10-Q – 2026-05-11 – ceg-20260331.htm

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ceg:OtherAvailableForSaleDebtSecurityInvestmentsMember 2025-12-31

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 March 31, 2026
  or

☐  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 x No ☐
Constellation Energy Generation, LLC Yes x No ☐

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 x Accelerated Filer ☐
Non-accelerated Filer ☐
Smaller Reporting Company ☐
Emerging Growth Company ☐

Constellation Energy Generation, LLC Large Accelerated Filer ☐
Accelerated Filer ☐
Non-accelerated Filer x 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 April 30, 2026 was as follows:

Constellation Energy Corporation Common Stock, without par value 361,190,063  
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
9

Consolidated Statements of Cash Flows
10

Consolidated Balance Sheets
11

Consolidated Statements of Changes in Equity
12

Combined Notes to Consolidated Financial Statements

1. Basis of Presentation
13

2. Mergers, Acquisitions, and Dispositions
13

3. Regulatory Matters
17

4. Revenue from Contracts with Customers
18

5. Segment Information
19

6. Government Assistance
21

7. Accounts Receivable
22

8. Property, Plant, and Equipment
23

9. Asset Retirement Obligations
24

10. Income Taxes
25

11. Retirement Benefits
27

12. Derivative Financial Instruments
27

13. Debt and Credit Agreements
32

14. Fair Value of Financial Assets and Liabilities
38

15. Commitments and Contingencies
42

16. Shareholders' Equity
44

17. Variable Interest Entities
45

18. Supplemental Financial Information
47

ITEM 2.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
50

Executive Overview
50

Significant Transactions and Developments
51

Other Key Business Drivers
52

Critical Accounting Policies and Estimates
53

Financial Results of Operations
53

Liquidity and Capital Resources
64

Properties
67

ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
70

ITEM 4.
CONTROLS AND PROCEDURES
74

PART II
OTHER INFORMATION
75

ITEM 1.
LEGAL PROCEEDINGS
75

ITEM 1A.
RISK FACTORS
75

ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
75

ITEM 4.
MINE SAFETY DISCLOSURES
75

ITEM 5.
OTHER INFORMATION
75

ITEM 6.
EXHIBITS
76

SIGNATURES
79

Constellation Energy Corporation
79

Constellation Energy Generation, LLC
80

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
NMP 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

West Medway II West Medway Generating Station II

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

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

1

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

2

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
SO 2
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

3

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 March 31,
(In millions, except per share data) 2026 2025
Operating revenues $ 11,122   $ 6,788  

Operating expenses
Purchased power and fuel 6,352   4,384  

Operating and maintenance 1,780   1,545  

Depreciation and amortization 443   248  
Taxes other than income taxes 229   160  
Total operating expenses 8,804   6,337  

Gain (loss) on sales of assets
14   —  

Operating income (loss) 2,332   451  
Other income and (deductions)
Interest expense, net ( 253 ) ( 146 )

Other, net 46   ( 154 )
Total other income and (deductions) ( 207 ) ( 300 )
Income (loss) before income taxes 2,125   151  
Income tax (benefit) expense 530   22  
Equity in income (losses) of unconsolidated affiliates 8   —  
Net income (loss) 1,603   129  
Net income (loss) attributable to noncontrolling interests 13   11  
Net income (loss) attributable to common shareholders $ 1,590   $ 118  
Comprehensive income (loss), net of income taxes
Net income (loss) $ 1,603   $ 129  
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost ( 1 ) —  
Actuarial loss reclassified to periodic cost 28   17  
Pension and non-pension postretirement benefit plan valuation adjustment ( 25 ) ( 34 )
Unrealized gain (loss) on cash flow hedges 1   2  
Unrealized gain (loss) on foreign currency translation ( 3 ) 8  
Other comprehensive income (loss), net of income taxes —   ( 7 )
Comprehensive income (loss) 1,603   122  
Comprehensive income (loss) attributable to noncontrolling interests 13   11  
Comprehensive income (loss) attributable to common shareholders $ 1,590   $ 111  

Average shares of common stock outstanding:
Basic 354   313  
Assumed exercise and/or distributions of stock-based awards —   1  
Diluted 354   314  

Earnings per average common share
Basic $ 4.49   $ 0.38  
Diluted $ 4.49   $ 0.38  

See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)

Three Months Ended March 31,
(In millions) 2026 2025
Cash flows from operating activities
Net income (loss) $ 1,603   $ 129  
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 1,202   640  

Deferred income taxes and amortization of ITCs 440   ( 98 )
Net fair value changes related to derivatives ( 1,040 ) 356  
Net realized and unrealized (gains) losses on NDT funds ( 17 ) ( 44 )
Net realized and unrealized (gains) losses on equity investments 27   268  
Other non-cash operating activities ( 199 ) 47  
Changes in assets and liabilities:
Accounts receivable 323   ( 15 )

Inventories 106   98  
Accounts payable and accrued expenses ( 1,377 ) ( 290 )
Option premiums received (paid), net ( 15 ) 26  
Collateral received (posted), net 249   ( 486 )
Income taxes 103   120  
Pension and non-pension postretirement benefit contributions ( 191 ) ( 174 )
Other assets and liabilities ( 789 ) ( 470 )
Net cash flows provided by (used in) operating activities 425   107  
Cash flows from investing activities
Capital expenditures ( 1,275 ) ( 806 )
Proceeds from NDT fund sales 2,504   2,084  
Investment in NDT funds ( 2,572 ) ( 2,152 )
Acquisition of Calpine, net of cash and restricted cash acquired ( 2,537 ) —  

Other investing activities 148   ( 12 )
Net cash flows provided by (used in) investing activities ( 3,732 ) ( 886 )
Cash flows from financing activities
Change in short-term borrowings 1,957   —  
Proceeds from short-term borrowings with maturities greater than 90 days 3,000   —  
Repayments of short-term borrowings with maturities greater than 90 days ( 1,500 ) —  
Issuance of long-term debt 2,770   —  
Retirement of long-term debt ( 5,254 ) ( 57 )
Dividends paid on common stock ( 155 ) ( 122 )

Other financing activities ( 88 ) ( 229 )
Net cash flows provided by (used in) financing activities 730   ( 408 )
Increase (decrease) in cash, restricted cash, and cash equivalents ( 2,577 ) ( 1,187 )
Cash, restricted cash, and cash equivalents at beginning of period 3,748   3,129  
Cash, restricted cash, and cash equivalents at end of period $ 1,171   $ 1,942  

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 ( 889 ) ( 6 )

See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Corporation and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) March 31, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 800   $ 3,641  
Restricted cash and cash equivalents 371   107  
Accounts receivable, net 4,414   4,266  

Derivative assets 1,795   945  

Inventories, net 2,582   1,736  

Renewable energy credits 1,038   789  
Assets held for sale 5,735   126  
Other 1,274   509  
Total current assets 18,009   12,119  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,524 and $ 19,072 , respectively)
40,769   22,474  
Deferred debits and other assets

Nuclear decommissioning trust funds 19,366   19,336  

Goodwill 11,527   420  
Derivative assets 2,113   450  

Other 5,127   2,450  
Total deferred debits and other assets 38,133   22,656  
Total assets (a)
$ 96,911   $ 57,249  

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 5,102   $ 1,650  
Long-term debt due within one year 370   92  

Accounts payable and accrued expenses 4,449   4,294  

Derivative liabilities 810   467  

Renewable energy credit obligation 1,193   1,075  

Other 1,291   366  
Total current liabilities 13,215   7,944  
Long-term debt 16,994   7,250  

Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 8,199   3,544  
Asset retirement obligations 12,433   13,193  
Pension and non-pension postretirement benefit obligations 1,835   1,977  

Payables related to Regulatory Agreement Units 5,389   5,334  
Derivative liabilities 518   414  

Other 4,508   2,740  
Total deferred credits and other liabilities 32,882   27,202  
Total liabilities (a)
63,091   42,396  
Commitments and contingencies (Note 15)

Shareholders' equity
Common stock ( No par value, 1,000 shares authorized, 362 and 312 shares outstanding, respectively)
28,574   11,043  
Retained earnings (deficit) 7,334   5,899  
Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,425 )
Total shareholders' equity 33,483   14,517  
Noncontrolling interests 337   336  
Total equity 33,820   14,853  
Total liabilities and shareholders' equity $ 96,911   $ 57,249  

__________
(a) Our consolidated assets include $ 4,609  million and $ 4,551  million at March 31, 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 $ 2,381  million and $ 914  million at March 31, 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

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Table of Contents

Constellation Energy Corporation and Subsidiary Companies
Consolidated Statements of Changes in Equity
(Unaudited)

Three Months Ended March 31, 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  

Three Months Ended March 31, 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  

See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Operations and Comprehensive Income
(Unaudited)

Three Months Ended March 31,
(In millions) 2026 2025
Operating revenues $ 11,122   $ 6,788  

Operating expenses
Purchased power and fuel 6,352   4,384  

Operating and maintenance 1,780   1,545  

Depreciation and amortization 443   248  
Taxes other than income taxes 229   160  
Total operating expenses 8,804   6,337  

Gain (loss) on sales of assets
14   —  

Operating income (loss) 2,332   451  
Other income and (deductions)
Interest expense, net ( 253 ) ( 146 )

Other, net 46   ( 154 )
Total other income and (deductions) ( 207 ) ( 300 )
Income (loss) before income taxes 2,125   151  
Income tax (benefit) expense 530   22  
Equity in income (losses) of unconsolidated affiliates 8   —  
Net income (loss) 1,603   129  
Net income (loss) attributable to noncontrolling interests 13   11  
Net income (loss) attributable to membership interest $ 1,590   $ 118  
Comprehensive income (loss), net of income taxes
Net income (loss) $ 1,603   $ 129  
Other comprehensive income (loss), net of income taxes
Pension and non-pension postretirement benefit plans:
Prior service benefit reclassified to periodic benefit cost ( 1 ) —  
Actuarial loss reclassified to periodic cost 28   17  
Pension and non-pension postretirement benefit plan valuation adjustment ( 25 ) ( 34 )
Unrealized gain (loss) on cash flow hedges 1   2  
Unrealized gain (loss) on foreign currency translation ( 3 ) 8  
Other comprehensive income (loss), net of income taxes —   ( 7 )
Comprehensive income (loss) 1,603   122  
Comprehensive income (loss) attributable to noncontrolling interests 13   11  
Comprehensive income (loss) attributable to membership interest $ 1,590   $ 111  

See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Cash Flows
(Unaudited)

Three Months Ended March 31,
(In millions) 2026 2025
Cash flows from operating activities
Net income (loss) $ 1,603   $ 129  
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 1,202   640  

Deferred income taxes and amortization of ITCs 440   ( 98 )
Net fair value changes related to derivatives ( 1,040 ) 356  
Net realized and unrealized (gains) losses on NDT funds ( 17 ) ( 44 )
Net realized and unrealized (gains) losses on equity investments 27   268  
Other non-cash operating activities ( 229 ) 24  
Changes in assets and liabilities:
Accounts receivable 330   ( 15 )
Receivables from and payables to affiliates, net ( 272 ) ( 259 )
Inventories 106   98  
Accounts payable and accrued expenses ( 1,386 ) ( 301 )
Option premiums received (paid), net ( 15 ) 26  
Collateral received (posted), net 249   ( 486 )
Income taxes 103   120  
Pension and non-pension postretirement benefit contributions ( 191 ) ( 174 )
Other assets and liabilities ( 527 ) ( 257 )
Net cash flows provided by (used in) operating activities 383   27  
Cash flows from investing activities
Capital expenditures ( 1,275 ) ( 806 )
Proceeds from NDT fund sales 2,504   2,084  
Investment in NDT funds ( 2,572 ) ( 2,152 )

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

Other investing activities 150   ( 12 )
Net cash flows provided by (used in) investing activities ( 3,730 ) ( 886 )
Cash flows from financing activities
Change in short-term borrowings 1,957   —  
Proceeds from short-term borrowings with maturities greater than 90 days 3,000   —  
Repayments of short-term borrowings with maturities greater than 90 days ( 1,500 ) —  
Issuance of long-term debt 2,770   —  
Retirement of long-term debt ( 5,254 ) ( 57 )
Distributions to member ( 155 ) ( 272 )

Other financing activities ( 55 ) ( 5 )
Net cash flows provided by (used in) financing activities 763   ( 334 )
Increase (decrease) in cash, restricted cash, and cash equivalents ( 2,584 ) ( 1,193 )
Cash, restricted cash, and cash equivalents at beginning of period 3,720   3,115  
Cash, restricted cash, and cash equivalents at end of period $ 1,136   $ 1,922  

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 ( 889 ) ( 6 )

See the Combined Notes to Consolidated Financial Statements

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Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Balance Sheets
(Unaudited)

(In millions) March 31, 2026 December 31, 2025
ASSETS
Current assets
Cash and cash equivalents $ 785   $ 3,641  
Restricted cash and cash equivalents 351   79  
Accounts receivable, net 4,392   4,251  

Derivative assets 1,795   945  

Inventories, net 2,582   1,736  

Renewable energy credits 1,038   789  
Assets held for sale 5,735   126  
Other 1,282   508  
Total current assets 17,960   12,075  
Property, plant, and equipment (net of accumulated depreciation and amortization of $ 19,524 and $ 19,072 , respectively)
40,769   22,474  
Deferred debits and other assets

Nuclear decommissioning trust funds 19,366   19,336  

Goodwill 11,527   420  
Derivative assets 2,113   450  

Other 5,120   2,443  
Total deferred debits and other assets 38,126   22,649  
Total assets (a)
$ 96,855   $ 57,198  

LIABILITIES AND EQUITY
Current liabilities
Short-term borrowings $ 5,102   $ 1,650  
Long-term debt due within one year 370   92  

Accounts payable and accrued expenses 4,324   4,033  
Payables to affiliates 102   365  

Derivative liabilities 810   467  

Renewable energy credit obligation 1,193   1,075  

Other 1,289   358  
Total current liabilities 13,190   8,040  
Long-term debt 16,994   7,250  

Deferred credits and other liabilities
Deferred income taxes and unamortized ITCs 8,199   3,544  
Asset retirement obligations 12,433   13,193  
Pension and non-pension postretirement benefit obligations 1,835   1,977  

Payables related to Regulatory Agreement Units 5,389   5,334  
Derivative liabilities 518   414  

Other 4,465   2,583  
Total deferred credits and other liabilities 32,839   27,045  
Total liabilities (a)
63,023   42,335  
Commitments and contingencies (Note 15)

Equity
Member’s equity
Membership interest 27,677   10,144  
Undistributed earnings (deficit) 8,243   6,808  
Accumulated other comprehensive income (loss), net ( 2,425 ) ( 2,425 )
Total member’s equity 33,495   14,527  
Noncontrolling interests 337   336  
Total equity 33,832   14,863  
Total liabilities and equity $ 96,855   $ 57,198  
__________
(a) Our consolidated assets include $ 4,609  million and $ 4,551 million as of March 31, 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 $ 2,381 million and $ 914 million as of March 31, 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

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Table of Contents

Constellation Energy Generation, LLC and Subsidiary Companies
Consolidated Statements of Changes in Equity
(Unaudited)

Three Months Ended March 31, 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  

Three Months Ended March 31, 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  

See the Combined Notes to Consolidated Financial Statements

12

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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 March 31, 2026 and for the three months ended March 31, 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 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.
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 will be subject to a lock-up period, which expires on June 30, 2026, for 50 % of the shares and on June 30, 2027, for the remaining 50 %.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

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. Closing of the sale is subject to receipt of applicable regulatory approvals, including review by the DOJ and FERC, and other customary closing conditions. We are taking steps to divest the ERCOT plant, the last asset sale required to satisfy our regulatory commitments under the merger. Certain of the generation assets being sold are currently secured under project financing arrangements, 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 2 — Mergers, Acquisitions, and Dispositions

Purchase Price Allocation
The following table presents the preliminary allocation of the total merger consideration to the identifiable assets acquired and liabilities assumed as of the Acquisition Date. The allocation is preliminary and subject to revision during the measurement period, which will not exceed one year from the Acquisition Date. Adjustments to provisional amounts will be recognized in the reporting period in which they are identified, with a corresponding adjustment to goodwill.

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  

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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 and 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. Goodwill will be assigned to the reporting units expected to benefit from the acquisition. The assignment of goodwill to the reporting units has not been completed as of the date of these financial statements due to the preliminary nature of the purchase price allocation. 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 preliminary 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 months ended March 31, 2026.
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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 months ended March 31, 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 March 31,
Unaudited pro forma financial information 2026 2025
Operating revenues $ 11,352   $ 9,321  
Net income (a)
1,590   147  
__________
(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. From the Acquisition Date through March 31, 2026, Operating revenues attributable to Calpine were $ 3,136 million . 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. We have requested that FERC grant the requested waiver no later than June 1, 2026.
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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 March 31, 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 $ 1,342   $ 1,757   $ 1,494   $ 1,415   $ 889   $ 5,137   $ 12,034  

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/SPP, and International Power (which includes operations in the United Kingdom and Canada).

Three Months Ended March 31, 2026 Power and Power-related Revenues (a)
Capacity Revenues (b)
Other Revenues Total

PJM $ 3,330   $ 130   $ —   $ 3,460  
MISO 252   6   —   258  
ERCOT 360   99   —   459  
NYISO 745   13   —   758  
ISO-NE 1,014   4   —   1,018  
West 168   160   —   328  
SERC/SPP 59   4   —   63  
International Power 109   —   —   109  
Total Power revenues 6,037   416   —   6,453  
Gas revenues (c)
—   —   943   943  
Other revenues (d)
—   —   145   145  
Total revenue from contracts with customers 6,037   416   1,088   7,541  
Other revenue sources (e)
—   —   3,581   3,581  
Total Operating revenues
$ 6,037   $ 416   $ 4,669   $ 11,122  

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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 4 — Revenue from Contracts with Customers

Three Months Ended March 31, 2025 Power and Power-related Revenues (a)
Capacity Revenues (b)
Other Revenues Total

PJM $ 2,698   $ 8   $ —   $ 2,706  
MISO 214   —   —   214  
ERCOT 301   —   —   301  
NYISO 675   —   —   675  
ISO-NE 1,109   —   —   1,109  
West 146   1   —   147  
SERC/SPP 35   3   —   38  
International Power 48   —   —   48  
Total Power revenues 5,226   12   —   5,238  
Gas revenues (c)
—   —   782   782  
Other revenues (d)
—   —   86   86  
Total revenue from contracts with customers 5,226   12   868   6,106  
Other revenue sources (e)
—   —   682   682  
Total Operating revenues
$ 5,226   $ 12   $ 1,550   $ 6,788  
__________
(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 certain 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 will be reviewed by the CODM separately from our historical reporting segments.
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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

• 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, and Canada.
Constellation's CEO is considered the CODM and evaluates the performance of our electric business activities and allocates resources based on segment RNF, primarily through review of budget-to-actual variance analyses. RNF is Operating revenues net of Purchased power and fuel expenses. We believe this is a useful measurement of operational performance, although it is not a presentation defined under GAAP and may not be comparable to other companies’ presentations 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 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.
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 months ended March 31, 2026 and 2025.

Three Months Ended March 31, 2026 Total Operating revenues Total Purchased power and fuel expenses Total RNF
Mid-Atlantic $ 1,847   $ ( 1,035 ) $ 812  
Midwest 1,732   ( 878 ) 854  
New York 569   ( 160 ) 409  
ERCOT 370   ( 161 ) 209  
Other Power Regions 1,487   ( 1,220 ) 267  
Calpine
2,395   ( 1,269 ) 1,126  
Total Reportable Segments 8,400   ( 4,723 ) 3,677  
Other (a)
2,722   ( 1,629 ) 1,093  
Total Consolidated Results $ 11,122   $ ( 6,352 ) $ 4,770  

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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 5 — Segment Information

Three Months Ended March 31, 2025 Total Operating revenues Total Purchased power and fuel expenses Total RNF
Mid-Atlantic $ 1,665   $ ( 856 ) $ 809  
Midwest 1,404   ( 554 ) 850  
New York 562   ( 161 ) 401  
ERCOT 398   ( 184 ) 214  
Other Power Regions 1,556   ( 1,362 ) 194  

Total Reportable Segments 5,585   ( 3,117 ) 2,468  
Other (a)
1,203   ( 1,267 ) ( 64 )
Total Consolidated Results $ 6,788   $ ( 4,384 ) $ 2,404  

__________
(a) Represents activities not allocated to a segment. See text above for a description of included activities. Operating revenues include unrealized gains of $ 1,315 million and losses of $ 287 million for the three months ended March 31, 2026 and 2025, respectively. Purchased power and fuel expenses include unrealized losses of $ 254 million and $ 34 million for the three months ended March 31, 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.
For the three months ended March 31, 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 March 31, 2026 and December 31, 2025, our Consolidated Balance Sheets reflect approximately $ 125  million and $ 120  million, respectively, of nuclear PTCs within Other deferred debits and other assets. For the three months ended March 31, 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 March 31, 2026 and December 31, 2025, we have recognized approximately $ 740  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 three months ended March 31, 2026, we refunded or offset against outstanding receivables approximately $ 450  million associated with state-sponsored program compensation relating to the nuclear PTCs recorded in 2024. During the three months ended March 31, 2026, we recognized a reduction to net operating revenue of approximately $ 285  million 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 $ 110  million for the three months ended March 31, 2025.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

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

Accounts receivable, net
March 31, 2026 CEG Parent Constellation
Customer accounts receivable (net of allowance for credit losses of $ 157 for CEG Parent and Constellation)
$ 3,960   $ 3,960  
Other accounts receivable (net of allowance for credit losses of $ — for CEG Parent and Constellation)
454   432  
Total $ 4,414   $ 4,392  

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 March 31, 2026.

Balance as of January 1, 2026
$ 158  
Current period provision for expected credit losses
15  
Write-offs, net of recoveries (a)
( 16 )

Balance as of March 31, 2026
$ 157  

__________
(a) Recoveries were not material.
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 $ 1,465  million and $ 1,305  million of unbilled customer revenues in Accounts receivable, net in the Consolidated Balance Sheets as of March 31, 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 7 — Accounts Receivable

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 March 31, 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 $ 564 million in gross accounts receivable outstanding that were sold at a nominal discount under the Calpine AR Facility as of March 31, 2026 and the $ 500  million facility amount was fully utilized. The following table summarizes certain activity for the period under the Calpine AR Facility:

Three Months Ended March 31, 2026
Aggregate receivables sold during the period $ 1,205  
Proceeds collected on sold receivables
1,126  

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 $ 1,244 million and $ 1,147 million for the three months ended March 31, 2026 and 2025, respectively.

8. Property, Plant, and Equipment
The following table presents a summary of property, plant, and equipment by asset category as of March 31, 2026 and December 31, 2025:

Asset Category March 31, 2026 December 31, 2025
Electric (a)
$ 49,844   $ 33,253  
Nuclear fuel 6,712   6,298  
CWIP (a)
3,737   1,995  

Total property, plant, and equipment 60,293   41,546  
Less: accumulated depreciation 19,524   19,072  
Property, plant, and equipment, net (b)
$ 40,769   $ 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 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 9 — Asset Retirement Obligations

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 March 31, 2026:

Balance as of December 31, 2025
$ 12,908  

Accretion expense 165  
Net decrease due to changes in, and timing of, estimated future cash flows
( 1,277 )
Costs incurred related to decommissioning plants ( 4 )

Balance as of March 31, 2026
$ 11,792  

During the three months ended March 31, 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 c hanges in assumed retirement dates for various plants, including Calvert Cliffs, Fitzpatrick, Limerick, and Nine Mile Point.
The 2026 ARO update resulted in a decrease of $ 285 million in Operating and maintenance expense for the three months ended March 31, 2026 in the Consolidated Statements of Operations and Comprehensive income.
NDT Funds
We had NDT funds totaling $ 19,494 million and $ 19,396  million as of March 31, 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, wer e not material as of March 31, 2026 and December 31, 2025. See Note 18 — Supplemental Financial Information for additional information on activities of the NDT funds.
Accounting Implications of the Regulatory Agreement Units
See Note 1 — Basis of Presentation 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 March 31, 2026 and December 31, 2025:

March 31, 2026 December 31, 2025
ComEd $ 4,297   $ 4,313  
PECO 533   442  
CenterPoint
416   430  
AEP Texas
143   149  
Payables related to Regulatory Agreement Units $ 5,389   $ 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.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 9 — Asset Retirement Obligations

Non-Nuclear Asset Retirement Obligations
We have AROs for plant closure costs associated with our natural gas, oil, battery storage, and renewable generating facilities. 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 March 31, 2026:

Balance as of December 31, 2025
$ 317  
Acquisition of Calpine (a)
350  

Accretion expense 9  
Costs incurred related to decommissioning plants
( 1 )
Balance as of March 31, 2026
$ 675  

__________
(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.

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 March 31,
2026 2025
U.S. federal statutory income tax 21.0   % $ 446   21.0   % $ 32  
Increase (decrease) due to:

State income taxes, net of federal income tax benefit (a)
3.4   73   ( 0.7 ) ( 1 )
Foreign tax effects —   —   0.7   1  
Tax credits
PTC ( 0.2 ) ( 4 ) ( 1.3 ) ( 2 )
Amortization of ITC, including deferred taxes on basis differences ( 0.2 ) ( 5 ) ( 2.0 ) ( 3 )
Other ( 0.2 ) ( 5 ) ( 2.0 ) ( 3 )
Nontaxable or nondeductible items
Share-based payment awards ( 0.7 ) ( 14 ) ( 25.2 ) ( 38 )
Excess officers compensation 0.1   3   4.6   7  
Other 0.8   17   0.9   1  
Other adjustments
Qualified NDT fund income and losses 0.9   19   18.6   28  
Effective income tax (b)
24.9   % $ 530   14.6   % $ 22  

__________
(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.
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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 separation, 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 March 31, 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 February 2024, we executed an amendment to the TMA that modified the timing of Exelon's payment of amounts due to us. In March 2026, we adjusted our receivable under the TMA as a result of IRS Notice 2026-7, as discussed below. As of March 31, 2026 and December 31, 2025, respectively, we had $ 58 million and $ 175 million in Accounts receivable, net and $ 373 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.
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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.
T he following tables present the components of our net periodic benefit (credit) cost for the three months ended March 31, 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 March 31, 2026 2025 2026 2025 2026 2025
Components of net periodic benefit (credit) cost:
Service cost $ 22   $ 21   $ 5   $ 4   $ 27   $ 25  
Non-service components of pension benefits & OPEB (credit) cost:
Interest cost 99   102   20   19   119   121  
Expected return on assets ( 119 ) ( 122 ) ( 8 ) ( 8 ) ( 127 ) ( 130 )
Amortization of:
Prior service (credit) cost —   —   ( 1 ) ( 2 ) ( 1 ) ( 2 )
Actuarial (gain) loss 38   26   ( 1 ) ( 2 ) 37   24  

Non-service components of pension benefits & OPEB (credit) cost 18   6   10   7   28   13  
Net periodic benefit (credit) cost
$ 40   $ 27   $ 15   $ 11   $ 55   $ 38  

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.
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.
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Note 12 — Derivative Financial Instruments

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 electricity sales at a level that provides an acceptable return. We are also exposed to differences between the locational settlement prices of certain economic hedges and the hedged generating units. This price difference is actively managed through other instruments which include derivative congestion products, whose changes in fair value are recognized in earnings each period, and auction revenue rights, which are accounted for on an accrual basis.
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(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 March 31, 2026 and December 31, 2025:

March 31, 2026 Economic Hedges
Collateral (a)
Netting (a)
Total
Derivative assets (current) $ 13,711   $ 453   $ ( 12,436 ) $ 1,728  
Derivative assets (noncurrent) 8,352   306   ( 6,573 ) 2,085  
Total derivative assets 22,063   759   ( 19,009 ) 3,813  
Derivative liabilities (current) ( 13,807 ) 564   12,436   ( 807 )
Derivative liabilities (noncurrent) ( 7,446 ) 360   6,573   ( 513 )
Total derivative liabilities ( 21,253 ) 924   19,009   ( 1,320 )
Total derivative net assets (liabilities) $ 810   $ 1,683   $ —   $ 2,493  

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 March 31, 2026 and December 31, 2025:

Total Net Position (In Millions)

Commodity Type
March 31, 2026 December 31, 2025 Unit of Measure

Electricity (a)
( 638 ) ( 260 ) MWh

Natural Gas (a)
1,576 33 MMBtu

Emissions
( 28 ) ( 35 ) Short Ton

_________
(a) The increase of net notional position at March 31, 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 months ended March 31, 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 March 31,
Income Statement Location 2026 2025
Operating revenues $ 1,311   $ ( 287 )
Purchased power and fuel ( 252 ) ( 37 )
Total $ 1,059   $ ( 324 )

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Note 12 — Derivative Financial Instruments

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 $ 4.6 billion and $ 1.4 billion as of March 31, 2026 and December 31, 2025, respectively.
The derivative assets and liabilities as of March 31, 2026 and December 31, 2025 and the gains and losses associated with management of interest rate risk for the three months ended March 31, 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 t ransactions 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 March 31, 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 March 31, 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 $ 1,979   $ 41   $ 1,938   1   $ 457  
Non-investment grade 86   18   68   —   —  
No external ratings
Internally rated — investment grade 151   5   146   —   —  
Internally rated — non-investment grade 319   58   261   —   —  
Total $ 2,535   $ 122   $ 2,413   1   $ 457  
__________
(a) As of March 31, 2026, credit collateral held from counterparties where we had credit exposure included $ 36 million of cash and $ 86 million of letters of credit.
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Note 12 — Derivative Financial Instruments

Net Credit Exposure by Type of Counterparty As of March 31, 2026
Investor-owned utilities, marketers, power producers $ 1,218  
Financial Institutions 599  
Energy cooperatives and municipalities 223  
Other 373  
Total $ 2,413  

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 March 31, 2026 December 31, 2025
Gross fair value of derivative contracts containing this feature
$ ( 2,321 ) $ ( 1,307 )
Offsetting fair value of derivative contracts under master netting arrangements
1,192   554  
Net fair value of derivative contracts containing this feature $ ( 1,129 ) $ ( 753 )

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As of March 31, 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.

March 31, 2026 December 31, 2025
Cash collateral posted
$ 1,904   $ 1,399  
Letters of credit posted
1,303   718  
Cash collateral held
221   47  
Letters of credit held
157   115  
Additional collateral required in the event of a credit downgrade below investment grade (at BB+/Ba1) (a)(b)(c)
2,972   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.

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 ("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 March 31, 2026, there were $ 1.3  billion and $ 44  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 Jack A. Fusco Energy Center (Fusco), 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 Fusco as guarantor depending on the application of
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Note 13 — Debt and Credit Agreements

net sales proceeds. The term loan matures July 2030 and bears interest at SOFR plus 1.75 %. As of March 31, 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 $ 1.20  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 York Energy Centers that partially secure the CDHI Revolver are subject to sale in accordance with the DOJ resolution. Under the terms of the CDHI revolver, consent of certain lenders is required to release these plants as collateral. 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. In March 2026 and April 2026, the CDHI revolver's total capacity was reduced by $ 250  million and $ 568  million, respectively. As of March 31, 2026, there was $ 309  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 finances 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 March 31, 2026, there was $ 581  million of borrowings outstanding under the credit agreement.
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 March 31, 2026, there was $ 330  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 are being 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 March 31, 2026, there was $ 246  million of borrowings outstanding under the loan.
Calpine Credit Agreements
As a result of the acquisition, we acquired 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 is 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 by CEG Parent, we commenced private exchange offers and related consent solicitations with respect to certain outstanding debt of Calpine ("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.
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Note 13 — Debt and Credit Agreements

The terms of the debt issuance 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 Secured Notes 3.750 % March 2031 795  
Total $ 2,290  

Senior Note Issuance
In January 2026, we issued senior unsecured notes totaling $ 2.75 billion, the proceeds from which were used to pay down Calpine debt assumed. The terms of the debt issuance are reflected in the Debt Issuances and Redemptions table below.
Long-term Debt Summary
The following table presents the outstanding long-term debt, as of March 31, 2026 and December 31, 2025:

Rates Maturity Date
March 31, 2026 December 31, 2025
Long-term debt
Senior unsecured notes (a)(b)
3.75 % - 6.50 %
2028 - 2066 $ 10,833   $ 5,688  
Tax-exempt notes (c)
4.10 % - 4.45 %
2029 - 2053 412   412  
Notes payable and other 1.71 % - 8.18 %
2026 - 2035 85   53  
Project finance: (b)

Variable rates 4.13 % - 5.98 %
2027 - 2030 5,274   597  
Fixed rates 2.29 % - 8.64 %
2031 - 2048 876   653  
Total long-term debt 17,480   7,403  
Unamortized debt discount and premium, net ( 16 ) ( 1 )
Unamortized fair value of debt
( 19 ) —  
Unamortized debt issuance costs ( 81 ) ( 60 )
Long-term debt due within one year ( 370 ) ( 92 )
Long-term debt $ 16,994   $ 7,250  
________
(a) Includes January 2026 debt issuance of $ 2.75  billion and exchanged debt of $ 2.3  billion.
(b) Includes debt assumed in acquisition of Calpine.
(c) 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.

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Note 13 — Debt and Credit Agreements

Debt Issuances and Redemptions
During the three months ended March 31, 2026, the following long-term debt was issued (redeemed):

Type (a)
Interest Rate Maturity Amount
2028 Senior Notes (b)
3.90 % January 2028 $ 900  
2066 Senior Notes (b)
5.875 % January 2066 800  
2031 Senior Notes (b)
4.40 % January 2031 750  
2028 Floating Rate Senior Notes (b)
SOFR + 0.60 %
January 2028 300  
Pin Oak Creek Energy Center 3.00 % October 2045 16  
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 ( 6 )
Greenfield CORRA + 1.875 %
November 2030 ( 7 )
Nova Power SOFR + 1.75 %
March 2028 ( 10 )
Calpine Development Holdings SOFR + 2.25 %
March 2028 ( 11 )
Continental Wind Nonrecourse Debt 6.00 % February 2033 ( 18 )
Geysers Power Company SOFR + 1.625 %
May 2029 ( 35 )
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) $ ( 2,484 )

__________
(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 is 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.
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
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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. Subsequently, in February and March 2026, we drew on the Facility in the amounts of $ 600  million and $ 900  million, respectively. The Facility was fully drawn on and outstanding as of March 31, 2026. In April 2026, we issued a $ 1.5  billion term loan, as discussed below, and used the proceeds to repay $ 400  million of the Facility.
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 March 31, 2026, the balance of our eligible receivables exceeded the cash proceeds outstanding from the Lenders.
Credit Facilities Summary
As of March 31, 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
March 31, 2026
Revolving Credit Facility $ 7,000   $ —   $ 701   $ 1,957   $ 4,342  
Bilateral and letter of credit facilities (c)(d)
4,100   —   2,632   —   1,468  
Accounts Receivable Facility 1,500   1,500   —   —   —  
CDHI Revolver (d)
908   309   —   —   599  
Liquidity Facility 971   —   758   —  

199   (e)

Project Finance (d)
571   44   453   —   74  
Total $ 15,050   $ 1,853   $ 4,544   $ 1,957   $ 6,682  

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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  
Bilaterals 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 March 31, 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 March 31, 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 3.98 % as of March 31, 2026. There were no commercial paper borrowings outstanding as of December 31, 2025.
(c) In February 2026, we increased the capacity to issue letters of credit by an additional $ 100  million each for two existing uncommitted bilateral facilities, and an additional $ 200  million for a third uncommitted bilateral facility. In February 2026, we initiated a new bilateral credit agreement for $ 400  million, with no maturity date. In February 2026, we entered into a $ 75  million uncommitted bilateral credit agreement. In March 2026, we increased the capacity to issue letters of credit for one committed bilateral facility by an additional $ 300  million and converted it to an uncommitted facility. In March 2026, a bilateral credit agreement initiated in March 2025 was extended for an additional two years to mature March 2028.
(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 March 31, 2026 and December 31, 2025, without posting additional collateral, the actual availability of facility, prior to outstanding letters of credit was $ 957  million and $ 959  million, respectively.
Short-Term Loan Agreements
As of March 31, 2026 and December 31, 2025, we had the following short-term loan agreements, both of which are unsecured and reflected in Short-term borrowings in the Consolidated Balance Sheets:

Month Initiated
Interest Rate Maturity
March 31, 2026
December 31, 2025

May 2025 (a)
1-month SOFR + 0.90 %
May 2026 $ 900   $ 900  
September 2025 1-month SOFR + 0.90 %
September 2026 750   750  
__________
(a) In April 2026, we initiated a term loan for $ 1.5  billion, the proceeds of which were used to repay the May 2025 term loan.
Debt Covenants
As of March 31, 2026, we are in compliance with all debt covenants.
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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 March 31, 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.

March 31, 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 $ 17,364   $ 13,994   $ 3,475   $ 17,469   $ 7,342   $ 6,995   $ 666   $ 7,661  
SNF Obligation (a)
1,440   1,308   —   1,308   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.

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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 March 31, 2026 and December 31, 2025:

March 31, 2026 December 31, 2025
Level 1 Level 2 Level 3 Total Level 1 Level 2 Level 3 Total
Assets
Cash equivalents (a)
$ 332   $ —   $ —   $ 332   $ 42   $ —   $ —   $ 42  
NDT fund investments
Cash equivalents (b)
290   163   —   453   72   165   —   237  
Equities 6,000   1,072   —   7,072   6,245   1,426   —   7,671  
Fixed income 2,536   1,478   401   4,415   2,201   1,566   395   4,162  
Private credit —   —   133   133   —   —   132   132  
Assets measured at NAV —  —  —  7,421   —  —  —  7,194  

NDT fund investments subtotal (c)
8,826   2,713   534   19,494   8,518   3,157   527   19,396  
Rabbi trust investments 65   43   1   109   66   45   1   112  
Investments in equities 60   —   —   60   87   —   —   87  
Derivative assets
Economic hedges 2,102   11,063   8,994   22,159   1,114   7,449   3,830   12,393  

Effect of netting and allocation of collateral
( 1,940 ) ( 10,361 ) ( 5,950 ) ( 18,251 ) ( 889 ) ( 6,853 ) ( 3,256 ) ( 10,998 )
Derivative assets subtotal 162   702   3,044   3,908   225   596   574   1,395  

Total assets measured at fair value 9,445   3,458   3,579   23,903   8,938   3,798   1,102   21,032  

Liabilities
Derivative liabilities
Economic hedges ( 2,349 ) ( 11,613 ) ( 7,300 ) ( 21,262 ) ( 1,148 ) ( 8,021 ) ( 4,062 ) ( 13,231 )
Effect of netting and allocation of collateral
2,222   11,283   6,429   19,934   1,065   7,657   3,628   12,350  
Derivative liabilities subtotal ( 127 ) ( 330 ) ( 871 ) ( 1,328 ) ( 83 ) ( 364 ) ( 434 ) ( 881 )
Deferred compensation obligation —   ( 110 ) —   ( 110 ) —   ( 124 ) —   ( 124 )
Total liabilities measured at fair value ( 127 ) ( 440 ) ( 871 ) ( 1,438 ) ( 83 ) ( 488 ) ( 434 ) ( 1,005 )
Total net assets $ 9,318   $ 3,018   $ 2,708   $ 22,465   $ 8,855   $ 3,310   $ 668   $ 20,027  

__________
(a) CEG Parent has $ 352 million and $ 70 million of Level 1 cash equivalents as of March 31, 2026 and December 31, 2025, respectively. We exclude cash of $ 734 million and $ 3,621 million, and restricted cash of $ 70 million and $ 57 million as of March 31, 2026 and December 31, 2025, respectively. CEG Parent has excluded an additional $ 15 million of cash as of March 31, 2026 and no additional cash exclusions as of December 31, 2025.
(b) Includes net liabilities of $ 231 million and $ 166 million as of March 31, 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 $ 1,053 million and $ 810 million as of March 31, 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.
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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 March 31, 2026, our NDTs have outstanding commitments to invest in private credit, private equity, and real assets of $ 493 million, $ 445 million, and $ 656 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 $ 113 million and $ 109 million as of March 31, 2026 and December 31, 2025, respectively. Changes in fair value, cumulative adjustments, and impairments were not material for the three months ended March 31, 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 months ended March 31, 2026 and 2025:

Three Months Ended March 31, 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) 2   848   (b)
—   850  
Included in Payables related to Regulatory Agreement Units
5   —   —   5  
Change in collateral —   ( 102 ) —   ( 102 )

Purchases —   20   —   20  
Sales —   ( 5 ) —   ( 5 )

Transfers into Level 3 —   14   (c)
—   14  
Transfers out of Level 3 —   159   (c)
—   159  
Amortization of acquired contracts
—   ( 191 ) —   ( 191 )
Balance as of March 31, 2026
$ 534   $ 2,173   $ 1   $ 2,708  
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2026
$ 2   $ 568   $ —   $ 570  

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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

Three Months Ended March 31, 2025
NDT Fund Investments Derivatives Rabbi Trust Investments Total
Balance as of January 1, 2025
$ 502   $ ( 1 ) $ 1   $ 502  
Total realized / unrealized gains (losses)
Included in net income (loss) 1   ( 131 ) (b)
—   ( 130 )

Change in collateral —   67   —   67  

Purchases —   15   —   15  
Sales —   ( 3 ) —   ( 3 )
Settlements ( 2 ) —   —   ( 2 )
Transfers into Level 3 1   ( 1 ) (c)
—   —  
Transfers out of Level 3 —   36   (c)
—   36  
Balance as of March 31, 2025
$ 502   $ ( 18 ) $ 1   $ 485  
The amount of total gains (losses) included in income attributed to the change in unrealized gains (losses) related to assets and liabilities as of March 31, 2025
$ 1   $ ( 96 ) $ —   $ ( 95 )

__________
(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 an addition of $ 89 million for realized losses and reduction of ($ 35 ) million for realized gains due to the settlement of derivative contracts for the three months ended March 31, 2026 and 2025, respectively.
(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.
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 months ended March 31, 2026 and 2025:

Three Months Ended March 31,
Operating Revenues Purchased Power and Fuel Other, net

2026 2025 2026 2025 2026 2025
Total gains (losses) included in net income $ 582   $ 38   $ 75   $ ( 169 ) $ 2   $ 1  
Total unrealized gains (losses) 528   ( 8 ) 40   ( 88 ) 2   1  

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Table of Contents
Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 14 — Fair Value of Financial Assets and Liabilities

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

Type of trade Fair Value as of March 31, 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)
$ 1,694   $ ( 232 ) Discounted Cash Flow Forward power price (Non-congestion) $ 2.43 - $ 181
$ 49 $ 4.77 - $ 154
$ 54
Forward power price (Congestion) $ 1.61 - $ 180
$ 52 $ 3.14 - $ 154
$ 50
Forward gas price ($ 2.93 ) - $ 21
$ 3.20 ($ 0.46 ) - $ 15
$ 3.52
Option Model Volatility percentage 10 % - 110 %
57 % 14 % - 197 %
59 %