10-Q – 2026-05-11 – ceg-20260331.htm

__________
(a) The valuation techniques, unobservable inputs, ranges, and arithmetic averages are the same for the asset and liability positions.
(b) The fair values do not include cash collateral posted (received) on Level 3 positions of $ 479 million and $ 372 million as of March 31, 2026 and December 31, 2025, respectively.
The inputs listed above, which are as of the balance sheet date, would have a direct impact on the fair values of the above instruments if they were adjusted. The significant unobservable inputs used in the fair value measurement of our commodity derivatives are forward commodity prices and for options is price volatility. Increases (decreases) in the forward commodity price in isolation would result in significantly higher (lower) fair values for long positions (contracts that give us the obligation or option to purchase a commodity), with offsetting impacts to short positions (contracts that give us the obligation or right to sell a commodity). Increases (decreases) in volatility would increase (decrease) the value for the holder of the option (writer of the option). Generally, a change in the estimate of forward commodity prices is unrelated to a change in the estimate of volatility of prices. An increase to the heat rate or renewable factors would increase the fair value accordingly. Generally, interrelationships exist between market prices of natural gas and power. As such, an increase in natural gas pricing would potentially have a similar impact on forward power markets.

15. Commitments and Contingencies
Commitments
Commercial Commitments. Commercial commitments as of March 31, 2026, representing commitments potentially triggered by future events, were as follows:

Expiration within
2026 2027 2028 2029 2030 2031 and thereafter Total
Letters of credit $ 3,402   $ 1,036   $ 120   $ —   $ 1   $ —   $ 4,559  
Surety bonds (a)
581   261   78   —   —   545   1,465  
Guarantee under the Calpine AR Facility (b)
550   —   —   —   —   —   550  
Total commercial commitments $ 4,533   $ 1,297   $ 198   $ —   $ 1   $ 545   $ 6,574  

__________
(a) Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
(b) We have guaranteed the performance of Calpine Energy Solutions, LLC to Calpine Receivables, LLC under the Calpine AR Facility. The commitment represents the gross amount of sold receivables that are currently outstanding, limited to $ 550 million per the guarantee agreement. Refer to Note 7 — Accounts Receivable for additional information.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Commitments and Contingencies

First Priority Liens for Commodity Procurement and Risk Management Activities
Following the acquisition of Calpine in January 2026, the Company has assumed additional first-priority liens on Calpine assets, which are currently subject to first priority liens under various debt agreements, as collateral under certain of our power and natural gas agreements and certain of the interest rate swaps in order to reduce the cash collateral and letters of credit that would otherwise be provided to the counterparties under such agreements. The counterparties under such agreements share the benefits of the collateral subject to such first priority liens pro rata with the lenders under various debt agreements. As of March 31, 2026, the exposure was $ 220 million under these first priority liens for power and natural gas agreements and no exposure for the interest rate swaps.
Environmental Remediation Matters
General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies, or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.
As of March 31, 2026 and December 31, 2025, we had accrued undiscounted amounts for environmental liabilities of $ 9 million in Accounts payable and accrued expenses and $ 169 million in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on environmental remediation matters. As of March 31, 2026, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2025 Form 10-K.
Litigation
We are involved in various litigation matters that are being defended and handled in the ordinary course of business. The assessment of whether a loss is probable or reasonably possible, and whether the loss or a range of loss is estimable, often involves a series of complex judgments about future events. We maintain accruals for such losses that are probable of being incurred and subject to reasonable estimation. Management is sometimes unable to estimate an amount or range of reasonably possible loss, particularly where (1) the damages sought are indeterminate, (2) the proceedings are in the early stages, or (3) the matters involve novel or unsettled legal theories. In such cases, there is considerable uncertainty regarding the timing or ultimate resolution of such matters, including a possible eventual loss.
As of March 31, 2026 and December 31, 2025, we had accrued $ 28 million and $ 15 million, respectively, in Accounts payable and accrued expenses and $ 108 million and $ 113 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets for liabilities related to litigation matters, including asbestos personal injury claims. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on asbestos personal injury claims
Impacts of the February 2021 Extreme Cold Weather Event and Texas-based Generating Assets Outages. Calpine was acquired on January 7, 2026, and is party to the same ongoing litigation proceedings as Constellation. See Note 18 — Commitments and Contingencies of our 2025 Form 10-K for additional information on this matter, which is likewise representative of the ongoing proceedings as it pertains to Calpine.
In March 2026, the Supreme Court of Texas denied plaintiffs’ petitions for a writ of mandamus in all five bellwether appeals. Plaintiffs have stated that they intend to seek rehearing before the Court. If the rehearing petitions in the bellwether cases are denied, the parties would return to the Multi-District-Litigation court to dispose of all of the remaining Winter Storm Uri tort claims pending against the power generator defendants.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Shareholders' Equity

16. Shareholders' Equity
Share Repurchase Program (CEG Parent)
During 2026, our Board of Directors approved a $ 4.4 billion increase relative to the remaining authorized amount to repurchase our outstanding common stock. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $ 4.7 billion of remaining authority for repurchases, which includes the impact of the open market repurchases, as discussed below. See Note 19 — Shareholders' Equity of our 2025 Form 10-K for additional information on our share repurchase program.
During the three months ended March 31, 2026 and 2025, no open market repurchases occurred. During April and May 2026, prior to this filing, we repurchased from the open market approximately 1.2 million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $ 338 million.
Capped Call Options. During the first quarter of 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments of $ 150  million in the first quarter of 2025 in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration. Neither option was exercised during the second and third quarter of 2025, therefore we did not receive any shares at expiration. As a result, we received our initial up-front cash payments of $ 150  million plus a nominal cash premium during the second and third quarters of 2025. The cash received restored the remaining authority available for repurchases.
Changes in Accumulated Other Comprehensive Income (Loss) (All Registrants)
The following tables present changes in AOCI, net of tax, by component:

Three Months Ended March 31, 2026 Gains (losses) on Cash Flow Hedges Pension and OPEB Items (a)
Foreign Currency Items Total
Beginning balance $ 1   $ ( 2,413 ) $ ( 13 ) $ ( 2,425 )
OCI before reclassifications —   ( 25 ) ( 3 ) ( 28 )
Amounts reclassified from AOCI 1   27   —   28  
Net current-period OCI 1   2   ( 3 ) —  
Ending balance $ 2   $ ( 2,411 ) $ ( 16 ) $ ( 2,425 )

Three Months Ended March 31, 2025
Beginning balance $ ( 6 ) $ ( 2,262 ) $ ( 34 ) $ ( 2,302 )
OCI before reclassifications —   ( 34 ) 8   ( 26 )
Amounts reclassified from AOCI 2   17   —   19  
Net current-period OCI 2   ( 17 ) 8   ( 7 )
Ending balance $ ( 4 ) $ ( 2,279 ) $ ( 26 ) $ ( 2,309 )
__________
(a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 11 — Retirement Benefits for additional information. See our Consolidated Statements of Operations and Comprehensive Income for individual components of AOCI.
The following table presents income tax (expense) benefit allocated to each component of our other comprehensive income (loss):

Three Months Ended March 31,
2026 2025
Pension and OPEB plans:

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

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

Note 17 — Variable Interest Entities

17. Variable Interest Entities
At March 31, 2026 and December 31, 2025, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of March 31, 2026 and December 31, 2025. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.

March 31, 2026 December 31, 2025
Cash and cash equivalents $ 69   $ 52  
Restricted cash and cash equivalents 32   48  
Accounts receivable, net
2,561   2,477  
Inventories, net 13   13  
Other current assets 34   29  
Total current assets 2,709   2,619  
Property, plant, and equipment, net 1,912   1,942  
Other noncurrent assets 117   123  
Total assets (a)
$ 4,738   $ 4,684  

Short-term borrowings $ 1,500   $ —  
Long-term debt due within one year 67   66  
Accounts payable and accrued expenses
26   34  
Other current liabilities
2   3  
Total current liabilities 1,595   103  
Long-term debt 551   578  
Asset retirement obligations 234   231  
Other deferred credits and other liabilities 1   2  
Total deferred credits and other liabilities
235   233  
Total liabilities
$ 2,381   $ 914  

__________
(a) Our balances include unrestricted assets for current UEC assets of $ 17  million and $ 17  million, disclosed within other current assets in the table above, and noncurrent UEC assets of $ 112  million and $ 116  million, disclosed within other noncurrent assets in the table above, as of March 31, 2026 and December 31, 2025, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

As of March 31, 2026 and December 31, 2025, our consolidated VIEs included the following:

Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51 % equity ownership in CRP. See additional discussion below.
Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100 % owned by us. Antelope Valley sells all of its output to PG&E through a PPA.
The PPA contract absorbs variability through a performance guarantee. We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100 % owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity and gas.

NER’s assets will be available first and foremost to satisfy the claims of the creditors of NER. Refer to Note 7 —Accounts Receivable for additional information on the sale of receivables.
Equity capitalization is insufficient to support its operations. We conduct all activities.

Unconsolidated VIEs
Our variable interests in unconsolidated VIEs generally include an equity method investment and energy purchase and sale contracts. For the equity investment, the carrying amount of the investment is reflected in the Consolidated Balance Sheets in Other deferred debits and other assets, see Note 18 — Supplemental Financial Information for additional information . For the energy purchase and sale contracts (commercial agreements), the carrying amount of assets and liabilities in the Consolidated Balance Sheets that relate to our involvement with the VIEs are predominantly related to working capital accounts and generally represent the amounts owed by, or owed to, us for the deliveries associated with the current billing cycles under the commercial agreements.
As of March 31, 2026 and December 31, 2025, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial and securitization agreements.
The following table presents summary information about our significant unconsolidated VIE entities:

March 31, 2026 December 31, 2025
Commercial Agreement VIEs Equity Investment VIEs
Total
Commercial Agreement VIEs Equity Investment VIEs
Total

Total assets (a)
$ 710   $ 575   $ 1,285   $ 711   $ —   $ 711  
Total liabilities (a)
97   550   647   95   —   95  

Other ownership interests in VIE (a)
613   25   638   616   —   616  

__________
(a) These items represent amounts on the unconsolidated VIE balance sheets, not in the Consolidated Balance Sheets. These items are included to provide information regarding the relative size of the unconsolidated VIEs.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 17 — Variable Interest Entities

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

Unconsolidated VIE or VIE groups:
Reason entity is a VIE: Reason we are not the primary beneficiary:
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities.
Calpine Receivables, LLC - A bankruptcy remote entity created for the special purpose of purchasing trade accounts receivable from Calpine Energy Solutions, LLC under the Accounts Receivable Sales Program
Equity capitalization is insufficient to support its operations.
We do not have the power to direct activities nor affect its financial performance

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

Three Months Ended March 31,
Operating revenues 2026 2025

Variable lease income $ 97   $ 52  

Three Months Ended March 31,
Taxes other than income taxes 2026 2025
Property $ 102   $ 72  
Payroll 58   44  
Gross receipts (a)
64   38  
Other
5   6  
Total $ 229   $ 160  

__________
(a) Represent gross receipts taxes related to our retail operations. The offsetting collection of gross receipts taxes from customers is recorded in Operating revenues in the Consolidated Statements of Operations and Comprehensive Income.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information

Three Months Ended March 31,
Other, net 2026 2025
Decommissioning-related activities:
Net realized income on NDT funds (a)

Regulatory Agreement Units $ 271   $ 243  
Non-Regulatory Agreement Units 155   94  
Net unrealized gains (losses) on NDT funds

Regulatory Agreement Units ( 206 ) ( 117 )
Non-Regulatory Agreement Units ( 109 ) ( 23 )
Regulatory offset to NDT fund-related activities (b)
( 52 ) ( 103 )
Total Decommissioning-related activities 59   94  

Net unrealized gains (losses) from equity investments (c)
( 27 ) ( 268 )

Other
14   20  
Total $ 46   $ ( 154 )

__________
(a) Realized income includes interest, dividends and realized gains and losses on sales of NDT fund investments.
(b) Includes the elimination of decommissioning-related activities and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units.
(c) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.
Supplemental Cash Flow Information
The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows.

Three Months Ended March 31,
Depreciation, amortization, and accretion Income statement location
2026 2025
PP&E Depreciation and amortization $ 436   $ 243  
Nuclear fuel Purchased power and fuel 244   232  
Amortization of acquired derivative contracts (a)
Operating revenues or purchased power and fuel 228   —  
ARO accretion Operating and maintenance 174   158  
Amortization of UECs Operating revenues or purchased power and fuel 128   2  
Amortization of intangible assets, net (b)
Depreciation and amortization 7   5  
Other amortization
Operating revenues, purchased power and fuel, or interest expense, net ( 15 ) —  
Total $ 1,202   $ 640  
__________
(a) Related to the amortization of acquired derivative contracts from the acquisition of Calpine.
(b) Primarily related to the amortization of customer relationships and trade names.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information

CEG Parent Constellation
Three Months Ended March 31, Three Months Ended March 31,
Other non-cash operating activities
2026 2025 2026 2025
Other decommissioning-related activity (a)
$ ( 349 ) $ ( 74 ) $ ( 349 ) $ ( 74 )
Pension and non-pension postretirement benefit costs
50   38   50   38  

Other
100   83   70   60  
Total $ ( 199 ) $ 47   $ ( 229 ) $ 24  

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

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

March 31, 2026 CEG Parent Constellation
Cash and cash equivalents $ 800   $ 785  
Restricted cash and cash equivalents 371   351  

Total cash, restricted cash, and cash equivalents $ 1,171   $ 1,136  

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

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

March 31, 2025
Cash and cash equivalents $ 1,846   $ 1,836  
Restricted cash and cash equivalents 96   86  

Total cash, restricted cash, and cash equivalents $ 1,942   $ 1,922  

For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2025 Form 10-K. Calpine's restricted cash balances, included in our balances as of March 31, 2026, align with our current policy or represent other agreements that require us to establish and maintain segregated cash accounts, the use of which is restricted, making these cash funds unavailable for general use.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 18 — Supplemental Financial Information

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

Inventories, net March 31, 2026 December 31, 2025
Materials and supplies $ 2,200   $ 1,485  
Natural gas, oil, and emission allowances 382   251  
Total $ 2,582   $ 1,736  

CEG Parent Constellation
Accounts payable and accrued expenses March 31, 2026 December 31, 2025 March 31, 2026 December 31, 2025
Accounts payable
$ 2,708   $ 2,813   $ 2,697   $ 2,801  
Compensation-related accruals (a)
557   920   445   672  
Taxes accrued (b)
484   246   483   245  
Other accrued expenses
700   315   699   315  
Total
$ 4,449   $ 4,294   $ 4,324   $ 4,033  
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
(b) Includes $ 375 million as of December 31, 2025, related to nuclear PTC that was used to offset the current tax liability. No credits were utilized in the first quarter of 2026. See Note 6 — Government Assistance for additional information on the nuclear PTC.
The following table provides additional information about investments included in Other deferred debits and other assets in the Consolidated Balance Sheets.

Investments March 31, 2026 December 31, 2025
Equity method investments
$ 26   $ 3  
Other investments:
Employee benefit trusts and investments (a)
110   112  
Equity investments with readily determinable fair values (b)
64   82
Equity investments without readily determinable fair values 113   109
Other available for sale debt security investments 1   1
Total
$ 314   $ 307  

__________
(a) Debt and equity security investments are recorded at fair market value.
(b) Does not include the equity investments with readily determinable fair values that are recorded in Other current assets in the Consolidated Balance Sheets. See Note 14 — Fair Value of Financial Assets and Liabilities for additional information on investments in equities.

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

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

Executive Overview
Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation’s largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation’s clean energy and delivering the around-the-clock reliability needed to power America’s growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future.
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Significant Transactions and Developments
Acquisition of Calpine Corporation
On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.
This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.
In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments and remains subject to customary closing conditions, including receipt of applicable regulatory approvals. Completion of this transaction, together with the planned divestiture of an additional ERCOT facility, is expected to satisfy the remaining regulatory commitments related to the merger.
See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
New Data Center Facility at Freestone Energy Center
In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. Calpine has also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas.
Pastoria Solar Project
In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired combined-cycle generating facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which will be coming online during the spring/summer of 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company.
Pin Oak Creek Energy Center
In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460-megawatt, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas’ continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state’s economic momentum.
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Other Key Business Drivers
PJM Market Reform
In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar—consisting of a price cap of approximately $325/MW‑day and a price floor of approximately $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM’s tariff revisions, allowing the continued application of the price collar for the specified delivery years. The Commission found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms.
FERC Issues Order in PJM Show Cause Proceeding
In December 2025, FERC issued a draft order finding PJM's tariff unjust and unreasonable as it relates to colocated load, citing lack of sufficient clarity and consistency regarding rates, terms, and conditions of service for interconnection customers serving co-located load. The draft order also found that behind-the-meter generation rules in PJM's current tariff are no longer appropriate. PJM's current tariff requires that all co-located load be served through the PJM transmission system and that any planned modifications to generating facilities would require reliability studies and be subject to PJM's approval. FERC is now directing PJM to revise its tariff to: a) detail the terms and conditions for interconnection customers serving co-located load, b) require transmission customers serving co-located load to choose from four specific service options, and c) revise behind-the-meter generation rules, including the development of a transition period and grandfather clause for certain existing contracts. Through the date of this filing, PJM had not filed its final compliance tariff revisions, and the ultimate form and timing of these changes remain subject to further stakeholder processes and FERC review.
Russia and Ukraine Conflict
We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. “Prohibiting Russian Uranium Imports Act” became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.
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Environmental Regulation
California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state’s Cap-and-Trade Program through January 1, 2046, and renaming it the “Cap and Invest" Program.
In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO 2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions. Unless relief from the requirements is provided this could require our natural gas generation facility Zion Energy Center, acquired as part of Calpine, to shut down by January 2030.
See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to.

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

Financial Results of Operations
GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations below.

Three Months Ended March 31, $ Change

2026 2025
GAAP Net Income (Loss) Attributable to Common Shareholders
$ 1,590  $ 118  $ 1,472 

Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.
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The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.
Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.5% for the three months ended March 31, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three months ended March 31, 2026 compared to the same period in 2025.

Three Months Ended March 31,
2026 2025
(In millions, except per share data) Earnings Per Share (a)
Earnings Per Share (a)

GAAP Net Income (Loss) Attributable to Common Shareholders $ 1,590  $ 4.49  $ 118  $ 0.38 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $247 and $169, respectively) (b)
(721) (2.03) 505  1.61 
Decommissioning-Related Activities (net of taxes of $79 and $31, respectively) (c)
(174) (0.49) 19  0.06 
Amortization of Acquired Commodity Contracts (net of taxes of $53 and $—, respectively) (d)
154  0.44  —  — 
Calpine Merger and Integration Costs (net of taxes of $22 and $4, respectively) (e)
119  0.34  13  0.04 
Plant Retirements and Divestitures (net of taxes of $— and $4, respectively)
—  —  11  0.03 
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $7 and $3, respectively)
20  0.06  9  0.03 

Income Tax-Related Adjustments
(13) (0.04) —  — 
Noncontrolling Interests (f)
(3) (0.01) (2) (0.01)
Adjusted (non-GAAP) Operating Earnings $ 972  $ 2.74  $ 673  $ 2.14 
__________
(a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 354 million and 314 million for the three months ended March 31, 2026 and 2025, respectively.
(b) Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.
(c) Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts.
(d) In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition.
(e) Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible.
(f) Represents elimination of the noncontrolling interest portion of certain adjustments included above.
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Results of Operations

Three Months Ended March 31, $ Change

2026 2025
Operating revenues $ 11,122  $ 6,788  $ 4,334 
Operating expenses
Purchased power and fuel 6,352  4,384  1,968 
Operating and maintenance 1,780  1,545  235 
Depreciation and amortization 443  248  195 
Taxes other than income taxes 229  160  69 
Total operating expenses 8,804  6,337  2,467 

Gain (loss) on sales of assets
14  —  14 

Operating income (loss)
2,332  451  1,881 
Other income and (deductions)
Interest expense, net (253) (146) (107)
Other, net 46  (154) 200 
Total other income and (deductions) (207) (300) 93 
Income (loss) before income taxes
2,125  151  1,974 
Income tax (benefit) expense
530  22  508 
Equity in income (losses) of unconsolidated affiliates
8  —  8 
Net income (loss)
1,603  129  1,474 
Net income (loss) attributable to noncontrolling interests
13  11  2 
Net income (loss) attributable to common shareholders
$ 1,590  $ 118  $ 1,472 

Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $1,472 million primarily due to:
• Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information;
• Favorable net unrealized gains on economic hedges;
• Favorable decommissioning-related activities primarily driven by the Q1 2026 nuclear ARO update. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information;
• Lower net unrealized loss on equity investments; and
• Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by higher costs related to a significant weather event in the first quarter of 2026 and lower CMC program revenue.
The favorable items were partially offset by:
• Unfavorable impacts from nuclear outages.
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Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations are reported under Other and not allocated to a segment.
For the three months ended March 31, 2026 compared to 2025, Operating revenues were as follows:

Three Months Ended March 31,
2026 2025 $ Change
% Change
Mid-Atlantic $ 1,847  $ 1,665  $ 182  10.9  %
Midwest 1,732  1,404  328  23.4  %
New York 569  562  7  1.2  %
ERCOT 370  398  (28) (7.0) %
Other Power Regions 1,487  1,556  (69) (4.4) %
Calpine 2,395  —  2,395  100.0  %
Total reportable segment revenues 8,400  5,585  2,815  50.4  %
Other 1,407  1,490  (83) (5.6) %
Unrealized gains (losses) (a)
1,315  (287) 1,602 
Total Operating revenues $ 11,122  $ 6,788  $ 4,334  63.8  %

__________
(a) % Change in unrealized gains (losses) is not a meaningful measure.
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Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below:

Three Months Ended March 31,
(GWhs)
2026 2025 Change
% Change
Nuclear Generation (a)

Mid-Atlantic 13,326  13,177  149  1.1  %
Midwest 22,974  23,596  (622) (2.6) %
New York 6,014  6,280  (266) (4.2) %
ERCOT
2,352  2,529  (177) (7.0) %
Total Nuclear Generation 44,666  45,582  (916) (2.0) %

Natural Gas, Oil, and Renewables (a)

Mid-Atlantic 740  632  108  17.1  %
Midwest 344  385  (41) (10.6) %

ERCOT
2,738  3,084  (346) (11.2) %
Other Power Regions 1,742  1,804  (62) (3.4) %
Calpine
26,497  —  26,497  100.0  %
Total Natural Gas, Oil, and Renewables 32,061  5,905  26,156  442.9  %

Purchased Power
Mid-Atlantic
4,094  4,794  (700) (14.6) %
Midwest 417  488  (71) (14.5) %

ERCOT 686  659  27  4.1  %
Other Power Regions 9,317  10,994  (1,677) (15.3) %
Calpine
2,089  —  2,089  100.0  %
Total Purchased Power 16,603  16,935  (332) (2.0) %

Total Supply/Sales by Segment
Mid-Atlantic 18,160  18,603  (443) (2.4) %
Midwest 23,735  24,469  (734) (3.0) %
New York 6,014  6,280  (266) (4.2) %
ERCOT
5,776  6,272  (496) (7.9) %
Other Power Regions 11,059  12,798  (1,739) (13.6) %
Calpine
28,586  —  28,586  100.0  %
Total Supply/Sales by Segment 93,330  68,422  24,908  36.4  %
__________
(a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.
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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

Three Months Ended March 31,
2026 2025
Nuclear fleet capacity factor 92.3  % 94.1  %
Refueling outage days 99  88 
Non-refueling outage days —  — 

Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three months ended March 31, 2026 is 4.5%. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.
Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized.

Three Months Ended March 31,
ISO/RTO
2026 2025 $ Change
% Change
PJM - PJM West
$ 97.16  $ 53.69  $ 43.47  81.0  %
PJM - ComEd
50.71  35.31  15.40  43.6  %
NYISO - Central
112.23  75.31  36.92  49.0  %
ERCOT - North
40.65  31.39  9.26  29.5  %
ERCOT - Houston 38.55  31.73  6.82  21.5  %
ISO-NE - Southeast Massachusetts
118.82  104.75  14.07  13.4  %
CAISO - NP15
29.01  40.96  (11.95) (29.2) %

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Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three months ended March 31, 2026 and 2025.
We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below.

Three Months Ended March 31,
ISO/RTO
2026 2025 $ Change
% Change
PJM - Eastern Mid-Atlantic Area Council
$ 269.92  $ 53.60  $ 216.32  403.6  %
PJM - ComEd
269.92  28.92  241.00  833.3  %
NYISO - Rest of State
112.33  86.33  26.00  30.1  %
ISO-NE - Rest of Pool (a)
84.37  82.57  1.80  2.2  %

__________
(a) We did not have significant activity at this zone for the three months ended March 31, 2025.
ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three months ended March 31, 2026 and 2025 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

Three Months Ended March 31,
State (Segment) (a)
2026 2025 $ Change
% Change
New Jersey (Mid-Atlantic) (b)
$ —  $ 10.00  $ (10.00) (100.0) %
Illinois (Midwest )
1.17  9.38  (8.21) (87.5) %
New York (New York) 14.76  18.27  (3.51) (19.2) %

__________
(a) See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs.
(b) The New Jersey ZEC program concluded in May 2025.
Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025 and $33.50 per MWh for the period June 2025 through May 2026. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($26.18) and ($2.04) for the three months ended March 31, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.
Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025. We expect the inflation factor for 2026 to be published in the second or third quarter of 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.
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Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.
The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three months ended March 31, 2026 compared to 2025:

Three Months Ended March 31,
2026 2025 $ Change
% Change
Nuclear PTC revenue (a)
$ 10  $ —  $ 10  100.0  %
State-sponsored programs net revenue (b)
(285) 110  (395) (359.1) %

__________
(a) Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.
For the three months ended March 31, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:

Three Months Ended March 31

$ Change
% Change Description

Mid-Atlantic $ 182  10.9  % • favorable retail load revenue of $315 primarily due to higher contracted energy prices
• favorable wholesale load revenue of $100 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by
• unfavorable realized economic hedges of $215 due to settled prices relative to hedged prices

Midwest 328  23.4  % • favorable net generation and wholesale load revenue of $370 primarily due to higher energy prices and higher load volumes, partially offset by lower generation volumes
• favorable retail load revenue of $210 primarily due to higher contracted energy prices
• favorable net capacity revenue of $90 primarily due to higher prices; partially offset by
• unfavorable CMC program revenue of $350 primarily due to higher energy and capacity prices

New York 7  1.2  % • favorable net generation revenue of $100 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices; partially offset by
• unfavorable realized economic hedges of $95 due to settled prices relative to hedged prices

ERCOT (28) (7.0) % • no individually significant drivers

Other Power Regions (69) (4.4) % • unfavorable wholesale load revenue of $125 primarily due to lower load volumes in New England

Calpine 2,395  100.0  % • represents the operating revenues associated with our Calpine segment since the date of acquisition

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Three Months Ended March 31

$ Change
% Change Description

Other (83) (5.6) % • current year includes unfavorable amortization associated with certain commodity contracts related to the Calpine acquisition of $215; partially offset by
• favorable retail gas revenue of $165 primarily due to higher gas prices

Unrealized gains or losses (a)(b)
1,602  • gains on economic hedging activities of $1,315 in 2026 compared to losses of $287 in 2025, inclusive of Calpine

Total $ 4,334  63.8  %

__________
(a) % Change in unrealized gains or losses is not a meaningful measure.
(b) See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.
Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices.
With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment.
For the three months ended March 31, 2026 compared to 2025, Purchased power and fuel expense were as follows:

Three Months Ended March 31,
2026 2025 $ Change
% Change
Mid-Atlantic $ 1,035  $ 856  $ 179  20.9  %
Midwest 878  554  324  58.5  %
New York 160  161  (1) (0.6) %
ERCOT 161  184  (23) (12.5) %
Other Power Regions 1,220  1,362  (142) (10.4) %
Calpine
1,269  —  1,269  100.0  %
Total segment purchased power and fuel 4,723  3,117  1,606  51.5  %
Other 1,375  1,233  142  11.5  %
Unrealized losses (gains) (a)
254  34  220 
Total purchased power and fuel $ 6,352  $ 4,384  $ 1,968  44.9  %

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

Three Months Ended March 31,
Location 2026 2025 $ Change % Change
Henry Hub $ 4.90  $ 4.28  $ 0.62  14.5  %
Transco Zone 6 (a)
9.48  6.06  3.42  56.4  %
Houston Ship Channel (b)
3.26  3.46  (0.20) (5.8) %
PG&E Citygate (c)
2.07  3.71  (1.64) (44.2) %
Algonquin Citygate (d)
14.08  11.83  2.25  19.0  %

__________
(a) Transcontinental Gas pipeline located in Mid-Atlantic region.
(b) Houston-area pipeline and industrial network located in ERCOT region.
(c) Pacific Gas & Electric Company virtual trading point located in West region.
(d) Algonquin Gas Transmission physical delivery point located in New England region.
For the three months ended March 31, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:

Three Months Ended March 31

$ Change
% Change Description

Mid-Atlantic $ 179  20.9  % • unfavorable $350 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to a significant weather event in January 2026; partially offset by
• favorable realized economic hedges of $190 due to settled prices relative to hedged prices

Midwest 324  58.5  % • unfavorable $310 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026

New York (1) (0.6) % • no individually significant drivers

ERCOT (23) (12.5) % • no individually significant drivers

Other Power Regions (142) (10.4) % • favorable $80 associated with purchased power to supply load primarily due to lower energy prices in the West

Calpine 1,269  100.0  % • represents the purchased power and fuel associated with our Calpine segment since the date of acquisition

Other 142  11.5  % • unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $175 primarily due to higher gas prices

Unrealized gains or losses (a)(b)
220  • losses on economic hedging activities of $254 in 2026 compared to losses of $34 in 2025, inclusive of Calpine

Total $ 1,968  44.9  %

__________
(a) % Change in unrealized gains or losses is not a meaningful measure.
(b) See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.
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The changes in Operating and maintenance expense consisted of the following:

Three Months Ended 
 March 31
2026 vs. 2025
Increase (Decrease)

Labor, contracting, and materials (a)
$ 175 
Calpine merger and integration costs
126 
Nuclear refueling outage costs (b)
51 
Decommissioning-related activities
(272)
Other 155 
Total increase $ 235 

__________
(a) Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026.
(b) Includes the co-owned Salem and STP generating units
Depreciation and amortization expense increased by $195 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Interest expense, net increased by $107 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Other, net was favorable for the three months ended March 31, 2026 compared to the same period in 2025, due to activity described in the table below:

Income (Deductions)

Three Months Ended March 31,
2026 2025
Decommissioning-related activities (a)
$ 59  $ 94 
Net unrealized gains (losses) from equity investments (b)
(27) (268)
Other
14  20 
Other, net $ 46  $ (154)

__________
(a) Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 — Asset Retirement Obligations and Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.
Effective income tax rates were 24.9% and 14.6% for the three months ended March 31, 2026 and 2025, respectively. The change in effective tax rate for 2026 is primarily due to the decrease in share-based payment awards as well as lower qualified NDT fund income which is taxed at a higher rate. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
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Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $15.1 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flow Activities
The following table summarizes our cash flow activities for the three months ended March 31, 2026 and 2025, respectively:

Three Months Ended March 31,
2026 2025 $ Change
Cash, restricted cash, and cash equivalents at beginning of period
$ 3,748  $ 3,129  $ 619 
Net cash provided by (used in):
Operating activities 425  107  318 
Investing activities (3,732) (886) (2,846)
Financing activities 730  (408) 1,138 
Net increase (decrease) in cash, restricted cash, and cash equivalents
(2,577) (1,187) (1,390)

Cash, restricted cash, and cash equivalents at end of period
$ 1,171  $ 1,942  $ (771)

Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities was $425 million and $107 million for the three months ended March 31, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Additionally, the increase in cash provided by operating activities was due to cash inflows associated with a decrease in collateral posted. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Net Cash Provided By (Used In) Investing Activities
Cash used in investing activities was ($3,732) million and ($886) million for the three months ended March 31, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
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Net Cash Provided By (Used In) Financing Activities
Cash provided by financing activities was $730 million for the three months ended March 31, 2026, compared to cash used in financing activities of ($408) million for the three months ended March 31, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the three months ended March 31, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Quarterly dividends declared by our Board of Directors during 2026 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share
First Quarter of 2026
February 20, 2026 March 9, 2026 March 20, 2026 $ 0.4265 
Second Quarter of 2026
April 28, 2026 May 15, 2026 June 5, 2026 0.4265 

Credit Matters and Cash Requirements
We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of March 31, 2026, we have access to facilities with aggregate bank commitments of $15.1 billion. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.
Security Ratings
Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of March 31, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of March 31, 2026, we had $6.7 billion of available capacity under our credit facilities and $0.8 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we would be required to access additional liquidity through the capital markets. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements. Our credit ratings were affirmed by Moody’s and S&P in January 2026 following the completion of the acquisition of Calpine.
If we had lost our investment grade credit ratings as of March 31, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.
See Note 12 — Derivative Financial Instruments and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
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Pension and Other Postretirement Benefits
We consider various factors when making qualified pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2026 for $161 million. Unlike the qualified pension plans, our non-qualified plans are not subject to statutory minimum contribution requirements.
OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2026 are approximately $25 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $64 million. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on pension and other postretirement benefits.
Cash Requirements for Other Financial Commitments
In connection with the acquisition of Calpine in January 2026, we assumed approximately $3 billion of projected cash payments under existing financial commitments with fixed or minimum payments required. These commitments exclude future cash payments for debt service on assumed debt as much of the debt was refinanced or paid off following the acquisition. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other than as described above and elsewhere in this Quarterly Report on Form 10-Q, there have been no material changes to the cash requirements from contractual and other obligations disclosed in our 2025 Annual Report on Form 10-K. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on our cash requirements for financial commitments.
Accounts Receivable Facilities
We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain accounts receivables. As a result of our acquisition of Calpine in January 2026, we assumed Calpine's accounts receivable sales program which allows for the sale of certain Calpine receivables at a nominal discount. See Note 7 — Accounts Receivable and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Project Financing
Project financing is based upon a financial structure in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. As a result of our acquisition of Calpine in January 2026, we assumed various project financing arrangements. See Note 16 — Debt and Credit Agreements of our 2025 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt.
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Credit Facilities
We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. We assumed various credit facilities as part of the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.
As of March 31, 2026, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of March 31, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.

Properties
There have been no changes in the properties that were owned as of December 31, 2025 and disclosed within ITEM 2. PROPERTIES of our 2025 Form 10-K. The following table presents our interests in net electric generating capacity by station as of March 31, 2026, for those acquired from Calpine.

Station
Location No. of Units Percent Owned (a)
Primary Fuel Type Primary Dispatch Type (b)
Net Generation Capacity (MWs) (c)

Calpine
Deer Park Deer Park, TX 6 Gas Intermediate 1,217 
Bethlehem (d)
Bethlehem, PA
8 Gas Intermediate 1,130 
Hay Road (d)
Wilmington, DE 8 Gas Intermediate 1,130 
Guadalupe New Braunfels, TX 6 Gas Intermediate 1,040 
Greenfield Ontario, Canada 4 Gas Intermediate 1,088 
Baytown Baytown, TX 4 Gas Intermediate 896 
Delta Pittsburg, CA 4 Gas Intermediate 882 
Channel Houston, TX 4 Gas Intermediate 845 
York 2 (d)
Delta, PA 3 Gas Intermediate 828 
Morgan Decatur, AL 4 Gas Intermediate 807 
Thad Hill Clifton, TX 5 Gas Intermediate 792 
Pasadena Pasadena, TX 5 Gas Intermediate 781 
Freestone Fairfield, TX 6 75  Gas Intermediate 776 
Pastoria Arvin, CA 5 Gas Intermediate 759 
Magic Valley Edinburg, TX 3 Gas Intermediate 712 

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Station
Location No. of Units Percent Owned (a)
Primary Fuel Type Primary Dispatch Type (b)
Net Generation Capacity (MWs) (c)

Granite Ridge Londonderry , NH 3 Gas Intermediate 695 
Hermiston Hermiston, OR 3 Gas Intermediate 635 
Metcalf Coyote, CA 3 Gas Intermediate 625 
Russell City Hayward, CA 3 Gas Intermediate 619 
Jack A. Fusco (d)
Richmond, TX 3 Gas Intermediate 609 
Otay Mesa San Diego, CA 3 Gas Intermediate 608 
Sutter Yuba City, CA 3 Gas Intermediate 578 
Los Medanos Pittsburg, CA 3 Gas Intermediate 572 
York 1 (d)
Delta, PA 4 Gas Intermediate 565 
South Point Mohave Valley, AZ 3 Gas Intermediate 555 
Westbrook Westbrook, ME 3 Gas Intermediate 552 
Quail Run Odessa, TX 6 Gas Intermediate 550 
Corpus Christi Corpus Christi, TX 3 Gas Intermediate 520 
Texas City Texas City, TX 4 Gas Intermediate 453 
Hidalgo Edinburg, TX 3 78.5  Gas Intermediate 395 
Los Esteros San Jose, CA 5 Gas Intermediate 309 
Pine Bluff Pine Bluff, AR 2 Gas Intermediate 215 
Gilroy Cogeneration Gilroy, CA 2 Gas Intermediate 130 
King City Cogeneration King City, CA 2 Gas Intermediate 120 
Bethpage 3 Levittown, NY 2 Gas Intermediate 80 
Bethpage Bethpage, NY 5 Gas Intermediate 56 
Stony Brook Stony Brook, NY 1 Gas Intermediate 47 
Agnews San Jose, CA 2 Gas Intermediate 28 
Zion Zion, IL 3 Gas Peaking 503 
Cumberland Milleville, NJ 2 Gas Peaking 191 
Gilroy Gilroy, CA 3 Gas Peaking 141 
Sherman Avenue Vineland, NJ 1 Gas Peaking 92 
Wolfskill Fairfield, CA 1 Gas Peaking 48 
Bethpage Peaker Bethpage, NY 1 Gas Peaking 48 
Yuba City Yuba City, CA 1 Gas Peaking 47 
Feather River Yuba City, CA 1 Gas Peaking 47 
Creed Suisun City, CA 1 Gas Peaking 47 
Lambie Suisun City, CA 1 Gas Peaking 47 
Goose Haven Suisun City, CA 1 Gas Peaking 47 
Riverview Antioch, CA 1 Gas Peaking 47 
King City Peaking King City, CA 1 Gas Peaking 44 
Delaware City New Castle, DE 1 Gas Peaking 23 
West Wilmington, DE 3 Gas Peaking 20 
Fore River Weymouth, MA 3 Oil/Gas Intermediate 731 
Edge Moor (d)
Wilmington, DE 3 Oil Peaking 725 
Christiana Wilmington, DE 2 Oil Peaking 53 
Tasley Accomac, VA 1 Oil Peaking 33 
Bayview Cape Charles, VA 6 Oil Peaking 12 
Crisfield Crisfield, MD 1 Oil Peaking 10 

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Station
Location No. of Units Percent Owned (a)
Primary Fuel Type Primary Dispatch Type (b)
Net Generation Capacity (MWs) (c)

Nova Project I-V Menifee, CA 5 Battery Storage Peaking 680 
Santa Ana Santa Ana, CA 3 Battery Storage Peaking 80 
West Ford Flat Sonoma County, CA 1 Battery Storage Peaking 25 
Bear Canyon Sonoma County, CA 1 Battery Storage Peaking 13 
McCabe 5 & 6
Sonoma County, CA 2 Geothermal Baseload 85 
Ridge Line 7 & 8
Sonoma County, CA 2 Geothermal Baseload 77 
Eagle Rock Sonoma County, CA 1 Geothermal Baseload 71 
Calistoga Lake County, CA 2 Geothermal Baseload 69 
Big Geysers Lake County, CA 1 Geothermal Baseload 61 
Lake View Sonoma County, CA 1 Geothermal Baseload 56 
Quicksilver Lake County, CA 1 Geothermal Baseload 53 
Sonoma Sonoma County, CA 1 Geothermal Baseload 53 
Cobb Creek Sonoma County, CA 1 Geothermal Baseload 51 
Socrates Sonoma County, CA 1 Geothermal Baseload 50 
Sulphur Springs Sonoma County, CA 1 Geothermal Baseload 47 
Grant Sonoma County, CA 1 Geothermal Baseload 41 
Aidlin Sonoma County, CA 2 Geothermal Baseload 18 
Vineland Solar Vineland, NJ 1 Solar Intermittent 4 
Total Calpine 27,689 

__________
(a) 100%, unless otherwise indicated.
(b) Baseload units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(c) Net generation capacity is stated at proportionate ownership share. All facilities reflect a summer rating.
(d) These stations are pending divestiture as part of the regulatory requirements for the acquisition of Calpine that closed in January 2026 and the associated balances are classified as Assets held for sale in the Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
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The following table presents our estimated net generation capacity by station for projects under construction at March 31, 2026, each of which is wholly owned by us unless otherwise noted.

Station
Location No. of Units Primary Fuel Type Primary Dispatch Type
Estimated Net Generation Capacity (MWs) (a)

Crane Middletown, PA 1 Uranium Baseload 835 
Pin Oak Creek (b)
Freestone, TX 2 Gas Peaking 425 
Pastoria Solar (c)
Kern County, CA 1 Solar Intermittent 105 
Pastoria/Bess Kern County, CA 1 Battery Storage Peaking 80 
Total Projects Under Construction 1,445 
__________
(a) The estimated net generation capacity for units under construction is approximate until commercial operation commences and applicable confirmatory testing is completed.
(b) Commercial operation was in April 2026. Additionally, in May 2026, we sold a 25% ownership interest in the facility to an unrelated party. The sale did not have a material impact on our results of operations or financial condition.
(c) Pastoria Solar was commissioned in April 2026.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Dollars in millions, unless otherwise noted)
We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. The Executive Committee and the Audit and Risk Committee of the Board of Directors have oversight responsibilities for risk management. The following discussion serves as an update to ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2025 Annual Report on Form 10-K incorporated herein by reference.
Commodity Price Risk
Commodity price risk is associated with price movements resulting from changes in supply and demand, fuel costs, market liquidity, weather conditions, governmental, regulatory and environmental policies, and other factors. To the extent the total amount of energy we produce or procure differs from the amount of energy we have contracted to sell, we are exposed to market fluctuations in commodity prices. We seek to mitigate our commodity price risk through the sale and purchase of electricity, natural gas and oil, and other commodities.
Electricity available from our owned or contracted generation supply in excess of our obligations to customers is sold into the wholesale markets. To reduce commodity price risk caused by market fluctuations, we enter into non-derivative contracts as well as derivative contracts, including swaps, futures, forwards, and options, with approved counterparties to hedge anticipated exposures in locations and periods where our load serving activities do not naturally offset existing generation portfolio risk. Portfolio hedging activities are generally concentrated in the prompt three years, when customer demand and market liquidity enable effective price risk mitigation. We expect the settlement of the majority of our economic hedges will occur during 2026 through 2028. We also enter into transactions that further optimize the economic benefits of our overall portfolio.
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 of the Combined Notes to Consolidated Financial Statements for additional information.
The forecasted market price risk exposure is the risk of a change in the value of unhedged positions. The forecasted market price risk exposure as of March 31, 2026 for our portfolio associated with a hypothetical $10/MWh reduction in the annual average around-the-clock energy price and $5/MWh reduction in around-the-clock spark spread results in an impact to earnings that is not material for 2026 and 2027. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
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Fuel Procurement
We procure natural gas through long-term and short-term contracts, and spot-market purchases. We also enter into natural gas transportation and storage contracts that allow us to source reliable and cost-effective natural gas for our fleet and to take advantage of favorable market pricing, regardless of when the gas is used in our operations. Fuel oil inventories are managed so that, in the winter months, sufficient volumes of fuel are available in the event of extreme weather conditions and during the remaining months to take advantage of favorable market pricing.
Nuclear fuel is obtained predominantly through long-term contracts for uranium concentrates, conversion services, enrichment services, (or a combination thereof) and fabrication services, including contracts sourced from Russia. The supply markets for uranium concentrates and certain nuclear fuel services are subject to price fluctuations and availability restrictions. Supply market conditions may make our procurement contracts subject to credit risk related to the potential non-performance of counterparties to deliver the contracted commodity or service at the contracted prices. We engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Approximately 35% of our uranium concentrate requirements for the remainder of 2026 through 2031 are supplied by three suppliers. To-date, we have not experienced any counterparty credit risk associated with these suppliers stemming from the Russia and Ukraine conflict. In the event of non-performance by these or other suppliers, we believe that replacement uranium concentrate can be obtained, although at prices that may be unfavorable when compared to the prices under the current supply agreements. Geopolitical developments, including the Russia and Ukraine conflict and United States, United Kingdom, European Union, and Canadian sanctions against Russia, have the potential to impact delivery from multiple suppliers in the international uranium processing industry. Non-performance by these counterparties could have a material adverse impact on our consolidated financial statements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Other Key Business Drivers for additional information on the Russia and Ukraine conflict.
Commodity Derivative Activity
The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from December 31, 2025 to March 31, 2026. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the commodity derivative contract net assets (liabilities) recorded as of March 31, 2026 and December 31, 2025.

Balance as of December 31, 2025 (a)
$ 504 
Net change in fair value of contracts recorded in results of operations
1,294 
Reclassification to realized at settlement of contracts recorded in results of operations (235)
Changes in allocated collateral (265)
Contracts acquired at acquisition date (b)
1,403 
Amortization of acquired contracts (b)
(228)
Net option premium paid (received) 15 
Option premium amortization 18 
Upfront payments and amortizations (c) 
(14)
Foreign currency translation 1 
Balance as of March 31, 2026 (a)
$ 2,493 

__________
(a) Amounts are shown net of collateral paid to and received from counterparties.
(b) Includes amounts related to contracts acquired as part of the Calpine acquisition in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
(c) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
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Fair Values
The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 14 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding fair value measurements and the fair value hierarchy.

Maturities Within Total Fair Value

2026 2027 2028 2029 2030 2031 and Beyond
Commodity derivative contracts (a) :

Actively quoted prices (Level 1) $ 51  $ 5  $ (9) $ (13) $ 1  $ —  $ 35 
Prices provided by external sources (Level 2) 54  206  23  1  1  —  285 
Prices based on model or other valuation methods (Level 3) 545  474  416  177  109  452  2,173 
Total $ 650  $ 685  $ 430  $ 165  $ 111  $ 452  $ 2,493 

__________
(a) Amounts are shown net of collateral paid to and received from counterparties (and offset against derivative assets and liabilities) of $1,683 million at March 31, 2026.
Credit Risk
We would be exposed to credit-related losses in the event of non-performance by counterparties that execute derivative instruments. The credit exposure of derivative contracts, before collateral, is represented by the fair value of contracts at the reporting date. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
Credit-Risk-Related Contingent Features
As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 12 — Derivative Financial Instruments and Note 15 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information.
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RTOs and ISOs
We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, OIESO, and ERCOT. ERCOT is not subject to regulation by FERC but performs a similar function in Texas to that performed by RTOs and ISOs in markets regulated by FERC. In these areas, power and related products are traded through bilateral agreements between buyers and sellers and in the energy markets that are administered by the RTOs or ISOs, as applicable. In areas where there is no RTO or ISO to administer energy markets, electricity and related products are purchased and sold primarily through bilateral agreements. For activities administered by an RTO or ISO, the RTO or ISO maintains financial assurance policies that are established and enforced by those administrators. The credit policies of the RTOs and ISOs may, under certain circumstances, require that losses arising from the default of one member be shared by the remaining participants. Non-performance or non-payment by a major member of an RTO or ISO could result in a material adverse impact on our consolidated financial statements.
Exchange Traded Transactions
We enter into commodity transactions on NYMEX, ICE, NASDAQ, NGX, and the Nodal exchange (each an Exchange and, collectively, Exchanges). The Exchange clearinghouses act as the counterparty to each trade. Transactions on the Exchanges must adhere to comprehensive collateral and margining requirements. As a result, transactions on Exchanges are significantly collateralized and have limited counterparty credit risk.
Interest Rate Risk
We use a combination of fixed-rate and variable-rate debt to manage interest rate exposure. We may also utilize interest rate swaps to manage our interest rate exposure, including derivatives to lock in rate levels in anticipation of future financings. A hypothetical 50 basis points change in interest rates associated with unhedged variable-rate long-term debt and interest rate swaps would not have resulted in a material impact to our earnings for the three months ended March 31, 2026. See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk
We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.
A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $1,072 million reduction in the fair value of our NDT trust assets as of March 31, 2026. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements and Liquidity and Capital Resources section of ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS for additional information.
Our employee benefit plan trusts also hold investments in equity and debt securities. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.
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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
During the first quarter of 2026, our principal executive officer and principal financial officer, evaluated the effectiveness of our disclosure controls and procedures related to the recording, processing, summarizing, and reporting of information in periodic reports that we file or submit with the SEC. These disclosure controls and procedures have been designed to ensure that (a) information relating to our consolidated subsidiaries, is accumulated and made known to our management, including our principal executive officer and principal financial officer, by other employees as appropriate to allow timely decisions regarding required disclosure, and (b) this information is recorded, processed, summarized, and reported, as applicable, within the time periods specified in the SEC's rules and forms. Due to the inherent limitations of control systems, not all misstatements may be detected. These inherent limitations include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls could be circumvented by the individual acts of some persons or by collusion of two or more people.
Accordingly, as of March 31, 2026, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.
Changes in Internal Control Over Financial Reporting
We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. During the first quarter of 2026, we completed the acquisition of Calpine and are in the process of integrating Calpine into our system of internal control over financial reporting. We anticipate that Calpine will be fully incorporated into our annual assessment of internal control over financial reporting for the fiscal year ending December 31, 2026. There have been no other changes in internal control over financial reporting that occurred during the first quarter of 2026 that have materially affected, or are reasonably likely to materially affect, any of our internal control over financial reporting.
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PART II. OTHER INFORMATION
(Dollars in millions except per share data, unless otherwise noted)

ITEM 1.
LEGAL PROCEEDINGS

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

ITEM 1A.
RISK FACTORS

At March 31, 2026, our risk factors were consistent with the risk factors described in our 2025 Form 10-K in ITEM 1A. RISK FACTORS which was inclusive of the risks related to the Calpine acquisition and its operations.

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

Issuer Purchases of Equity Securities (CEG Parent)
During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining authorized amount to repurchase our outstanding common stock. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $4.7 billion of remaining authority for repurchases. See Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.
No share repurchases occurred under the program during the three months ended March 31, 2026.

ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.

ITEM 5. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the three months ended March 31, 2026, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act).
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ITEM 6. EXHIBITS

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

Exhibit No. Description
2 .1*
Agreement and Plan of Merger, dated as of January 10, 2025, by and among Calpine Corporation, CPN CS Holdco Corp., CPN CKS Corp., Constellation Energy Corporation, Cascade Transco Inc., Cascade Transco – 1, LLC and Volt Energy Holdings GP, LLC, solely in its capacity as the representative of the stockholders of Calpine Corporation (File No. 001-41137, Form 8-K dated January 13, 2025, Exhibit 2.1)

4 .1
Indenture, dated December 27, 2019, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.125% Senior Note due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.1)

4.2
Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 4.625% Senior Note due 2029) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.2)

4 .3
Indenture, dated August 10, 2020, between Calpine Corporation and Wilmington Trust, National Association, as trustee (including Form of 5.000% Senior Note due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.3)

4.4
Indenture, dated December 20, 2019, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 4.500% Senior Secured Notes due 2028) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.4)

4 .5
First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.5)

4 .6
Indenture, dated December 16, 2020, among Calpine Corporation, the guarantors party thereto from time to time and Wilmington Trust, National Association, as trustee (including Form of 3.750% Senior Secured Notes due 2031) (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.6)

4 .7
First Supplemental Indenture, dated August 20, 2025, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 7, 2026, Exhibit 4.7)

4 .8
Form of Constellation Energy Generation, LLC Floating Rate Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.1)

4.9
Form of Constellation Energy Generation, LLC 3.900% Senior Notes due January 8, 2028 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.2)

4.10
Form of Constellation Energy Generation, LLC 4.400% Senior Notes due January 15, 2031 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.3)

4 .11
Form of Constellation Energy Generation, LLC 5.875% Senior Notes due January 15, 2066 (File No. 333-85496, Form 8-K dated January 8, 2026, Exhibit 4.4 )

4.12
First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.1)

4.13
First Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.2)

4.14
Second Supplemental Indenture, dated as of January 15, 2026, among Calpine Corporation, the guarantors party thereto and Wilmington Trust, National Association, as trustee (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.3)

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4.15
Form of New 2029 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.4)

4.16
Form of New February 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.5)

4.17
Form of New March 2031 Senior Note (File No. 001-41137, Form 8-K dated January 15, 2026, Exhibit 4.6)

10.1**
Registration Rights Agreement, dated January 7, 2026, by and among Constellation Energy Corporation and the parties thereto from time to time (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.1)

10.2*
Credit Agreement, dated December 15, 2017, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto from time to time, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.2)

10.3*
Amendment No. 3 to Credit Agreement, dated August 2, 2023, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Credit Suisse AG, Cayman Islands Branch, as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.3)

10.4*
Amendment No. 4 to Credit Agreement, dated June 6, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.4)

10.5*
2024 Incremental Term Loan Commitment Supplement, dated September 16, 2024, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.5)

10.6*
Amendment No. 5 to Credit Agreement, dated November 18, 2025, among Calpine Construction Finance Company, L.P., as borrower, the lenders party thereto, and Citibank, N.A., as administrative agent and collateral agent (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.6)

10.7*
Credit Agreement, dated June 9, 2020, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.7)

10.8*
Omnibus Amendment Agreement, dated November 9, 2021, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.8)

10.9*
Second Omnibus Amendment Agreement, dated May 31, 2022, among Geysers Power Company, LLC, the guarantors party thereto, MUFG Bank, Ltd, as administrative agent, MUFG Union Bank, N.A., as first lien collateral agent, and the lenders and issuing banks parties thereto (File No. 001-41137, Form 8-K, dated January 7, 2026, Exhibit 10.9)

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Certifications Pursuant to Rule 13a-14(a) and 15d-14(a) of the Exchange Act as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026 filed by the following officers for the following registrants:

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

31.2
Filed by Shane P. Smith for Constellation Energy Corporation

31.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

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

Certifications Pursuant to Section 1350 of Chapter 63 of Title 18 United States Code as to the Quarterly Report on Form 10-Q for the quarterly period ended March 31, 2026 filed by the following officers for the following registrants:

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

32.2
Filed by Shane P. Smith for Constellation Energy Corporation

32.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

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

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

101.SCH Inline XBRL Taxonomy Extension Schema Document.

101.CAL Inline XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF Inline XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB Inline XBRL Taxonomy Extension Label Linkbase Document.

101.PRE Inline XBRL Taxonomy Extension Presentation Linkbase Document.

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

__________
* Schedules have been omitted pursuant to Item 601(b)(2) of Regulation S-K. CEG Parent will furnish the omitted schedules to the SEC upon request by the SEC.
** Portions of this exhibit have been redacted in accordance with Item 601(a)(6) of Regulation S-K.
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SIGNATURES

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

CONSTELLATION ENERGY CORPORATION

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

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

May 11, 2026
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Pursuant to requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
CONSTELLATION ENERGY GENERATION, LLC

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

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

May 11, 2026
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