For the six months ended June 30, 2026, we did not utilize any estimated nuclear PTCs as a credit against our current federal income taxes payable. For the year ended December 31, 2025, we recognized a reduction to Accounts payable and accrued expenses in our Consolidated Balance Sheets of $375 million 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 June 30, 2026 and December 31, 2025, we have recognized approximately $270 million and $1,190 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. During the six months ended June 30, 2026, we refunded or offset against outstanding receivables approximately $920 million associated with state-sponsored program compensation relating to the nuclear PTCs recorded in 2024. During the three and six months ended June 30, 2026, we recognized an increase to net operating revenue (pre-tax) of approximately $10 million and a reduction to net operating revenue of approximately $275 million, respectively, associated with these programs in our Consolidated Statements of Operations and Comprehensive Income, compared to an increase to net operating revenue (pre-tax) of approximately $75 million and $190 million during the three and six months ended June 30, 2025, respectively.

7. Accounts Receivable

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


	Accounts receivable, net
June 30, 2026	CEG Parent		Constellation
Customer accounts receivable (net of allowance for credit losses of $165 for CEG Parent and Constellation)	$	3,767	$	3,767
Other accounts receivable (net of allowance for credit losses of $— for CEG Parent and Constellation)	894		876
Total	$	4,661	$	4,643

December 31, 2025
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

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, 2026 to June 30, 2026.






Balance as of January 1, 2026	$	158
Current period provision for expected credit losses	35
Write-offs, net of recoveries(a)	(28)

Balance as of June 30, 2026	$	165

__________

(a)Recoveries were not material.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

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 $1,636 million and $1,305 million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of June 30, 2026 and December 31, 2025, respectively.

Calpine Accounts Receivable Sales Program

Following the acquisition of Calpine on January 7, 2026, the Company has assumed Calpine's Accounts Receivable Sales Program (Calpine AR Facility). The Calpine AR Facility was established by Calpine in December 2016 and was last renewed in November 2025 with a current expiration of November 2026. The Calpine AR Facility is a receivables purchase agreement between Calpine Energy Solutions, LLC and Calpine Receivables, LLC, a wholly-owned subsidiary that is accounted for as an unconsolidated VIE, along with an additional purchase and sale agreement between Calpine Receivables, LLC, and unaffiliated financial institutions, the combination of which allow for the revolving sale of up to $500 million in certain trade accounts receivables of Calpine Energy Solutions, LLC to third parties at a nominal discount.

Receivables sold under the Calpine AR Facility are accounted for as sales and excluded from Accounts receivable, net in the Consolidated Balance Sheets and reflected as Cash provided by operating activities in the Consolidated Statements of Cash Flows. Any portion of the purchase price for the sold receivables which is not paid in cash is recorded as a short-term note receivable within Accounts receivable, net, which was not material as of June 30, 2026. Our risk of loss following the transfer of accounts receivable is limited to the note receivable outstanding. Payment of the note receivable is not subject to significant risks other than delinquencies and credit losses on accounts receivable transferred.

The Company has guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility, see Note 15 — Commitments and Contingencies for additional information. Additionally, see Note 17 — Variable Interest Entities for additional information on Calpine Receivables, LLC and its status as an unconsolidated VIE.

There was $459 million in gross accounts receivable outstanding that were sold at a nominal discount under the Calpine AR Facility as of June 30, 2026, and $343 million of the $500 million facility amount was utilized. The following table summarizes certain activity for the period under the Calpine AR Facility:


	Six Months Ended June 30, 2026
Aggregate receivables sold during the period	$	2,040
Proceeds collected on sold receivables	2,066

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 $1,833 million and $2,045 million for the six months ended June 30, 2026 and 2025, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 8 — Property, Plant, and Equipment

8. Property, Plant, and Equipment

The following table presents a summary of property, plant, and equipment balances by asset category as of June 30, 2026 and December 31, 2025:


Asset Category	June 30, 2026		December 31, 2025
Electric(a)	$	51,514	$	33,253
Nuclear fuel	6,485		6,298
CWIP(a)	2,818		1,995

Total property, plant, and equipment	60,817		41,546
Less: accumulated depreciation	19,589		19,072
Property, plant, and equipment, net(b)	$	41,228	$	22,474

__________

(a)Includes Electric and CWIP assets acquired as a result of the Calpine acquisition of $17,247 million and $1,234 million, respectively.

(b)Excludes assets held for sale related to the acquisition of Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

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. As a result of the acquisition of Calpine, we added a fleet of natural gas, oil, geothermal, battery storage and solar assets. There were no material changes in the estimated useful lives of our combined oil and gas, battery storage, wind and solar facilities as a result. Geothermal facility depreciation provisions are based on an estimated useful life through 2066. For additional information about the useful lives of our generating facilities and depreciation provisions, see Note 8 — Property, Plant, and Equipment of our 2025 Form 10-K.

9. 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. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information regarding AROs and the financial statement impact of changes in estimates.

The following table provides a rollforward of the nuclear decommissioning AROs reflected in the Consolidated Balance Sheets from December 31, 2025 to June 30, 2026:


Balance as of December 31, 2025	$	12,908

Accretion expense	318
Net decrease due to changes in, and timing of, estimated future cash flows	(1,277)
Costs incurred related to decommissioning plants	(7)

Balance as of June 30, 2026	$	11,942

During the six months ended June 30, 2026, the net $1,277 million decrease in the ARO for the changes in, and timing of, estimated future cash flows was driven primarily by changes in assumed retirement dates for various plants, including Calvert Cliffs, Fitzpatrick, Limerick, and Nine Mile Point.

The 2026 ARO updates resulted in a decrease of $285 million in Operating and maintenance expense for the six months ended June 30, 2026 in the Consolidated Statements of Operations and Comprehensive income.

NDT Funds

We had NDT funds totaling $20,583 million and $19,396 million as of June 30, 2026 and December 31, 2025, 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 June 30, 2026 and December 31, 2025. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 9 — Asset Retirement Obligations

Accounting Implications of the Regulatory Agreement Units

See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information on the Regulatory Agreement Units.

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 June 30, 2026 and December 31, 2025:


	June 30, 2026		December 31, 2025
ComEd	$	4,638	$	4,313
PECO	642		442
CenterPoint	471		430
AEP Texas	163		149
Payables related to Regulatory Agreement Units	$	5,914	$	5,334

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.

We filed our annual decommissioning funding status report with the NRC for our shutdown units, and any units within five years of shutdown in March 2026. The status report demonstrated adequate decommissioning funding assurance as of December 31, 2025 for all units included in the report. See Note 10 — Asset Retirement Obligations of our 2025 Form 10-K for additional information.

Non-Nuclear Asset Retirement Obligations

We have AROs for plant closure costs associated with our natural gas, oil, battery storage, and renewable generating facilities, including geothermal. The obligations include 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, plug and abandonment of wells, and other decommissioning-related activities. See Note 1 — Basis of Presentation of our 2025 Form 10-K 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 December 31, 2025 to June 30, 2026:


Balance as of December 31, 2025	$	317
Acquisition of Calpine(a)	350
Development projects	19
Accretion expense	18
Net increase due to changes in, and timing of, estimated future cash flows	2
Costs incurred related to decommissioning plants	(2)
Balance as of June 30, 2026	$	704

__________

(a)Reflects our decommissioning obligations for Calpine plants acquired on January 7, 2026, which are recorded at estimated fair value. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Many of the facilities acquired from Calpine do not have AROs given the absence of legal requirements to perform retirement related activities.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Income Taxes

10. Income Taxes

Rate Reconciliation

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


	Three Months Ended June 30,
	2026				2025
U.S. federal statutory income tax	21.0	%	$	189	21.0	%	$	267
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(a)	2.6		23		3.8		48

Tax credits
PTC	(0.6)		(5)		(0.9)		(11)
Amortization of ITC, including deferred taxes on basis differences	(0.3)		(3)		(0.2)		(3)
Other	(0.2)		(2)		(0.2)		(3)
Nontaxable or nondeductible items
Share-based payment awards	—		—		(0.1)		(1)
Excess officers compensation	—		—		0.7		9
Other	1.0		10		—		—
Other adjustments
Qualified NDT fund income and losses	20.7		186		10.5		134
Effective income tax(b)	44.2	%	$	398	34.6	%	$	440


	Six Months Ended June 30,
	2026				2025
U.S. federal statutory income tax	21.0	%	$	635	21.0	%	$	299
Increase (decrease) due to:
State income taxes, net of federal income tax benefit(a)	3.2		96		3.3		47
Foreign tax effects	—		—		0.1		1
Tax credits
PTC	(0.3)		(9)		(0.9)		(13)
Amortization of ITC, including deferred taxes on basis differences	(0.3)		(8)		(0.4)		(5)
Other	(0.2)		(6)		(0.4)		(5)
Nontaxable or nondeductible items
Share-based payment awards	(0.5)		(14)		(2.8)		(40)
Excess officers compensation	0.1		3		1.1		16
Other	0.9		26		—		—
Other adjustments
Qualified NDT fund income and losses	6.8		205		11.4		162
Effective income tax(b)	30.7	%	$	928	32.4	%	$	462

__________

(a)In 2026, state taxes in California, Massachusetts, and New York made up the majority (greater than 50%) of the tax effect in this category. In 2025, state taxes in Illinois, Maryland, Massachusetts, California, Pennsylvania, and New Jersey made up the majority (greater than 50%) of the tax effect in this category.

(b)Amounts may not recalculate due to rounding.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 10 — Income Taxes

Other Tax Matters

Tax Matters Agreement

In connection with the corporate separation transaction, we entered into 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 in which we were included in joint 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 June 30, 2026 and December 31, 2025, respectively, our Consolidated Balance Sheets reflect $32 million and $43 million in Other deferred credits and other liabilities, 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 March 2026, we adjusted our receivable under the TMA as a result of IRS Notice 2026-7, as discussed below. During the second quarter of 2026 and 2025, we received payments for tax attributes utilized by Exelon related to the 2025 and 2024 tax years of $53 million and $128 million, respectively. As of June 30, 2026 and December 31, 2025, respectively, we had $98 million and $175 million in Accounts receivable, net and $279 million and $21 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 2026-7. 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 in February 2026, and as a result, in March 2026 we remitted $235 million to Exelon under the TMA related to prior periods. We increased our receivable for the $235 million in the first quarter of 2026, as reflected above, as we expect Exelon to pay us as it utilizes these tax attributes in future periods.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 11 — Retirement Benefits

11. Retirement Benefits

Components of Net Periodic Benefit (Credits) Costs

See Note 1 — Basis of Presentation of our 2025 Form 10-K for additional information on where we report the service cost and other non-service cost (credit) components for all plans.

The following tables present the components of our net periodic benefit (credit) cost for the three and six months ended June 30, 2026 and 2025. 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
Three Months Ended June 30,	2026		2025		2026		2025		2026		2025
Components of net periodic benefit (credit) cost:
Service cost	$	21	$	21	$	5	$	5	$	26	$	26
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	100		101		20		20		120		121
Expected return on assets	(119)		(123)		(7)		(8)		(126)		(131)
Amortization of:
Prior service (credit) cost	—		—		(2)		(1)		(2)		(1)
Actuarial (gain) loss	38		25		(1)		(2)		37		23

Non-service components of pension benefits & OPEB (credit) cost	19		3		10		9		29		12
Net periodic benefit (credit) cost	$	40	$	24	$	15	$	14	$	55	$	38


Six Months Ended June 30,
Components of net periodic benefit (credit) cost:
Service cost	$	43	$	42	$	10	$	9	$	53	$	51
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost	199		203		40		39		239		242
Expected return on assets	(238)		(245)		(15)		(16)		(253)		(261)
Amortization of:
Prior service (credit) cost	—		—		(3)		(3)		(3)		(3)
Actuarial (gain) loss	76		51		(2)		(4)		74		47

Non-service components of pension benefits & OPEB (credit) cost	37		9		20		16		57		25
Net periodic benefit (credit) cost	$	80	$	51	$	30	$	25	$	110	$	76

12. Derivative Financial Instruments

We use derivative instruments to manage commodity price risk and interest rate 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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

Authoritative guidance about offsetting 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 energy-related 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.

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 into transactions that further optimize the economic benefits of our overall portfolio.

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 commodity sales and purchases 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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

The following tables provide a summary of the commodity derivative fair value balances recorded as of June 30, 2026 and December 31, 2025:


June 30, 2026	Economic Hedges		Collateral(a)		Netting(a)		Total
Derivative assets (current)	$	15,197	$	664	$	(13,744)	$	2,117
Derivative assets (noncurrent)	8,431		349		(7,071)		1,709
Total derivative assets	23,628		1,013		(20,815)		3,826
Derivative liabilities (current)	(15,279)		825		13,744		(710)
Derivative liabilities (noncurrent)	(8,112)		445		7,071		(596)
Total derivative liabilities	(23,391)		1,270		20,815		(1,306)
Total derivative net assets (liabilities)	$	237	$	2,283	$	—	$	2,520

December 31, 2025
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

_________

(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 June 30, 2026 and December 31, 2025:

Total Net Position (In Millions)

Commodity Type

June 30, 2026

December 31, 2025

Unit of Measure

Electricity(a)

(691)

(260)

MWh

Natural Gas(a)

1,561

MMBtu

Emissions

(20)

(35)

Short Ton

_________

(a)The increase in our net notional position as of June 30, 2026 compared to December 31, 2025 is primarily driven by derivatives acquired from Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

Economic Hedges (Commodity Price Risk)

For the three and six months ended June 30, 2026 and 2025, 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.


	Three Months Ended June 30,				Six Months Ended June 30,
Income Statement Location	2026		2025		2026		2025
Operating revenues	$	(321)	$	89	$	992	$	(197)
Purchased power and fuel	(118)		75		(368)		39
Total	$	(439)	$	164	$	624	$	(158)

Interest Rate Risk

We utilize interest rate swaps to manage our interest rate exposure, which are treated as economic hedges. The notional amounts for interest rate swaps were approximately $4.0 billion and $1.4 billion as of June 30, 2026 and December 31, 2025, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

The derivative assets and liabilities as of June 30, 2026 and December 31, 2025 and the gains and losses associated with management of interest rate risk for the three and six months ended June 30, 2026 and 2025 were not material. The gains and losses associated with management of interest rate risk are 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 June 30, 2026. 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 June 30, 2026	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	$	1,938	$	59	$	1,879	1	$	321
Non-investment grade	85		15		70		—	—
No external ratings
Internally rated — investment grade	219		7		212		—	—
Internally rated — non-investment grade	313		68		245		—	—
Total	$	2,555	$	149	$	2,406	1	$	321

__________

(a)As of June 30, 2026, credit collateral held from counterparties where we had credit exposure included $29 million of cash and $120 million of letters of credit.


Net Credit Exposure by Type of Counterparty	As of June 30, 2026
Investor-owned utilities, marketers, power producers	$	1,250
Financial Institutions	484
Energy cooperatives and municipalities	292
Other	380
Total	$	2,406

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 12 — Derivative Financial Instruments

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:


Credit-Risk-Related Contingent Features	June 30, 2026		December 31, 2025
Gross fair value of derivative contracts containing this feature	$	(2,477)	$	(1,307)
Offsetting fair value of derivative contracts under master netting arrangements	1,344		554
Net fair value of derivative contracts containing this feature	$	(1,133)	$	(753)

As of June 30, 2026 and December 31, 2025, 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.


	June 30, 2026		December 31, 2025
Cash collateral posted	$	2,456	$	1,399
Letters of credit posted	1,359		718
Cash collateral held	173		47
Letters of credit held	168		115
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1)(a)(b)(c)	3,441		2,670

__________

(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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

13. Debt and Credit Agreements

Long-Term Debt

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 $5.0 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, $1.25 billion of Calpine senior secured first lien notes in February 2026, and $1.4 billion of Calpine senior unsecured notes in March 2026.

As discussed above, the following project financing arrangements were assumed as part of the acquisition:

Geysers Power Company, LLC. We acquired the GPC first lien senior secured term loan facility, which includes a term loan and $250 million letter of credit facility, up to $50 million of which may be used for loans to finance energy storage projects (the sub-facility). At acquisition, outstanding borrowings under the term loan and sub-facility were approximately $1.35 billion and $45 million, respectively. The GPC facility is secured by substantially all of the real and personal property of GPC and subsidiaries, primarily consisting of the Geysers Assets. The facility matures May 2029 and bears interest at SOFR plus 1.625%. As of June 30, 2026, there were $1.3 billion and $43 million of borrowings outstanding under the term loan and sub-facility, respectively.

Calpine Construction Finance Company, L.P. We acquired the CCFC first lien senior secured term loan facility with $2.1 billion outstanding borrowings at acquisition. The CCFC term loan facility is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants. One plant secured under the facility, the Brazos Valley Energy Center (Brazos), f/k/a Jack A. Fusco Energy Center, is subject to sale in accordance with the DOJ resolution. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Under the terms of the loan facility, CCFC may require the consent of certain lenders to release Brazos as guarantor depending on the application of net sales proceeds. The term loan matures July 2030 and bears interest at SOFR plus 1.75%. As of June 30, 2026, there was $2.1 billion of borrowings outstanding under the term loan.

CDHI Intermediate Holdco, LLC. We acquired the CDHI facility (CDHI Revolver), a $1.2 billion letter of credit facility, up to $400 million of which can be used for revolving loans to finance construction of renewable energy projects. At acquisition, outstanding borrowings under the CDHI Revolver were $319 million. The CDHI Revolver is secured by substantially all of the assets of CDHI's subsidiaries in accordance with the terms of the agreement. The two York Energy Centers that partially secured the CDHI Revolver are subject to sale in accordance with the DOJ resolution. Under the terms of the CDHI revolver, consent of certain lenders was required to release these plants as collateral. In March 2026 and April 2026, the CDHI revolver's total capacity was reduced by $250 million and $568 million, respectively. In June 2026, in connection with the capacity reductions, the lenders agreed to release four plants from the collateral securing CDHI's obligations under the agreement; the two York Energy Centers, Sutter Energy Center, and South Point Energy Center. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information. Redemptions prior to March 2026 were based on SOFR plus 2.25%, and effective March 2026, redemptions bear interest at SOFR plus 2.375%. The CDHI Revolver matures March 2028. As of June 30, 2026, there was $290 million of borrowings outstanding under the credit facility.

Nova Power, LLC. We acquired the Nova Power, LLC credit agreement, which is comprised of a term loan, with $591 million of outstanding borrowings at acquisition, and a $80 million letter of credit facility. The agreement financed a portion of the cost of the development, construction, maintenance, and operation of the Nova Power battery storage project, and is secured by Nova Power's real and personal property. The credit agreement matures September 2031 and bears interest at SOFR plus 1.75%. As of June 30, 2026, there was $572 million of borrowings outstanding under the credit agreement.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Greenfield L.P. We acquired the Greenfield L.P. credit facility, which includes a term loan, with $342 million of outstanding borrowings at acquisition, and several letters of credit facilities, with issuing capacity of approximately $75 million. The Greenfield L.P. credit facility is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada. The credit facility matures November 2030 and bears interest at CORRA plus 1.875%. As of June 30, 2026, there was $317 million of borrowings outstanding under the facility.

Pin Oak Creek Energy Center LLC. We acquired Pin Oak Creek Energy Center's credit agreement pursuant with Texas Energy Fund (TEF), as lender, as administered by the Public Utility of Texas (PUCT). The loan proceeds were used to finance eligible costs for the development (as defined in the agreement), construction, and installation of Pin Oak Creek Energy Center in Fairfield, Texas. The loan had outstanding borrowings of $230 million at acquisition. The loan matures October 2045 and bears interest at 3%. As of June 30, 2026, there was $277 million of borrowings outstanding under the loan.

Calpine Credit Agreements

As a result of the acquisition, we assumed Calpine's corporate secured and unsecured letters of credit facilities with capacity totaling $525 million and $200 million, respectively, at the time of acquisition.

The total capacity of assumed project and corporate credit facilities discussed above was approximately $2.3 billion at the time of acquisition, which was reduced by outstanding borrowings under the GPC facility and CDHI Revolver. At the time of acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion. See the Credit Facilities table below for additional information on credit facilities associated with these project financing arrangements.

Debt Exchange Offering

In December 2025, we announced that, in connection with the planned acquisition of Calpine, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine (the Exchange Offers). 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 issued under the exchange are as follows:


Note	Interest Rate	Maturity	Issued Amount
2029 Senior Unsecured Notes	4.625%	February 2029	$	647
2031 Senior Unsecured Notes	5.000%	February 2031	848
2031 Senior Unsecured 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. In May 2026, we issued senior unsecured notes totaling $2.2 billion and used the net proceeds (i) to repay short-term borrowings, including commercial paper obligations and (ii) for general corporate purposes. The terms of the debt issuances are reflected in the Debt Issuances and Redemptions table below.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Long-term Debt Summary

The following table presents the outstanding long-term debt, as of June 30, 2026 and December 31, 2025:


	Rates	Maturity Date	June 30, 2026		December 31, 2025
Long-term debt
Senior unsecured notes(a)	3.75% - 6.50%	2028 - 2066	$	13,033	$	5,688
Tax-exempt notes(b)	4.10% - 4.45%	2029 - 2053	412		412
Notes payable and other	1.71% - 8.18%	2026 - 2035	85		53
Project finance:(a)
Variable rates	4.13% - 6.11%	2027 - 2030	5,172		597
Fixed rates	2.29% - 8.64%	2031 - 2048	904		653
Total long-term debt			19,606		7,403
Unamortized debt discount and premium, net			(20)		(1)
Unamortized fair value of debt			(18)		—
Unamortized debt issuance costs			(94)		(60)
Long-term debt due within one year			(363)		(92)
Long-term debt			$	19,111	$	7,250

________

(a)Includes debt assumed in acquisition of Calpine.

(b)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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Debt Issuances and Redemptions

During the six months ended June 30, 2026, the following long-term debt was issued (redeemed):


Type(a)	Interest Rate		Maturity	Amount
2028 Senior Unsecured Notes(b)	3.90	%	January 2028	$	900
2036 Senior Unsecured Notes	5.30	%	June 2036	850
2066 Senior Unsecured Notes(b)	5.88	%	January 2066	800
2031 Senior Unsecured Notes(b)	4.40	%	January 2031	750
2029 Senior Unsecured Notes	4.55	%	June 2029	750
2032 Senior Unsecured Notes	4.80	%	January 2032	600
2028 Floating Rate Senior Notes(b)	SOFR + 0.60 %		January 2028	300
Pin Oak Creek Energy Center	3.00	%	October 2045	47
Energy Efficiency Project Financing(c)	5.51	%	December 2030	4
RPG Nonrecourse Debt	4.11	%	March 2035	(2)
2031 Unsecured Notes	5.00	%	August 2031	(2)
2029 Unsecured Notes	4.625	%	August 2029	(3)
Antelope Valley DOE Nonrecourse Debt	2.29 % - 3.56 %		January 2037	(9)
Greenfield	CORRA + 1.875 %		November 2030	(14)
Continental Wind Nonrecourse Debt	6.00	%	February 2033	(18)
Nova Power	SOFR + 1.75 %		September 2031	(19)
Calpine Development Holdings	SOFR + 2.25 % - 2.375 %		March 2028	(29)
Constellation Renewables, LLC	3m SOFR + 2.00 %		December 2027	(36)
Geysers Power Company	SOFR + 1.625 %		May 2029	(60)
Calpine Term Loan	SOFR + 1.75 %		February 2032	(860)
Calpine 2028 Senior Secured Notes	4.50	%	February 2028	(1,250)
Calpine 2028 Senior Unsecured Notes	5.125	%	March 2028	(1,400)
Calpine Term Loan	SOFR + 1.75 %		January 2031	(1,650)
Total long-term debt issued (redeemed)				$	(351)

__________

(a)Does not include debt exchange activity discussed above.

(b)Relates to January 2026 debt issuance used to pay down Calpine corporate debt assumed.

(c)Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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 matures November 2055. Interest rates on the loan are 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.

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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements

Credit Agreements

In September 2025, we amended our existing revolving credit facility (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 the 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 letter 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 rating. 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

The Accounts Receivable Facility (the Facility) provides NER access to revolving loans from a number of financial institutions (Lenders) secured by certain customer accounts receivable. The maximum funding limit of the Facility is $1.5 billion and matures December 2027. 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. In January 2026, we drew on and repaid the full amount of the Facility. In February and March 2026, we drew on the Facility in full. Subsequently, in the second quarter of 2026, we used the proceeds of the term loan and senior notes issued to repay $1.1 billion of the Facility. As of June 30, 2026, $400 million of the Facility was drawn on and outstanding.

The 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 June 30, 2026, the balance of our eligible receivables exceeded the cash proceeds outstanding from the Lenders.

Credit Facilities Summary

As of June 30, 2026 and December 31, 2025, we had the following aggregate bank commitments, credit facility borrowings and available capacity under our respective credit facilities:


Facility Type	Aggregate Bank Commitment		Facility Draws		Outstanding Letters of Credit(a)		Outstanding Commercial Paper(b)		Total Available Capacity
June 30, 2026
Revolving Credit Facility	$	7,000	$	—	$	207	$	2,586	$	4,207
Bilateral and letter of credit facilities(c)(d)	4,100		—		2,691		—		1,409
Accounts Receivable Facility	1,500		400		—		—		1,100
CDHI Revolver(d)	340		290		—		—		50
Liquidity Facility	971		—		809		—		156		(e)
Project Finance(d)	571		43		454		—		74
Total	$	14,482	$	733	$	4,161	$	2,586	$	6,996

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 13 — Debt and Credit Agreements


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

__________

(a)Excludes an additional outstanding letter of credit which was not issued under these facilities of $15 million as of June 30, 2026 and December 31, 2025. See Note 15 — 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 June 30, 2026 and December 31, 2025, the maximum program size of our commercial paper program was $7.0 billion and $4.5 billion, respectively. We do not issue commercial paper in an aggregate amount exceeding the then available capacity under our credit facility. The weighted average interest rate on commercial paper borrowings was 4.21% as of June 30, 2026. There were no commercial paper borrowings outstanding as of December 31, 2025.

(c)In 2026, we entered into or amended several bilateral credit facilities increasing our letter of credit capacity totaling $1,025 million. Amendments to bilateral credit facilities included converting various committed facilities to uncommitted status, and extending maturity dates.

(d)Includes corporate and project-related facilities assumed in connection with Calpine acquisition in January 2026.

(e)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 June 30, 2026 and December 31, 2025, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $965 million and $959 million, respectively.

Short-Term Loan Agreements

As of June 30, 2026 and December 31, 2025, we had the following short-term loan agreements, which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets:

Month Initiated

Interest Rate

Maturity

June 30, 2026

December 31, 2025

May 2025

1-month SOFR + 0.90%

May 2026

—

900

September 2025

1-month SOFR + 0.90%

September 2026

750

April 2026

1-month SOFR + 0.70%

April 2027

1,500

—

Debt Covenants

As of June 30, 2026, we are in compliance with all debt covenants.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

14. 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 SNF obligation as of June 30, 2026 and December 31, 2025. 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.


	June 30, 2026								December 31, 2025
	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	$	19,474	$	16,190	$	3,446	$	19,636	$	7,342	$	6,995	$	666	$	7,661
SNF Obligation(a)	1,454		1,342		—		1,342		1,426		1,406		—		1,406

__________

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

Valuation Techniques Used to Determine Fair Value and Net Asset Value

Our valuation techniques used to measure the fair value and net asset value of the assets and liabilities are in accordance with the policies discussed in Note 17 — Fair Value of Financial Assets and Liabilities of our 2025 Form 10-K except for certain assumed variable rate project financings which are valued using a model that estimates pricing using an internal rate of return calculation and benchmark indices, which may be adjusted for company or security specific risks, resulting in these being classified as Level 3.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Recurring Fair Value Measurements

The following table presents 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 June 30, 2026 and December 31, 2025:


	June 30, 2026								December 31, 2025
	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
Assets
Cash equivalents(a)	$	368	$	—	$	—	$	368	$	42	$	—	$	—	$	42
NDT fund investments
Cash equivalents(b)	420		198		—		618		72		165		—		237
Equities	6,626		1,116		—		7,742		6,245		1,426		—		7,671
Fixed income	2,428		1,599		399		4,426		2,201		1,566		395		4,162
Private credit	—		—		132		132		—		—		132		132
Assets measured at NAV	—		—		—		7,665		—		—		—		7,194

NDT fund investments subtotal(c)	9,474		2,913		531		20,583		8,518		3,157		527		19,396
Rabbi trust investments	72		49		2		123		66		45		1		112
Investments in equities	63		—		—		63		87		—		—		87
Derivative assets
Economic hedges	1,528		12,835		9,348		23,711		1,114		7,449		3,830		12,393

Effect of netting and allocation of collateral	(1,568)		(11,289)		(6,946)		(19,803)		(889)		(6,853)		(3,256)		(10,998)
Derivative assets subtotal	(40)		1,546		2,402		3,908		225		596		574		1,395

Total assets measured at fair value	9,937		4,508		2,935		25,045		8,938		3,798		1,102		21,032



Liabilities
Derivative liabilities
Economic hedges	(1,865)		(13,169)		(8,369)		(23,403)		(1,148)		(8,021)		(4,062)		(13,231)
Effect of netting and allocation of collateral	1,839		12,617		7,630		22,086		1,065		7,657		3,628		12,350
Derivative liabilities subtotal	(26)		(552)		(739)		(1,317)		(83)		(364)		(434)		(881)
Deferred compensation obligation	—		(107)		—		(107)		—		(124)		—		(124)
Total liabilities measured at fair value	(26)		(659)		(739)		(1,424)		(83)		(488)		(434)		(1,005)
Total net assets	$	9,911	$	3,849	$	2,196	$	23,621	$	8,855	$	3,310	$	668	$	20,027

__________

(a)CEG Parent has $396 million and $70 million of Level 1 cash equivalents as of June 30, 2026 and December 31, 2025, respectively. We exclude cash of $622 million and $3,621 million, and restricted cash of $44 million and $57 million as of June 30, 2026 and December 31, 2025, respectively. CEG Parent has excluded an additional $15 million of cash as of June 30, 2026 and no additional cash exclusions as of December 31, 2025.

(b)Includes net liabilities of $231 million and $166 million as of June 30, 2026 and December 31, 2025, 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 notional amounts of $995 million and $810 million as of June 30, 2026 and December 31, 2025, 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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

As of June 30, 2026, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $690 million, $494 million, and $582 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 $122 million and $109 million as of June 30, 2026 and December 31, 2025, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three and six months ended June 30, 2026 and the year ended December 31, 2025.

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 three and six months ended June 30, 2026 and 2025:


	Three Months Ended June 30, 2026
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of April 1, 2026	$	534	$	2,173		$	1	$	2,708
Total realized / unrealized gains (losses)
Included in net income (loss)	(1)		(514)		(b)	1		(514)
Included in Payables related to Regulatory Agreement Units	(2)		—			—		(2)
Change in collateral	—		204			—		204
Purchases	—		24			—		24
Sales	—		(1)			—		(1)
Settlements	—		—			—		—
Transfers into Level 3	—		(22)			—		(22)
Transfers out of Level 3	—		10			—		10
Contract amortization	—		(211)			—		(211)
Balance as of June 30, 2026	$	531	$	1,663		$	2	$	2,196
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2026	$	(1)	$	(278)		$	1	$	(278)


	Three Months Ended June 30, 2025
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of April 1, 2025	$	502	$	(18)		$	1	$	485
Total realized / unrealized gains (losses)
Included in net income (loss)	1		94		(b)	—		95
Included in Payables related to Regulatory Agreement Units	3		—			—		3
Change in collateral	—		80			—		80
Purchases	—		36			—		36
Sales	—		(2)			—		(2)
Settlements	(2)		—			—		(2)
Transfers into Level 3	—		(42)		(c)	—		(42)
Transfers out of Level 3	—		(11)		(c)	—		(11)
Balance as of June 30, 2025	$	504	$	137		$	1	$	642
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2025	$	1	$	206		$	—	$	207

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities


	Six Months Ended June 30, 2026
	NDT Fund Investments		Derivatives			Rabbi Trust Investments		Total
Balance as of January 1, 2026	$	527	$	140		$	1	$	668
Contracts acquired at acquisition date	—		1,290		(a)	—		1,290
Total realized / unrealized gains (losses)
Included in net income (loss)	1		334		(b)	1		336
Included in Payables related to Regulatory Agreement Units	3		—			—		3
Change in collateral	—		102			—		102
Purchases	—		44			—		44
Sales	—		(6)			—		(6)
Settlements	—		—			—		—
Transfers into Level 3	—		(8)		(c)	—		(8)
Transfers out of Level 3	—		169		(c)	—		169
Contract amortization	—		(402)			—		(402)
Balance as of June 30, 2026	$	531	$	1,663		$	2	$	2,196
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2026	$	1	$	290		$	1	$	292


	Six Months Ended June 30, 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)	2		(37)		(b)	—		(35)
Included in Payables related to Regulatory Agreement Units	3		—			—		3
Change in collateral	—		147			—		147
Purchases	—		51			—		51
Sales	—		(5)			—		(5)
Settlements	(4)		—			—		(4)
Transfers into Level 3	1		(43)		(c)	—		(42)
Transfers out of Level 3	—		25		(c)	—		25
Balance as of June 30, 2025	$	504	$	137		$	1	$	642
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of June 30, 2025	$	2	$	110		$	—	$	112

__________

(a)Represents contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions for additional information.

(b)Includes a reduction of ($447) million and ($358) million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2026, respectively. Includes a reduction of ($112) million and ($147) million for realized gains due to the settlement of derivative contracts for the three and six months ended June 30, 2025.

(c)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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

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 three and six months ended June 30, 2026 and 2025:


	Three Months Ended June 30,
	Operating Revenues				Purchased Power and Fuel				Other, net
	2026		2025		2026		2025		2026		2025
Total gains (losses) included in net income	$	(457)	$	(37)	$	(268)	$	131	$	—	$	1
Total unrealized gains (losses)	3		74		(281)		132		—		1


	Six Months Ended June 30,
	Operating Revenues				Purchased Power and Fuel				Other, net
	2026		2025		2026		2025		2026		2025
Total gains (losses) included in net income	$	125	$	1	$	(193)	$	(38)	$	2	$	2
Total unrealized gains (losses)	531		66		(241)		44		2		2

Derivatives

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


Type of trade	Fair Value as of June 30, 2026		Fair Value as of December 31, 2025		Valuation Technique	Unobservable Input	2026 Range & Arithmetic Average		2025 Range & Arithmetic Average
Level 3 Derivatives—Economic hedges(a)(b)	$	979	$	(232)	Discounted Cash Flow	Forward power price (Non-congestion)	$0.32 - $164	$49	$4.77 - $154	$54
						Forward power price (Congestion)	$11 - $168	$55	$3.14 - $154	$50
						Forward gas price	$0.65 - $18	$3.21	($0.46) - $15	$3.52
					Option Model	Volatility percentage	7% - 121%	58%	14% - 197%	59%

__________

(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 $684 million and $372 million as of June 30, 2026 and December 31, 2025, 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. 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.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Commitments and Contingencies

15. Commitments and Contingencies

Commitments

Commercial Commitments. Commercial commitments as of June 30, 2026, representing commitments potentially triggered by future events, were as follows:


	Expiration within
	2026		2027		2028		2029		2030		2031 and thereafter		Total
Letters of credit	$	2,899	$	1,154	$	122	$	—	$	1	$	—	$	4,176
Surety bonds(a)	443		389		78		—		—		557		1,467
Guarantee under the Calpine AR Facility(b)	459		—		—		—		—		—		459
Total commercial commitments	$	3,801	$	1,543	$	200	$	—	$	1	$	557	$	6,102

__________

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

(b)We have guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility. The commitment represents the gross amount of sold receivables that are currently outstanding, limited to $550 million per the guarantee agreement. Refer to Note 7 — Accounts Receivable for additional information.

First Priority Liens for Commodity Procurement and Risk Management Activities

Following the acquisition of Calpine in January 2026, the Company has assumed additional first-priority liens on Calpine assets, which are currently subject to first priority liens under various debt agreements, as collateral under certain of our power and natural gas agreements and certain of the interest rate swaps in order to reduce the cash collateral and letters of credit that would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. As of June 30, 2026, the exposure was $167 million under these first priority liens for power and natural gas agreements and no exposure for the interest rate swaps.

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 currently 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 June 30, 2026 and December 31, 2025, we had accrued undiscounted amounts for environmental liabilities of $14 million and $9 million, respectively, in Accounts payable and accrued expenses and $162 million and $169 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on environmental remediation matters. As of June 30, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 15 — Commitments and Contingencies

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.

As of June 30, 2026 and December 31, 2025, we had accrued $28 million and $15 million, respectively, in Accounts payable and accrued expenses and $122 million and $113 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets for liabilities related to litigation matters, including asbestos personal injury claims. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on asbestos personal injury claims. As of June 30, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K.

Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Calpine was acquired on January 7, 2026, and is party to the same ongoing litigation proceedings as Constellation. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on this matter, which is likewise representative of the ongoing proceedings as it pertains to Calpine.

In March 2026, the Supreme Court of Texas denied plaintiffs’ petitions for a writ of mandamus in all five bellwether appeals. In July 2026, the Court denied plaintiffs' motions for rehearing. The parties will now return to the Multi-District-Litigation court to effect dismissal of all remaining Winter Storm Uri tort claims pending against the power generator defendants.

16. Shareholders' Equity

Share Repurchase Program (CEG Parent)

During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining $0.6 billion authorization under our share repurchase program. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $2.8 billion of remaining authority for repurchases, which includes the impact of the repurchases discussed below. See Note 19 — Shareholders' Equity of our 2025 Form 10-K for additional information on our share repurchase program.

During the three and six months ended June 30, 2026, we repurchased approximately 7.1 million shares of our common stock in the open market for approximately $2.0 billion, inclusive of open market purchases and the secondary public offering discussed further in Note 2 — Mergers, Acquisitions, and Dispositions. In July 2026, we repurchased an additional one million shares for approximately $250 million.

ASR Agreements. In June 2025, we entered into an ASR agreement with a financial institution to initiate share repurchases of our common stock. Under the ASR agreement, we paid a specified amount to the financial institution and received an initial delivery of shares of common stock based on 80% of the ASR agreement's cost, which resulted in an immediate reduction in the number of our shares outstanding, with incremental shares delivered upon settlement of the ASR.

The following table summarizes the ASR agreement for the six months ended June 30, 2025:


(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
June 2025	$	404	1.1	August 2025	0.2	1.3	$	311.84

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Shareholders' Equity

Capped Call Options. During the first quarter of 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments of $150 million in the first quarter of 2025 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 the second and third quarter of 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 during the second and third quarters of 2025. 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:


Three Months Ended June 30, 2026	Gains (losses) on Cash Flow Hedges		Pension and OPEB Items(a)		Foreign Currency Items		Total
Beginning balance	$	2	$	(2,411)	$	(16)	$	(2,425)
OCI before reclassifications	—		—		(1)		(1)
Amounts reclassified from AOCI	2		26		—		28
Net current-period OCI	2		26		(1)		27
Ending balance	$	4	$	(2,385)	$	(17)	$	(2,398)

Three Months Ended June 30, 2025
Beginning balance	$	(4)	$	(2,279)	$	(26)	$	(2,309)
OCI before reclassifications	—		—		20		20
Amounts reclassified from AOCI	1		16		—		17
Net current-period OCI	1		16		20		37
Ending balance	$	(3)	$	(2,263)	$	(6)	$	(2,272)


Six Months Ended June 30, 2026
Beginning balance	$	1	$	(2,413)	$	(13)	$	(2,425)
OCI before reclassifications	—		(25)		(4)		(29)
Amounts reclassified from AOCI	3		53		—		56
Net current-period OCI	3		28		(4)		27
Ending balance	$	4	$	(2,385)	$	(17)	$	(2,398)

Six Months Ended June 30, 2025
Beginning balance	$	(6)	$	(2,262)	$	(34)	$	(2,302)
OCI before reclassifications	—		(34)		28		(6)
Amounts reclassified from AOCI	3		33		—		36
Net current-period OCI	3		(1)		28		30
Ending balance	$	(3)	$	(2,263)	$	(6)	$	(2,272)

__________

(a)AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 16 — Shareholders' Equity

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost	$	(9)	$	(6)	$	(18)	$	(12)
Pension and OPEB plans valuation adjustment	—		—		8		12

17. Variable Interest Entities

At June 30, 2026 and December 31, 2025, 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

The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of June 30, 2026 and December 31, 2025. 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.


	June 30, 2026		December 31, 2025
Cash and cash equivalents	$	95	$	52
Restricted cash and cash equivalents	54		48
Accounts receivable, net	2,132		2,477
Inventories, net	13		13
Other current assets	32		29
Total current assets	2,326		2,619
Property, plant, and equipment, net	1,885		1,942
Other deferred debits and other assets	111		123
Total assets(a)	$	4,322	$	4,684

Short-term borrowings	$	400	$	—
Long-term debt due within one year	67		66
Accounts payable and accrued expenses	33		34
Other current liabilities	1		3
Total current liabilities	501		103
Long-term debt	548		578
Asset retirement obligations	237		231
Other deferred credits and other liabilities	1		2
Total deferred credits and other liabilities	238		233
Total liabilities	$	1,287	$	914

__________

(a)Our balances include unrestricted assets for current UEC assets of $17 million and $17 million, disclosed within other current assets in the table above, and noncurrent UEC assets of $108 million and $116 million, disclosed within other noncurrent assets in the table above, as of June 30, 2026 and December 31, 2025, respectively.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

As of June 30, 2026 and December 31, 2025, 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 Note 21 - Variable Interest Entities of our 2025 Form 10-K for additional information.

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 and gas.

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.

Unconsolidated VIEs

Our variable interests in unconsolidated VIEs generally include an equity method investment and energy purchase and sale contracts. For the equity investment, the carrying amount of the investment is reflected in the Consolidated Balance Sheets in Other deferred debits and other assets, see Note 18 — Supplemental Financial Information for additional information. For the energy purchase and sale contracts (commercial agreements), 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 June 30, 2026 and December 31, 2025, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial and securitization agreements.

Table of Contents

Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

The following table presents summary information about our significant unconsolidated VIE entities:


	June 30, 2026						December 31, 2025
	Commercial Agreement VIEs		Equity Investment VIEs		Total		Commercial Agreement VIEs		Equity Investment VIEs		Total
Total assets(a)	$	711	$	471	$	1,182	$	711	$	—	$	711
Total liabilities(a)	94		440		534		95		—		95

Other ownership interests in VIE(a)	617		31		648		616		—		616

__________

(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.

As of June 30, 2026 and December 31, 2025, the unconsolidated VIEs consist of:

Unconsolidated VIE or 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.

Calpine Receivables, LLC(a) - A bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program

Equity capitalization is insufficient to support its operations.

We do not have the power to direct activities nor affect its financial performance

__________

(a)Calpine Receivables, LLC became an unconsolidated VIE in January 2026 as a result of the Calpine acquisition. As such, it was not an unconsolidated VIE as of December 31, 2025.

18. Supplemental Financial Information

Supplemental Consolidated Statements of Operations and Comprehensive Income Information

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


	Three Months Ended June 30,				Six Months Ended June 30,
Operating revenues	2026		2025		2026		2025

Variable lease income	$	84	$	64	$	182	$	117


	Three Months Ended June 30,				Six Months Ended June 30,
Taxes other than income taxes	2026		2025		2026		2025
Property	$	90	$	71	$	193	$	142
Payroll	60		39		118		83
Gross receipts(a)	52		39		116		77
Other	5		(2)		9		5
Total	$	207	$	147	$	436	$	307

__________

(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.

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Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information


	Three Months Ended June 30,				Six Months Ended June 30,
Other, net	2026		2025		2026		2025
Decommissioning-related activities:
Net realized income on NDT funds(a)
Regulatory Agreement Units	$	284	$	131	$	555	$	375
Non-Regulatory Agreement Units	170		73		325		167
Net unrealized gains (losses) on NDT funds
Regulatory Agreement Units	499		429		293		311
Non-Regulatory Agreement Units	270		253		161		230
Regulatory offset to NDT fund-related activities(b)	(625)		(449)		(677)		(552)
Total Decommissioning-related activities	598		437		657		531



Net unrealized gains (losses) from equity investments(c)	3		(7)		(24)		(275)

Other	2		10		16		30
Total	$	603	$	440	$	649	$	286

__________

(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 items recorded within our Consolidated Statements of Cash Flows.


		Six Months Ended June 30,
Depreciation, amortization, and accretion	Income statement location	2026		2025
PP&E	Depreciation and amortization	$	870	$	492
Nuclear fuel	Purchased power and fuel	496		468
Amortization of acquired derivative contracts(a)	Operating revenues or purchased power and fuel	423		—
ARO accretion	Operating and maintenance	338		318
Amortization of UECs	Operating revenues or purchased power and fuel	240		12
Amortization of intangible assets, net(b)	Depreciation and amortization	16		10
Other amortization	Operating revenues, purchased power and fuel, or interest expense, net	(15)		—
Total		$	2,368	$	1,300

__________

(a)Related to the amortization of acquired derivative contracts from the acquisition of Calpine.

(b)Primarily related to the amortization of customer relationships and trade names.

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Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information


	CEG Parent				Constellation
	Six Months Ended June 30,				Six Months Ended June 30,
Other non-cash operating activities	2026		2025		2026		2025
Other decommissioning-related activity(a)	$	(536)	$	(224)	$	(536)	$	(224)
Pension and non-pension postretirement benefit costs	101		76		101		76






Other	195		127		131		78
Total	$	(240)	$	(21)	$	(304)	$	(70)

__________

(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.

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


June 30, 2026	CEG Parent		Constellation
Cash and cash equivalents	$	697	$	681
Restricted cash and cash equivalents	380		353

Total cash, restricted cash, and cash equivalents	$	1,077	$	1,034

December 31, 2025
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

June 30, 2025
Cash and cash equivalents	$	1,974	$	1,964
Restricted cash and cash equivalents	88		76

Total cash, restricted cash, and cash equivalents	$	2,062	$	2,040

For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2025 Form 10-K. Calpine's restricted cash balances, included in our balances as of June 30, 2026, align with our current policy or represent other agreements that require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use.

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Combined Notes to Consolidated Financial Statements

(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information

Supplemental Balance Sheet Information

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


Inventories, net	June 30, 2026		December 31, 2025
Materials and supplies	$	2,223	$	1,485
Natural gas, oil, and emission allowances	1,145		251
Total	$	3,368	$	1,736


	CEG Parent				Constellation
Accounts payable and accrued expenses	June 30, 2026		December 31, 2025		June 30, 2026		December 31, 2025
Accounts payable	$	2,458	$	2,813	$	2,444	$	2,801
Compensation-related accruals(a)	783		920		680		672
Taxes accrued(b)	395		246		395		245
Other accrued expenses	796		315		796		315
Total	$	4,432	$	4,294	$	4,315	$	4,033

__________

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

(b)Includes $375 million as of December 31, 2025, related to nuclear PTC that was used to offset the current tax liability. No credits were utilized during the six months ended June 30, 2026. 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	June 30, 2026		December 31, 2025
Equity method investments	$	45	$	3
Other investments:
Employee benefit trusts and investments(a)	124		112
Equity investments with readily determinable fair values(b)	61		82
Equity investments without readily determinable fair values	122		109
Other available for sale debt security investments	1		1
Total	$	353	$	307

__________

(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 14 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.


Item 2.			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

(Dollars in millions except per share data, unless otherwise noted)

Executive Overview

Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation’s largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation’s clean energy and delivering the around-the-clock reliability needed to power America’s growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future.

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Significant Transactions and Developments

Acquisition of Calpine Corporation

On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.

This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.

In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments. In August 2026, we entered into an agreement with LS Power to divest the Brazos Valley Energy Center (f/k/a Jack A. Fusco Energy Center), a 606 MW natural gas-fired plant in ERCOT for $860 million before closing adjustments. Completion of these transactions is subject to customary closing conditions and receipt of applicable regulatory approvals, and is expected to satisfy the remaining regulatory commitments related to the merger. We expect the transactions to close by the end of this year.

See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

New Data Center Facility at Freestone Energy Center

In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. We have also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas.

Pastoria Solar Project

In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired Pastoria facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which came online in July 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company.

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Pin Oak Creek Energy Center

In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460 MW, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas’ continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state’s economic momentum.

Long-term Nuclear PPAs

We have signed an additional 920 MW of long-term PPAs for clean, reliable nuclear generation with a diverse set of investment grade customers to help them meet their evolving energy needs. These agreements are for 15-20 years in duration and are set to begin in 2029 through 2032. Among these PPAs, our 176 MW agreement with Walmart will enable a 30 MW capacity expansion at our Dresden Clean Energy Center in Illinois and facilitate additional investments to strengthen the local community by supporting jobs and enabling continued expansion of operations and workforce.

Other Key Business Drivers

PJM Market Reform

In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar—consisting of a price cap of approximately $325/MW‑day and a price floor of approximately $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM’s tariff revisions, allowing the continued application of the price collar for the specified delivery years. FERC found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms. In July 2026, PJM released the results of the 2028/2029 Base Residual Auction and the entire RTO, including all submitted CEG units, cleared at the price cap of $325/MW-day

FERC Issues Order in PJM Show Cause Proceeding

In December 2025, FERC issued an order finding the existing PJM Tariff to be unjust and unreasonable and directing PJM to take a number of actions. FERC ordered three new transmission services: an interim interruptible network integration transmission service (IT NITS), which will allow load to take service on an interruptible basis while waiting for the network upgrades required for traditional NITS, and two other services. The IT NITS service allows the load to elect to connect promptly and receive some service from the grid, while avoiding PJM purchases of capacity to serve it, as it will be interruptible. The other services include a firm and non-firm contract demand service for co-located load. FERC also directed several PJM compliance filings and a paper hearing.

In June 2026, FERC ruled on a number of issues presented in the co-location paper hearing and on several PJM compliance filings implementing directives from the December 2025 order. Importantly, FERC pressed PJM to implement changes to accommodate co-located load prior to PJM’s proposed June 2029 effective date.

FERC also issued a series of orders in the various RTOs in response to the Advance Notice of Proposed Rulemaking (ANOPR) published by DOE last fall. The orders direct filings by RTOs and their transmission owners that are designed to expedite service to large load (regardless of whether it is co-located) and avoid the expense and delay associated with network upgrades to provide service to these loads. Constellation’s Load Dependent Capacity at Existing Plants (LCEP) proposal, which would expedite connection of new generation when paired with a large load at an existing plant, was flagged in several RTO orders as a proposal to be considered.

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Russia and Ukraine Conflict

We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. “Prohibiting Russian Uranium Imports Act” became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.

Environmental Regulation

California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state’s Cap-and-Trade Program through January 1, 2046, and renaming it the “Cap and Invest" Program.

In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions, such as a determination by PJM that the unit is needed for reliability. PJM made such a finding with respect to our natural gas generation facility Zion Energy Center, acquired as part of Calpine, and accordingly Zion plans to operate past January 2030.

See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to.

Critical Accounting Policies and Estimates

Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At June 30, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.

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Financial Results of Operations

GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three and six months ended June 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended June 30, 2026 and 2025, see the discussions of Results of Operations below.


	Three Months Ended June 30,				$ Change		Six Months Ended June 30,				$ Change
	2026		2025				2026		2025
GAAP Net Income (Loss) Attributable to Common Shareholders	$	513	$	839	$	(326)	$	2,103	$	957	$	1,146

Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.

The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.

Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.5% for the three and six months ended June 30, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three and six months ended June 30, 2026 compared to the same period in 2025.


	Three Months Ended June 30,
	2026				2025
(In millions, except per share data)			Earnings Per Share(a)				Earnings Per Share(a)
GAAP Net Income (Loss) Attributable to Common Shareholders	$	513	$	1.42	$	839	$	2.67
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $116 and $37, respectively)(b)	340		0.94		(121)		(0.38)
Decommissioning-Related Activities (net of taxes of $298 and $208, respectively)(c)	(221)		(0.61)		(144)		(0.46)
Amortization of Acquired Commodity Contracts (net of taxes of $51 and $—, respectively)(d)	149		0.41		—		—
Calpine Merger and Integration Costs (net of taxes of $17 and $3, respectively)(e)	84		0.23		9		0.03
Plant Retirements and Divestitures (net of taxes of $— and $2, respectively)	—		—		7		0.02
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $7 and $3, respectively)	20		0.06		9		0.03
Change in Legal and Environmental Liabilities (net of taxes of $12 and $—, respectively)	35		0.10		—		—




Adjusted (non-GAAP) Operating Earnings	$	920	$	2.55	$	599	$	1.91

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	Six Months Ended June 30,
	2026				2025
(In millions, except per share data)			Earnings Per Share(a)				Earnings Per Share(a)
GAAP Net Income (Loss) Attributable to Common Shareholders	$	2,103	$	5.88	$	957	$	3.05
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $131 and $131, respectively)(b)	(381)		(1.07)		384		1.22
Decommissioning-Related Activities (net of taxes of $377 and $239, respectively)(c)	(395)		(1.11)		(125)		(0.40)
Amortization of Acquired Commodity Contracts (net of taxes of $104 and $—, respectively)(d)	303		0.85		—		—
Calpine Merger and Integration Costs (net of taxes of $39 and $8, respectively)(e)	204		0.57		22		0.07
Plant Retirements and Divestitures (net of taxes of $— and $6, respectively)	—		—		18		0.06
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $14 and $6, respectively)	40		0.11		18		0.06
Change in Legal and Environmental Liabilities (net of taxes of $12 and $—, respectively)	35		0.10		1		—
Income Tax-Related Adjustments	(13)		(0.04)		—		—
Noncontrolling Interests(f)	(3)		(0.01)		(3)		(0.01)
Adjusted (non-GAAP) Operating Earnings	$	1,893	$	5.30	$	1,272	$	4.05

__________

(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 360 million and 314 million for the three months ended June 30, 2026 and 2025, respectively, and 357 million and 314 million for the six months ended June 30, 2026 and 2025, respectively.

(b)Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts.

(d)In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition.

(e)Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible.

(f)Represents elimination of the noncontrolling interest portion of certain adjustments included above.

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Results of Operations


	Three Months Ended June 30,				$ Change		Six Months Ended June 30,				$ Change
	2026		2025				2026		2025
Operating revenues	$	7,504	$	6,101	$	1,403	$	18,626	$	12,889	$	5,737
Operating expenses
Purchased power and fuel	4,023		3,132		891		10,375		7,516		2,859
Operating and maintenance	2,253		1,617		636		4,033		3,162		871
Depreciation and amortization	443		254		189		886		502		384
Taxes other than income taxes	207		147		60		436		307		129
Total operating expenses	6,926		5,150		1,776		15,730		11,487		4,243

Gain (loss) on sales of assets	2		—		2		16		—		16


Operating income (loss)	580		951		(371)		2,912		1,402		1,510
Other income and (deductions)
Interest expense, net	(283)		(118)		(165)		(536)		(264)		(272)
Other, net	603		440		163		649		286		363
Total other income and (deductions)	320		322		(2)		113		22		91
Income (loss) before income taxes	900		1,273		(373)		3,025		1,424		1,601
Income tax (benefit) expense	398		440		(42)		928		462		466
Equity in income (losses) of unconsolidated affiliates	6		—		6		14		—		14
Net income (loss)	508		833		(325)		2,111		962		1,149
Net income (loss) attributable to noncontrolling interests	(5)		(6)		1		8		5		3
Net income (loss) attributable to common shareholders	$	513	$	839	$	(326)	$	2,103	$	957	$	1,146

Three Months Ended June 30, 2026 Compared to Three Months Ended June 30, 2025. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($326) million primarily due to:

•Unfavorable net unrealized losses on economic hedges;

•Unfavorable Calpine merger and integration costs; and

•Unfavorable impacts from nuclear outages.

The unfavorable items were partially offset by:

•Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by lower CMC program revenue; and

•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

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Six Months Ended June 30, 2026 Compared to Six Months Ended June 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $1,146 million primarily due to:

•Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by lower CMC program revenue;

•Favorable decommissioning-related activities primarily driven by the Q1 2026 nuclear ARO update. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information; and

•Lower net unrealized loss on equity investments.

The favorable items were partially offset by:

•Unfavorable Calpine merger and integration costs; and

•Unfavorable impacts from nuclear outages.

Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.

With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations, are reported under Other and not allocated to a segment.

For the three and six months ended June 30, 2026 compared to 2025, Operating revenues were as follows:


	Three Months Ended June 30,								Six Months Ended June 30,
	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
Mid-Atlantic	$	1,555	$	1,448	$	107	7.4	%	$	3,402	$	3,113	$	289	9.3	%
Midwest	1,568		1,524		44		2.9	%	3,300		2,928		372		12.7	%
New York	564		535		29		5.4	%	1,133		1,097		36		3.3	%
ERCOT	446		464		(18)		(3.9)	%	816		862		(46)		(5.3)	%
Other Power Regions	964		1,178		(214)		(18.2)	%	2,450		2,734		(284)		(10.4)	%
Calpine	2,147		—		2,147		100.0	%	4,541		—		4,541		100.0	%
Total reportable segment revenues	7,244		5,149		2,095		40.7	%	15,642		10,734		4,908		45.7	%
Other	580		866		(286)		(33.0)	%	1,989		2,356		(367)		(15.6)	%
Unrealized gains (losses)(a)	(320)		86		(406)		(a)		995		(201)		1,196		(a)
Total Operating revenues	$	7,504	$	6,101	$	1,403	23.0	%	$	18,626	$	12,889	$	5,737	44.5	%

__________

(a)% Change in unrealized gains (losses) is not a meaningful measure.

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Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below:


	Three Months Ended June 30,					Six Months Ended June 30,
(GWhs)	2026	2025	Change	% Change		2026	2025	Change	% Change
Nuclear Generation(a)
Mid-Atlantic	12,676	12,263	413	3.4	%	26,002	25,440	562	2.2	%
Midwest	23,112	23,760	(648)	(2.7)	%	46,086	47,356	(1,270)	(2.7)	%
New York	6,336	6,632	(296)	(4.5)	%	12,351	12,913	(562)	(4.4)	%
ERCOT	2,036	2,515	(479)	(19.0)	%	4,388	5,044	(656)	(13.0)	%
Total Nuclear Generation	44,160	45,170	(1,010)	(2.2)	%	88,827	90,753	(1,926)	(2.1)	%

Natural Gas, Oil, and Renewables(a)
Mid-Atlantic	611	810	(199)	(24.6)	%	1,351	1,442	(91)	(6.3)	%
Midwest	273	258	15	5.8	%	617	643	(26)	(4.0)	%

ERCOT	3,742	3,206	536	16.7	%	6,480	6,290	190	3.0	%
Other Power Regions	1,109	1,286	(177)	(13.8)	%	2,852	3,090	(238)	(7.7)	%
Calpine	24,914	—	24,914	100.0	%	51,411	—	51,411	100.0	%
Total Natural Gas, Oil, and Renewables	30,649	5,560	25,089	451.2	%	62,711	11,465	51,246	447.0	%

Purchased Power
Mid-Atlantic	3,063	3,750	(687)	(18.3)	%	7,157	8,544	(1,387)	(16.2)	%
Midwest	394	475	(81)	(17.1)	%	811	963	(152)	(15.8)	%

ERCOT	640	837	(197)	(23.5)	%	1,326	1,495	(169)	(11.3)	%
Other Power Regions	8,181	9,849	(1,668)	(16.9)	%	17,496	20,844	(3,348)	(16.1)	%
Calpine	2,728	—	2,728	100.0	%	4,817	—	4,817	100.0	%
Total Purchased Power	15,006	14,911	95	0.6	%	31,607	31,846	(239)	(0.8)	%

Total Supply/Sales by Segment
Mid-Atlantic	16,350	16,823	(473)	(2.8)	%	34,510	35,426	(916)	(2.6)	%
Midwest	23,779	24,493	(714)	(2.9)	%	47,514	48,962	(1,448)	(3.0)	%
New York	6,336	6,632	(296)	(4.5)	%	12,351	12,913	(562)	(4.4)	%
ERCOT	6,418	6,558	(140)	(2.1)	%	12,194	12,829	(635)	(4.9)	%
Other Power Regions	9,290	11,135	(1,845)	(16.6)	%	20,348	23,934	(3,586)	(15.0)	%
Calpine	27,642	—	27,642	100.0	%	56,228	—	56,228	100.0	%
Total Supply/Sales by Segment	89,815	65,641	24,174	36.8	%	183,145	134,064	49,081	36.6	%

__________

(a)Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Nuclear fleet capacity factor	93.0	%	94.8	%	92.7	%	94.5	%
Refueling outage days	86		41		185		129
Non-refueling outage days	20		22		20		22

Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider EFOF to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three and six months ended June 30, 2026 was 6.2% and 5.2%, respectively. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.

Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized.


	Three Months Ended June 30,								Six Months Ended June 30,
ISO/RTO	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
PJM - PJM West	$	51.40	$	42.43	$	8.97	21.1	%	$	74.28	$	48.06	$	26.22	54.6	%
PJM - ComEd	29.32		31.09		(1.77)		(5.7)	%	40.01		33.20		6.81		20.5	%
NYISO - Central	40.51		37.40		3.11		8.3	%	76.37		56.36		20.01		35.5	%
ERCOT - North	29.58		32.75		(3.17)		(9.7)	%	35.12		32.07		3.05		9.5	%
ERCOT - Houston	32.62		36.95		(4.33)		(11.7)	%	35.59		34.34		1.25		3.6	%
ISO-NE - Southeast Massachusetts	48.18		40.31		7.87		19.5	%	83.50		72.53		10.97		15.1	%
CAISO - NP15	17.28		26.62		(9.34)		(35.1)	%	23.14		33.79		(10.65)		(31.5)	%

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Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three and six months ended June 30, 2026 and 2025.

We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below.


	Three Months Ended June 30,								Six Months Ended June 30,
ISO/RTO	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
PJM - Eastern Mid-Atlantic Area Council	$	289.67	$	125.71	$	163.96	130.4	%	$	279.80	$	89.65	$	190.15	212.1	%
PJM - ComEd	289.67		109.25		180.42		165.1	%	279.80		69.09		210.71		305.0	%
NYISO - Rest of State	195.67		132.89		62.78		47.2	%	154.00		109.61		44.39		40.5	%
ISO-NE - Rest of Pool(a)	84.99		83.17		1.82		2.2	%	84.68		82.87		1.81		2.2	%

__________

(a)We did not have significant activity at this zone for the three months ended June 30, 2025.

ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and six months ended June 30, 2026 and 2025 and may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.


	Three Months Ended June 30,								Six Months Ended June 30,
State (Segment)(a)	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
New Jersey (Mid-Atlantic)(b)	$	—	$	10.00	$	(10.00)	(100.0)	%	$	—	$	10.00	$	(10.00)	(100.0)	%
Illinois (Midwest)	1.12		6.64		(5.52)		(83.1)	%	1.15		8.01		(6.86)		(85.6)	%
New York (New York)	14.76		14.76		—		—	%	14.76		16.52		(1.76)		(10.7)	%

__________

(a)See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs.

(b)The New Jersey ZEC program concluded in May 2025.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025, $33.50 per MWh for the period June 2025 through May 2026, and $34.50 per MWh for the period June 2026 through May 2027. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($5.91) and ($0.42) for the three months ended June 30, 2026 and 2025, respectively, and ($16.05) and ($1.23) for the six months ended June 30, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.

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Nuclear PTC. 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 and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025 and 2026. 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.

Many of the state-sponsored programs (e.g., ZECs and CMCs) 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. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three and six months ended June 30, 2026 compared to 2025:


	Three Months Ended June 30,								Six Months Ended June 30,
	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
Nuclear PTC revenue(a)	$	15	$	45	$	(30)	(66.7)	%	$	25	$	45	$	(20)	(44.4)	%
State-sponsored programs net revenue(b)	10		75		(65)		86.7	%	(275)		190		(465)		(244.7)	%

__________

(a)Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

(b)Includes only state-sponsored programs that have 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.

For the three and six months ended June 30, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:


	Three Months Ended June 30					Six Months Ended June 30
	$ Change		% Change		Description	$ Change		% Change		Description
Mid-Atlantic	$	107	7.4	%	• favorable retail load revenue of $160 primarily due to higher contracted energy prices; partially offset by • unfavorable realized economic hedges of $90 due to settled prices relative to hedged prices	$	289	9.3	%	• favorable retail load revenue of $470 primarily due to higher contracted energy prices • favorable wholesale load revenue of $145 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by • unfavorable realized economic hedges of $305 due to settled prices relative to hedged prices

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	Three Months Ended June 30				Six Months Ended June 30
	$ Change	% Change		Description	$ Change	% Change		Description
Midwest	44	2.9	%	• favorable retail load revenue of $110 primarily due to higher contracted energy prices • favorable net capacity revenue of $65 primarily due to higher prices; partially offset by • unfavorable ZEC program revenue of $135 primarily due to lower revenue recognized for Illinois ZECs delivered in prior planning years	372	12.7	%	• favorable net generation and wholesale load revenue of $410 primarily due to higher energy prices and higher load volumes, partially offset by lower generation volumes • favorable retail load revenue of $325 primarily due to higher contracted energy prices and higher load volumes • favorable net capacity revenue of $155 primarily due to higher prices • favorable realized economic hedges of $85 due to settled prices relative to hedged prices; partially offset by • unfavorable CMC program revenue of $400 primarily due to higher energy and capacity prices • unfavorable ZEC program revenue of $175 primarily due to lower revenue recognized for Illinois ZECs delivered in prior planning years and decrease in ZEC price
New York	29	5.4	%	• no individually significant drivers	36	3.3	%	• favorable net generation revenue of $125 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices • favorable retail load revenue of $50 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by • unfavorable realized economic hedges of $90 due to settled prices relative to hedged prices
ERCOT	(18)	(3.9)	%	• no individually significant drivers	(46)	(5.3)	%	• no individually significant drivers
Other Power Regions	(214)	(18.2)	%	• unfavorable wholesale load revenue of $105 and retail load revenue of $100 primarily due to lower load volumes in New England	(284)	(10.4)	%	• unfavorable wholesale load revenue of $230 primarily due to lower load volumes in New England • unfavorable retail load revenue of $100 primarily due to lower load volumes in New England and lower energy prices in the West

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	Three Months Ended June 30					Six Months Ended June 30
	$ Change		% Change		Description	$ Change		% Change		Description
Calpine	2,147		100.0	%	• represents the operating revenues associated with our Calpine segment	4,541		100.0	%	• represents the operating revenues associated with our Calpine segment since the date of acquisition
Other	(286)		(33.0)	%	• current year includes unfavorable amortization of $205 associated with certain commodity contracts related to the Calpine acquisition • unfavorable retail gas revenue of $60 primarily due to lower gas prices	(367)		(15.6)	%	• current year includes unfavorable amortization of $420 associated with certain commodity contracts related to the Calpine acquisition • unfavorable revenues in the United Kingdom, inclusive of realized economic hedges, of $70 primarily due to lower energy prices; partially offset by • favorable retail gas revenue of $100 primarily due to higher gas prices
Unrealized gains or losses(a)(b)	(406)		(a)		• losses on economic hedging activities of $320 in 2026 compared to gains of $86 in 2025, inclusive of Calpine	1,196		(a)		• gains on economic hedging activities of $995 in 2026 compared to losses of $201 in 2025, inclusive of Calpine
Total	$	1,403	23.0	%		$	5,737	44.5	%

__________

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

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Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices.

With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment.

For the three and six months ended June 30, 2026 compared to 2025, Purchased power and fuel expense were as follows:


	Three Months Ended June 30,								Six Months Ended June 30,
	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
Mid-Atlantic	$	567	$	666	$	(99)	(14.9)	%	$	1,602	$	1,522	$	80	5.3	%
Midwest	589		488		101		20.7	%	1,469		1,042		427		41.0	%
New York	174		138		36		26.1	%	335		299		36		12.0	%
ERCOT	162		193		(31)		(16.1)	%	323		377		(54)		(14.3)	%
Other Power Regions	677		997		(320)		(32.1)	%	1,896		2,359		(463)		(19.6)	%
Calpine	1,119		—		1,119		100.0	%	2,388		—		2,388		100.0	%
Total segment purchased power and fuel	3,288		2,482		806		32.5	%	8,013		5,599		2,414		43.1	%
Other	615		731		(116)		(15.9)	%	1,989		1,963		26		1.3	%
Unrealized losses (gains)(a)	120		(81)		201		(a)		373		(46)		419		(a)
Total purchased power and fuel	$	4,023	$	3,132	$	891	28.4	%	$	10,375	$	7,516	$	2,859	38.0	%

__________

(a)% Change in unrealized losses (gains) is not a meaningful measure.

Natural Gas Prices. As an owner-operator of a large fleet of natural gas-fired generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized.


	Three Months Ended June 30,								Six Months Ended June 30,
Location	2026		2025		$ Change		% Change		2026		2025		$ Change		% Change
Henry Hub	$	2.93	$	3.16	$	(0.23)	(7.3)	%	$	3.91	$	3.71	$	0.20	5.4	%
Transco Zone 6(a)	2.13		2.40		(0.27)		(11.3)	%	5.78		4.22		1.56		37.0	%
Houston Ship Channel(b)	2.45		2.74		(0.29)		(10.6)	%	2.85		3.10		(0.25)		(8.1)	%
PG&E Citygate(c)	1.55		2.81		(1.26)		(44.8)	%	1.81		3.26		(1.45)		(44.5)	%
Algonquin Citygate(d)	2.37		2.86		(0.49)		(17.1)	%	8.19		7.32		0.87		11.9	%

__________

(a)Transcontinental Gas pipeline located in Mid-Atlantic region.

(b)Houston-area pipeline and industrial network located in ERCOT region.

(c)Pacific Gas & Electric Company virtual trading point located in West region.

(d)Algonquin Gas Transmission physical delivery point located in New England region.

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For the three and six months ended June 30, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:


	Three Months Ended June 30					Six Months Ended June 30
	$ Change		% Change		Description	$ Change		% Change		Description
Mid-Atlantic	$	(99)	(14.9)	%	• favorable realized economic hedges of $85 due to settled prices relative to hedged prices • favorable $65 due to financial transmission rights overfunding in 2026; partially offset by • unfavorable $60 associated with purchased power to supply load, net of generation, primarily due to higher energy prices and higher prices associated with net capacity costs	$	80	5.3	%	• unfavorable $405 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to an extreme weather event in January 2026; partially offset by • favorable realized economic hedges of $275 due to settled prices relative to hedged prices • favorable $65 due to financial transmission rights overfunding in 2026
Midwest	101		20.7	%	• unfavorable $80 associated with purchased power to supply load, net of generation, primarily due to higher net transmission costs	427		41.0	%	• unfavorable $390 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026 and net transmission costs
New York	36		26.1	%	• no individually significant drivers	36		12.0	%	• no individually significant drivers
ERCOT	(31)		(16.1)	%	• no individually significant drivers	(54)		(14.3)	%	• no individually significant drivers
Other Power Regions	(320)		(32.1)	%	• favorable $150 associated with purchased power to supply load primarily due to lower load volumes in New England, and lower load volumes and energy prices in the West • favorable $120 primarily associated with environmental product sales • favorable realized economic hedges of $55 due to settled prices relative to hedged prices	(463)		(19.6)	%	• favorable $230 associated with purchased power to supply load primarily due to lower load volumes in New England, and lower energy prices in the West • favorable $140 associated with environmental product sales and lower environmental obligations • favorable realized economic hedges of $80 due to settled prices relative to hedged prices
Calpine	1,119		100.0	%	• represents the purchased power and fuel associated with our Calpine segment	2,388		100.0	%	• represents the purchased power and fuel associated with our Calpine segment since the date of acquisition

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	Three Months Ended June 30					Six Months Ended June 30
	$ Change		% Change		Description	$ Change		% Change		Description
Other	(116)		(15.9)	%	• favorable net wholesale gas purchases of $60, inclusive of realized economic hedges, primarily due to lower gas prices	26		1.3	%	• unfavorable net wholesale gas purchases of $115, inclusive of realized economic hedges, primarily due to higher gas prices • favorable purchases in the United Kingdom, inclusive of realized economic hedges, of $65 primarily due to lower energy prices
Unrealized gains or losses(a)(b)	201		(a)		• losses on economic hedging activities of $120 in 2026 compared to gains of $81 in 2025, inclusive of Calpine	419		(a)		• losses on economic hedging activities of $373 in 2026 compared to gains of $46 in 2025, inclusive of Calpine
Total	$	891	28.4	%		$	2,859	38.0	%

__________

(a)% Change in unrealized gains or losses is not a meaningful measure.

(b)See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

The changes in Operating and maintenance expense consisted of the following:


	2026 vs. 2025
	Three Months Ended June 30,		Six Months Ended June 30,

	Increase (Decrease)		Increase (Decrease)
Labor, contracting, and materials(a)	$	228	$	404
Calpine merger and integration costs	87		211
Nuclear refueling outage costs(b)	68		119
Changes in legal and environmental liabilities	48		47
Decommissioning-related activities	4		(268)
Other(c)	201		358
Total increase	$	636	$	871

__________

(a)Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026.

(b)Includes the co-owned Salem and STP generating units

(c)Primarily includes administrative expenses such as information technology, regulatory fees, facilities and rentals, and insurance. The increase is driven primarily by the addition of Calpine's operations beginning in January 2026.

Depreciation and amortization expense increased by $189 million for the three months ended June 30, 2026 compared to the same period in 2025, and increased by $384 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Interest expense, net increased by $165 million for the three months ended June 30, 2026 compared to the same period in 2025, and increased by $272 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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Other, net was favorable for the three and six months ended June 30, 2026 compared to the same period in 2025, due to activity described in the table below:


	Income (Deductions)
	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Decommissioning-related activities(a)	$	598	$	437	$	657	$	531
Net unrealized gains (losses) from equity investments(b)	3		(7)		(24)		(275)
Other	2		10		16		30
Other, net	$	603	$	440	$	649	$	286

__________

(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 — Asset Retirement Obligations and Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b)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.

Effective income tax rates were 44.2% and 34.6% for the three months ended June 30, 2026 and 2025, respectively, and 30.7% and 32.4% for the six months ended June 30, 2026 and 2025, respectively. The increase in effective tax rate for the three months ended was primarily due to higher qualified NDT fund income in the second quarter of 2026 which is taxed at a higher rate. The decrease in effective tax rate for the six months ended was primarily due to proportionally lower qualified NDT fund income in 2026 which is taxed at a higher rate as well as a decrease in share-based payment awards. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Liquidity and Capital Resources

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. Annually, we evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $14.5 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

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Cash Flow Activities

The following table summarizes our cash flow activities for the six months ended June 30, 2026 and 2025, respectively:


	Six Months Ended June 30,
	2026		2025		$ Change
Cash, restricted cash, and cash equivalents at beginning of period	$	3,748	$	3,129	$	619
Net cash provided by (used in):
Operating activities	1,553		1,584		(31)
Investing activities	(5,101)		(1,758)		(3,343)
Financing activities	877		(893)		1,770
Net increase (decrease) in cash, restricted cash, and cash equivalents	(2,671)		(1,067)		(1,604)

Cash, restricted cash, and cash equivalents at end of period	$	1,077	$	2,062	$	(985)

Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities was $1,553 million and $1,584 million for the six months ended June 30, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Included in net cash provided by operating activities for the six months ended June 30, 2026, are refunds to state programs associated with nuclear PTCs. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Investing Activities

Cash used in investing activities was ($5,101) million and ($1,758) million for the six months ended June 30, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition and an increase in capital expenditures related to the planned restart of Crane, inclusion of Calpine, and co-location infrastructure. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Financing Activities

Cash provided by financing activities was $877 million for the six months ended June 30, 2026, compared to cash used in financing activities of ($893) million for the six months ended June 30, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the six months ended June 30, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. The remaining change is related to repurchases of common stock. See Note 13 — Debt and Credit Agreements and Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Quarterly dividends declared by our Board of Directors during 2026 were as follows:

Period

Declaration Date

Shareholder of Record Date

Dividend Payable Date

Cash per Share

First Quarter of 2026

February 20, 2026

March 9, 2026

March 20, 2026

0.4265

Second Quarter of 2026

April 28, 2026

May 15, 2026

June 5, 2026

0.4265

Third Quarter of 2026

August 4, 2026

August 18, 2026

September 4, 2026

0.4265

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Credit Matters and Cash Requirements

We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of June 30, 2026, we have access to facilities with aggregate bank commitments of $14.5 billion. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

We had access to the commercial paper markets and had availability under our revolving credit facilities during the second quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.

Security Ratings

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of June 30, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of June 30, 2026, we had $7.0 billion of available capacity under our credit facilities and $0.7 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we would be required to access additional liquidity through the capital markets. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements. Our credit ratings were affirmed by Moody’s and S&P in January 2026 following the completion of the acquisition of Calpine.

If we had lost our investment grade credit ratings as of June 30, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.4 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.

See Note 12 — Derivative Financial Instruments and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Pension and Other Postretirement Benefits

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 contributions below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2026 for $161 million. Unlike the qualified pension plans, our non-qualified plans are not subject to statutory minimum contribution requirements.

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OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. 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. The estimated benefit payments to the non-qualified pension plans in 2026 are approximately $25 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $64 million. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on pension and other postretirement benefits.

Cash Requirements for Other Financial Commitments

In connection with the acquisition of Calpine in January 2026, we assumed approximately $3 billion of projected cash payments under existing financial commitments with fixed or minimum payments required. These commitments exclude future cash payments for debt service on assumed debt as much of the debt was refinanced or paid off following the acquisition. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other than as described above and elsewhere in this Quarterly Report on Form 10-Q, there have been no material changes to the cash requirements from contractual and other obligations disclosed in our 2025 Annual Report on Form 10-K. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on our cash requirements for financial commitments.

Accounts Receivable Facilities

We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain accounts receivables. As a result of our acquisition of Calpine in January 2026, we assumed Calpine's accounts receivable sales program which allows for the sale of certain Calpine receivables at a nominal discount. See Note 7 — Accounts Receivable and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Project Financing

Project financing is based upon a financial structure in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the 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. As a result of our acquisition of Calpine in January 2026, we assumed various project financing arrangements. See Note 16 — Debt and Credit Agreements of our 2025 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt.

Credit Facilities

We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. We assumed various credit facilities as part of the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.

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NRC Minimum Funding Requirements

NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.

As of June 30, 2026, the Crane NDT is fully funded under the SAFSTOR scenario that is the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of June 30, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.


ITEM 3.			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Dollars in millions, unless otherwise noted)

We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Executive Committee and the Audit and Risk Committee of the Board of Directors have oversight responsibilities for risk management. The following discussion serves as an update to ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2025 Annual Report on Form 10-K incorporated herein by reference.

Commodity Price Risk

Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors. To the extent the total 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 commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities.

Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures in locations and periods where our load serving activities do not naturally offset existing generation portfolio risk. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. We expect the settlement of the majority of our economic hedges will occur during 2026 through 2028. We also enter into transactions that further optimize the economic benefits of our overall portfolio.

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The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure as of June 30, 2026 for our portfolio associated with a hypothetical $10/MWh reduction in the annual average around-the-clock energy price and $5/MWh reduction in around-the-clock spark spread results in an impact to earnings that is not material for 2026 and 2027. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Fuel Procurement

We procure natural gas through long-term and short-term contracts, and spot-market purchases. We also enter into natural gas transportation and storage contracts that allow us to source reliable and cost-effective natural gas for our fleet and to take advantage of favorable market pricing, regardless of when the gas is used in our operations. Fuel oil inventories are managed so that, in the winter months, sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.

Nuclear fuel is obtained predominantly through long-term contracts for uranium concentrates, conversion services, enrichment services, (or a combination thereof) and fabrication services, including contracts sourced from Russia. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 30% of our uranium concentrate requirements for the remainder of 2026 through 2031 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Other Key Business Drivers for additional information on the Russia and Ukraine conflict.

Commodity Derivative Activity

The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from December 31, 2025 to June 30, 2026. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the commodity derivative contract net assets (liabilities) recorded as of June 30, 2026 and December 31, 2025.


Balance as of December 31, 2025(a)	$	504
Net change in fair value of contracts recorded in results of operations	898
Reclassification to realized at settlement of contracts recorded in results of operations	(274)
Changes in allocated collateral	335
Contracts acquired at acquisition date(b)	1,403
Amortization of acquired contracts(b)	(423)
Net option premium paid (received)	52
Option premium amortization	30
Upfront payments and amortizations(c)	(4)
Foreign currency translation	(1)
Balance as of June 30, 2026(a)	$	2,520

__________

(a)Amounts are shown net of collateral paid to and received from counterparties.

(b)Includes amounts related to contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

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(c)Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.

Fair Values

The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 14 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.


	Maturities Within												Total Fair Value
	2026		2027		2028		2029		2030		2031 and Beyond
Commodity derivative contracts(a):
Actively quoted prices (Level 1)	$	81	$	(110)	$	(32)	$	(11)	$	1	$	5	$	(66)
Prices provided by external sources (Level 2)	601		327		24		(29)		—		—		923
Prices based on model or other valuation methods (Level 3)	223		425		426		190		96		303		1,663
Total	$	905	$	642	$	418	$	150	$	97	$	308	$	2,520

__________

(a)Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $2,283 million at June 30, 2026.

Credit Risk

We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.

Credit-Risk-Related Contingent Features

As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. 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. See Note 12 — Derivative Financial Instruments and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.

We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information.

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RTOs and ISOs

We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold primarily through bilateral agreements. For activities administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our consolidated financial statements.

Exchange Traded Transactions

We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.

Interest Rate Risk

We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure, including derivatives to lock in rate levels in anticipation of future financings. A hypothetical 50 basis points change in interest rates associated with unhedged variable-rate long-term debt and interest rate swaps would not have resulted in a material impact to our earnings for the six months ended June 30, 2026. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Equity Price Risk

We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.

A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $1,129 million reduction in the fair value of our NDT trust assets as of June 30, 2026. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information.

Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.

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PART II. OTHER INFORMATION

(Dollars in millions except per share data, unless otherwise noted)


ITEM 1.			LEGAL PROCEEDINGS

We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this report. Such descriptions are incorporated herein by these references.


ITEM 1A.			RISK FACTORS

At June 30, 2026, our risk factors were consistent with the risk factors described in our 2025 Form 10-K in ITEM 1A. RISK FACTORS which was inclusive of the risks related to the Calpine acquisition and its operations.


ITEM 2.			UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities (CEG Parent)

During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining $0.6 billion authorization under our share repurchase program. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $2.8 billion of remaining authority for repurchases. See Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.

No accelerated share repurchases occurred under the program during the six months ended June 30, 2026.

The following table provides information regarding our share repurchases under the program during the three months ended June 30, 2026.


Period	Total Number of Shares Purchased(a)	Average Price Paid per Share		Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs(b)
April 1, 2026 to April 30, 2026(c)	1,175,521	$	284.75	$	4,658
May 1, 2026 to May 31, 2026(c)	2,088,837	276.71		4,080
June 1, 2026 to June 30, 2026(c)(d)	3,873,974	273.10		3,022
Total	7,138,332	$	276.08	$	3,022

__________

(a)We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above.

(b)Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions.

(c)Includes repurchases under open market repurchase agreements. See Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

(d)Includes repurchases under secondary public offering. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.


ITEM 4.			MINE SAFETY DISCLOSURES

Not Applicable.

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ITEM 5.			OTHER INFORMATION

Rule 10b5-1 Trading Plans

Except as set forth below, during the three months ended June 30, 2026, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act).

On May 18, 2026, Andrew Novotny, Senior Executive Vice President, Constellation Power Operations, and President and CEO, Calpine, entered into a stock trading plan designed to comply with Rule 10b5-1 under the Exchange Act. Under the terms of the plan, Mr. Novotny is scheduled to sell an aggregate of 118,915 shares of common stock in trades scheduled from August 2026 through January 2027. The plan will terminate on January 15, 2027.


ITEM 6.			EXHIBITS


Certain of the following exhibits are incorporated herein by reference under Rule 12b-32 of the Exchange Act.

Exhibit No.			Description
4 .1			Form of 4.550% Senior Notes due June 1, 2029 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.1)

4 .2			Form of 4.800% Senior Notes due January 15, 2032 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.2)

4 .3			Form of 5.300% Senior Notes due June 1, 2036 (File No. 333-85496, Form 8-K dated May 14, 2026, Exhibit 4.3)

Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026 filed by the following officers for the following registrants:

Exhibit No.			Description
31.1			Filed by Joseph Dominguez for Constellation Energy Corporation

31.2			Filed by Shane P. Smith for Constellation Energy Corporation

31.3			Filed by Joseph Dominguez for Constellation Energy Generation, LLC

31.4			Filed by Shane P. Smith for Constellation Energy Generation, LLC

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2026 filed by the following officers for the following registrants:

Exhibit No.			Description
32.1			Filed by Joseph Dominguez for Constellation Energy Corporation

32.2			Filed by Shane P. Smith for Constellation Energy Corporation

32.3			Filed by Joseph Dominguez for Constellation Energy Generation, LLC

32.4			Filed by Shane P. Smith for Constellation Energy Generation, LLC

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Exhibit No.			Description
101.INS			Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.

101.SCH			Inline XBRL Taxonomy Extension Schema Document.

101.CAL			Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF			Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB			Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE			Inline XBRL Taxonomy Extension Presentation Linkbase Document.

104			Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)


ITEM 4.			CONTROLS AND PROCEDURES

Disclosure Controls and Procedures

During the second quarter of 2026, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.

Accordingly, as of June 30, 2026, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.

Changes in Internal Control Over Financial Reporting

We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the second quarter of 2026 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting.

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SIGNATURES

Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONSTELLATION ENERGY CORPORATION


/s/ JOSEPH DOMINGUEZ						/s/ SHANE P. SMITH
Joseph Dominguez						Shane P. Smith
President and Chief Executive Officer (Principal Executive Officer)						Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller (Principal Accounting Officer)

August 6, 2026

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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

CONSTELLATION ENERGY GENERATION, LLC


/s/ JOSEPH DOMINGUEZ						/s/ SHANE P. SMITH
Joseph Dominguez						Shane P. Smith
President and Chief Executive Officer (Principal Executive Officer)						Executive Vice President and Chief Financial Officer (Principal Financial Officer)

/s/ MATTHEW N. BAUER
Matthew N. Bauer
Senior Vice President and Controller (Principal Accounting Officer)

August 6, 2026

Constellation Energy - 10-Q quarterly report FY2026 Q2

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