10-Q – 2025-11-07 – ceg-20250930.htm

__________
(a) Surety bonds — Guarantees issued related to contract and commercial agreements, excluding bid bonds.
Environmental Remediation Matters
General. Our operations have in the past, and may in the future, require substantial expenditures to comply with environmental laws. Additionally, under Federal and state environmental laws, we are generally liable for the costs of remediating environmental contamination of property now or formerly owned by us and of property contaminated by hazardous substances generated by us. We own or lease several real estate parcels, including parcels on which our operations or the operations of others may have resulted in contamination by substances that are considered hazardous under environmental laws. In addition, we are currently involved in proceedings relating to sites where hazardous substances have been deposited and may be subject to additional proceedings in the future. Unless otherwise disclosed, we cannot reasonably estimate whether we will incur significant liabilities for additional investigation and remediation costs at these or additional sites identified by us, environmental agencies, or others. Additional costs could have a material, unfavorable impact on our consolidated financial statements.
As of September 30, 2025 and December 31, 2024, we had accrued undiscounted amounts for environmental liabilities of $ 10 million and $ 60 million, respectively, in Accounts payable and accrued expenses and $ 163 million and $ 169 million, respectively, in Other deferred credits and other liabilities in the Consolidated Balance Sheets. See Note 18 — Commitments and Contingencies of our 2024 Form 10-K for additional information on environmental remediation matters. As of September 30, 2025, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2024 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.
See Note 18 — Commitments and Contingencies of our 2024 Form 10-K for additional information on litigation matters. As of September 30, 2025, and through the date of filing, there have been no material changes in amounts recognized for the matters discussed in our 2024 Form 10-K.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Shareholders' Equity

15. Shareholders' Equity
Share Repurchase Program (CEG Parent)
Since 2023, our Board of Directors authorized the repurchase of up to $ 3  billion of the Company's outstanding common stock. As of September 30, 2025, there was approximately $ 593 million of remaining authority to repurchase shares of the Company's outstanding common stock, which reflects the net impact of capped call options, as discussed below. No other repurchase plans or programs have been authorized. See Note 19 — Shareholders' Equity of our 2024 Form 10-K for additional information on our share repurchase program.
During the three and nine months ended September 30, 2025, there were no open market repurchases. During the nine months ended September 30, 2024, we repurchased from the open market 1.2  million shares of our common stock for a total cost, inclusive of taxes and transaction costs, of $ 150  million. There were no open market repurchases during the three months ended September 30, 2024.
In 2024 and 2025, we entered into ASR agreements with financial institutions to initiate share repurchases of our common stock. Under the ASR agreements, we paid a specified amount to the financial institutions and received an initial delivery of shares of common stock, which resulted in an immediate reduction in the number of our shares outstanding. Based on the terms of the ASR agreements, we received an initial share delivery based on 80 % of each ASR agreements' cost. Upon settlement of the ASR agreements, the financial institution delivers additional incremental shares. The total number of shares ultimately delivered, and therefore the average price paid per share, is determined at the end of the applicable purchase period of each ASR agreement based on the average of the daily-volume weighted average share price, less a discount.
The following table summarizes the activity of our ASR agreements for the nine months ended September 30, 2025 and 2024:

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

Capped Call Options. In February 2025, we entered into two structured share repurchase agreements. Under these agreements, we made up-front cash payments totaling $ 150  million in exchange for the right to receive a predetermined amount of shares of our common stock or cash at expiration, depending upon the closing price of our common stock on the respective settlement dates. Any prepayments or cash payments at settlement were recorded in Common Stock on our Consolidated Balance Sheet and as a financing activity within our Consolidated Statement of Cash Flows. Neither option was exercised therefore we did not receive any shares at expiration. As a result, as of September 30, 2025, we received our initial up-front cash payments of $ 150  million plus a nominal cash premium. The cash received restored the remaining authority available for repurchases.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 15 — Shareholders' Equity

Changes in Accumulated Other Comprehensive Loss (All Registrants)
The following tables present changes in AOCI, net of tax, by component:

Three Months Ended September 30, 2025 Gains (losses) on Cash Flow Hedges Pension and OPEB Items (a)
Foreign Currency Items Total
Beginning balance $ ( 3 ) $ ( 2,263 ) $ ( 6 ) $ ( 2,272 )
OCI before reclassifications —   —   ( 8 ) ( 8 )
Amounts reclassified from AOCI 2   18   —   20  
Net current-period OCI 2   18   ( 8 ) 12  
Ending balance $ ( 1 ) $ ( 2,245 ) $ ( 14 ) $ ( 2,260 )

Three Months Ended September 30, 2024
Beginning balance $ ( 8 ) $ ( 2,125 ) $ ( 28 ) $ ( 2,161 )
OCI before reclassifications —   —   12   12  
Amounts reclassified from AOCI 1   14   —   15  
Net current-period OCI 1   14   12   27  
Ending balance $ ( 7 ) $ ( 2,111 ) $ ( 16 ) $ ( 2,134 )

Nine Months Ended September 30, 2025
Beginning balance $ ( 6 ) $ ( 2,262 ) $ ( 34 ) $ ( 2,302 )
OCI before reclassifications —   ( 34 ) 20   ( 14 )
Amounts reclassified from AOCI 5   51   —   56  
Net current-period OCI 5   17   20   42  
Ending balance $ ( 1 ) $ ( 2,245 ) $ ( 14 ) $ ( 2,260 )

Nine Months Ended September 30, 2024
Beginning balance $ ( 10 ) $ ( 2,157 ) $ ( 24 ) $ ( 2,191 )
OCI before reclassifications —   ( 4 ) 8   4  
Amounts reclassified from AOCI 3   50   —   53  
Net current-period OCI 3   46   8   57  
Ending balance $ ( 7 ) $ ( 2,111 ) $ ( 16 ) $ ( 2,134 )
__________
(a) AOCI amounts are included in the computation of net periodic pension and OPEB cost. See Note 10 — 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 September 30, Nine Months Ended September 30,
2025 2024 2025 2024
Pension and OPEB plans:

Actuarial loss reclassified to periodic benefit cost $ ( 5 ) $ ( 5 ) $ ( 18 ) $ ( 18 )
Pension and OPEB plans valuation adjustment —   —   12   2  

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

Note 16 — Variable Interest Entities

16. Variable Interest Entities
At September 30, 2025 and December 31, 2024, we consolidated several VIEs or VIE groups for which we are the primary beneficiary (see Consolidated VIEs below) and had significant interests in several other VIEs for which we do not have the power to direct the entities’ activities and, accordingly, we were not the primary beneficiary (see Unconsolidated VIEs below). Consolidated and unconsolidated VIEs are aggregated to the extent that the entities have similar risk profiles.
Consolidated VIEs
The table below shows the carrying amounts and classification of the consolidated VIEs’ assets and liabilities included in the consolidated financial statements as of September 30, 2025 and December 31, 2024. The assets, except as noted in the footnotes to the table below, can only be used to settle obligations of the VIEs. The liabilities, except as noted in the footnotes to the table below, are such that creditors, or beneficiaries, do not have recourse to our general credit.

September 30, 2025 December 31, 2024
Cash and cash equivalents $ 69   $ 59  
Restricted cash and cash equivalents 51   50  
Accounts receivable
       Customer accounts receivable, net
2,225   2,134  
       Other accounts receivable, net
10   12  
Inventories, net
       Materials and supplies
13   13  
Other current assets 32   38  
Total current assets 2,400   2,306  
Property, plant, and equipment, net 1,970   2,025  
Other noncurrent assets 127   142  
Total noncurrent assets 2,097   2,167  
Total assets (a)
$ 4,497   $ 4,473  

Long-term debt due within one year $ 66   $ 64  
Accounts payable and accrued expenses
37   54  
Other current liabilities
3   —  
Total current liabilities 106   118  
Long-term debt 589   642  
Asset retirement obligations 228   206  
Other noncurrent liabilities 2   2  
Total noncurrent liabilities 819   850  
Total liabilities
$ 925   $ 968  

__________
(a) Our balances include unrestricted assets for current unamortized energy contract assets of $ 19  million and $ 22  million, disclosed within other current assets in the table above and noncurrent unamortized energy contract assets of $ 120  million and $ 133  million, disclosed within other noncurrent assets in the table above as of September 30, 2025 and December 31, 2024, respectively.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Variable Interest Entities

As of September 30, 2025 and December 31, 2024, our consolidated VIEs included the following:

Consolidated VIE or VIE groups: Reason entity is a VIE: Reason we are the primary beneficiary:
CRP - A collection of wind and solar project entities. We have a 51 % equity ownership in CRP. See additional discussion below.
Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Bluestem Wind Energy Holdings, LLC - A Tax Equity structure which is consolidated by CRP. Similar structure to a limited partnership and the limited partners do not have kick-out rights with respect to the general partner.
We conduct the operational activities.
Antelope Valley - A solar generating facility, which is 100 % owned by us. Antelope Valley sells all of its output to PG&E through a PPA.
The PPA contract absorbs variability through a performance guarantee. We conduct all activities.
NER - A bankruptcy remote, special purpose entity which is 100 % owned by us, which purchases certain of our customer accounts receivable arising from the sale of retail electricity 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 energy purchase and sale contracts. 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 September 30, 2025 and December 31, 2024, we had significant unconsolidated variable interests in several VIEs for which we were not the primary beneficiary. These interests include certain commercial agreements.
The following table presents summary information about our significant unconsolidated VIE entities:

Commercial Agreement VIEs:
September 30, 2025 December 31, 2024
Total assets (a)
$ 712   $ 617  
Total liabilities (a)
90   42  

Other ownership interests in VIE (a)
622   575  

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

Note 16 — Variable Interest Entities

As of September 30, 2025 and December 31, 2024 the unconsolidated VIEs consist of:

Unconsolidated VIE groups: Reason entity is a VIE: Reason we are not the primary beneficiary:
Energy Purchase and Sale agreements - We have several energy purchase and sale agreements with generating facilities. PPA contracts that absorb variability through fixed pricing. We do not conduct the operational activities.

17. Supplemental Financial Information
Supplemental Statement 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 September 30, Nine Months Ended September 30,
Operating revenues 2025 2024 2025 2024

Variable lease income $ 65   $ 69   $ 181   $ 189  

Three Months Ended September 30, Nine Months Ended September 30,
Taxes other than income taxes 2025 2024 2025 2024
Property $ 74   $ 76   $ 216   $ 215  
Payroll 44   48   128   122  
Gross receipts (a)
46   37   123   102  
Other
1   4   5   7  
Total taxes other than income taxes
$ 165   $ 165   $ 472   $ 446  

__________
(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.

Three Months Ended September 30, Nine Months Ended September 30,
Other, net 2025 2024 2025 2024
Decommissioning-related activities:
Net realized income on NDT funds (a)

Regulatory Agreement Units $ 165   $ 203   $ 540   $ 460  
Non-Regulatory Agreement Units 78   118   245   233  
Net unrealized gains (losses) on NDT funds

Regulatory Agreement Units 313   337   624   548  
Non-Regulatory Agreement Units 200   190   430   329  
Regulatory offset to NDT fund-related activities (b)
( 383 ) ( 433 ) ( 935 ) ( 808 )
Total Decommissioning-related activities 373   415   904   762  

Net unrealized gains (losses) from equity investments (c)
19   ( 104 ) ( 256 ) ( 115 )

Other
51   14   81   46  
Total Other, net $ 443   $ 325   $ 729   $ 693  

__________
(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 Investments on the Consolidated Balance Sheets based on quoted market price of the stock.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 17 — Supplemental Financial Information

Supplemental Cash Flow Information
The following tables provide additional information about items recorded within our Consolidated Statements of Cash Flows.

Nine Months Ended September 30,
Depreciation, amortization, and accretion Income statement location
2025 2024
PP&E
Depreciation and amortization
$ 729   $ 850  
Nuclear fuel
Purchased power and fuel
712   656  
ARO accretion
Operating and maintenance 480   498  
Amortization of intangible assets, net
Depreciation and amortization 14   18  
Amortization of energy contract assets and liabilities Operating revenues or purchased power and fuel
10   27  
Total depreciation, amortization, and accretion $ 1,945   $ 2,049  

CEG Parent Constellation
Nine Months Ended September 30, Nine Months Ended September 30,
Other non-cash operating activities
2025 2024 2025 2024
Other decommissioning-related activity (a)
$ ( 366 ) $ ( 488 ) $ ( 366 ) $ ( 488 )
Pension and non-pension postretirement benefit costs
115   81   115   81  
Energy-related options (b)
( 34 ) 40   ( 34 ) 40  

Other
211   206   146   172  
Total other non-cash operating activities
$ ( 74 ) $ ( 161 ) $ ( 139 ) $ ( 195 )

__________
(a) Includes the elimination of decommissioning-related activities for the Regulatory Agreement Units, including the elimination of operating revenues, ARO accretion, ARC amortization, investment income, and income taxes related to all NDT fund activity for these units.
(b) Includes option premiums reclassified to realized at the settlement of the underlying contracts and recorded to results of operations.

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

September 30, 2025 CEG Parent Constellation
Cash and cash equivalents $ 3,959   $ 3,949  
Restricted cash and cash equivalents 132   88  

Total cash, restricted cash, and cash equivalents $ 4,091   $ 4,037  

December 31, 2024
Cash and cash equivalents $ 3,022   $ 3,018  
Restricted cash and cash equivalents 107   97  

Total cash, restricted cash, and cash equivalents $ 3,129   $ 3,115  

September 30, 2024
Cash and cash equivalents $ 1,793   $ 1,793  
Restricted cash and cash equivalents 89   77  

Total cash, restricted cash, and cash equivalents $ 1,882   $ 1,870  

For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2024 Form 10-K.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 17 — Supplemental Financial Information

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

Accounts payable and accrued expenses

September 30, 2025 CEG Parent Constellation
Accounts payable
$ 2,509   $ 2,478  
Compensation-related accruals (a)
781   556  
Taxes accrued (b)
177   175  
Other accrued expenses
459   459  
Total
$ 3,926   $ 3,668  

December 31, 2024
Accounts payable
$ 2,369   $ 2,348  
Compensation-related accruals (a)
907   689  
Taxes accrued (b)
232   223  
Other accrued expenses
435   436  
Total
$ 3,943   $ 3,696  
__________
(a) Primarily includes accrued payroll, bonuses and other incentives, vacation, and benefits.
(b) Includes $ 270 million and $ 150 million as of September 30, 2025 and December 31, 2024, respectively, related to nuclear PTC that was used to offset the current tax liability. See Note 6 — Government Assistance for additional information on the nuclear PTC.

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
We are the nation's largest producer of carbon-free energy and a supplier of energy products and services. Our generating capacity includes primarily nuclear, wind, solar, natural gas, and hydroelectric assets. Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial, industrial, public sector, and residential customers in markets across multiple geographic regions. We have five reportable segments: Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions.

Significant Transactions and Developments
Conowingo Hydroelectric Project License Renewal
In September 2025, we reached a settlement agreement with MDE, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, that resolves all outstanding issues related to obtaining a water quality certification from MDE. As a result, MDE issued a water quality certification, clearing the way for the re-licensing and continued operation of our Conowingo hydroelectric facility. The terms of the agreement include operational improvements and commitments for water quality and resiliency, trash and debris removal, aquatic life passage, freshwater mussel restoration, dredging and invasive species management. See Note 3 — Regulatory Matters for more information.
One Big Beautiful Bill Act
We continue to see legislative support for nuclear energy generation, including the passage of the OBBBA. Signed into law in July 2025, the OBBBA both preserves certain federal tax credits from the IRA and enhances certain credits to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to
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eligibility requirements. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. See Note 3 — Regulatory Matters for more information.
Clinton Clean Energy Center
In June 2025, we signed a 20-year PPA with Meta Platforms, Inc. (Meta) for the output of the Clinton Clean Energy Center to support Meta’s clean energy goals and operations in the region with emissions-free nuclear energy. The agreement, beginning in June 2027, supports the relicensing and continued operations of Clinton for another two decades after the state’s ZEC program expires. This deal will expand Clinton’s clean energy output by 30 megawatts through plant uprates, expected to be fully complete in 2029, and will enable the Clinton Clean Energy Center to continue to flow power onto the local grid, providing grid reliability and low-cost power to the region for decades to come. The uprates are expected to qualify for the technology-neutral clean electricity PTC (45Y) provided for by the IRA and preserved by the OBBBA for its first 10 years of operations.
Proposed Acquisition of Calpine Corporation
On January 10, 2025, we entered an agreement and plan of merger (Merger Agreement) with Calpine Corporation (Calpine) under which we will acquire all the outstanding equity interests of Calpine in a cash and stock transaction. Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with over 27 GWs of generation capacity, in addition to a competitive retail electric supplier platform with 60 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. We will couple the largest producer of clean, carbon-free energy with the reliable, dispatchable natural gas assets of Calpine, and also create the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that will enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine will strengthen our essential role in providing clean, reliable, and affordable 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.
We received regulatory approvals for the merger from the PUCT and NYPSC in June 2025 and from the FERC in July 2025. Completion of the transaction is subject to the expiration or termination of any agreement with the DOJ to delay the consummation of the transaction and other customary closing conditions. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Other Key Business Drivers
Tariffs
The energy sector has been impacted by changes in U.S. and foreign trade policies, particularly the introduction and adjustment of tariffs by the U.S. on the import of various energy-related products and materials. Importantly, oil, natural gas, and uranium (including enriched uranium) are currently excluded from most of the recent tariff changes. The imposition of tariffs on imported goods, including electric transformers and other equipment used for power generation, may lead to increased costs for acquiring essential components to maintain, uprate, and operate our generating facilities. We are committed to navigating the current environment through prudent cost management, utilization of supplier relationships, and potential supply alternatives as mitigants for potential price increases. The long-term impact of tariffs on the energy sector remains uncertain and we cannot predict or estimate the impact on future consolidated financial statements.
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
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support expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.
Environmental Regulation
Regulation of GHGs from Power Plants under the Clean Air Act. In April 2024, EPA issued a final rule that regulates greenhouse gases from existing coal, new natural gas-fired power plants, and existing oil/gas steam generators under Clean Air Act section 111. The applicable standards are subcategorized by retirement date for existing coal and capacity factor for new gas. In June 2025, EPA issued a proposal to repeal its regulations addressing GHG emissions from the sector. In July 2025, EPA issued a proposed rule to repeal the 2009 "Endangerment Finding" underpinning all GHG regulation by EPA. Repealing the finding would provide an independent basis for ending EPA regulation of GHGs from power plants.
Good Neighbor Rule. In June 2023, EPA published a final rule called “Federal 'Good Neighbor Plan' for the 2015 Ozone National Ambient Air Quality Standards” also known as the "Transport Rule". The rule, among other things, establishes nitrogen oxides emissions budgets requiring fossil fuel-fired power plants in 23 states to participate in an allowance-based ozone season trading program beginning in 2023. In February 2023, EPA disapproved state implementation plans submitted by 21 states for failure to address their obligations under the "good neighbor" provisions of the Clean Air Act. However, several Regional Courts of Appeals issued orders staying, pending judicial review, EPA's disapproval of several state plans (including Texas). In June 2024, the Supreme Court stayed EPA's rule for the duration of the litigation. In November 2024, EPA issued an administrative stay of the rule. EPA has announced its intent to approve state plans that would replace the Good Neighbor Plan.

Critical Accounting Policies and Estimates
Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At September 30, 2025, our critical accounting policies and estimates had not changed significantly from December 31, 2024. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2024 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 and nine months ended September 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and nine months ended September 30, 2025 and 2024, see the discussions of Results of Operations below.

Three Months Ended September 30, $ Change
Nine Months Ended September 30, $ Change

2025 2024 2025 2024
GAAP Net Income (Loss) Attributable to Common Shareholders
$ 930  $ 1,200  $ (270) $ 1,887  $ 2,897  $ (1,010)

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. For all adjustments except the NDT fund investment returns, which are included in decommissioning-related activities, the marginal statutory income tax rate was 25.6% and 25.5% for the three and nine months ended September 30, 2025 and 2024, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized and realized gains and losses related to NDT funds were 54.9% and 54.6% for the three months ended September 30, 2025 and 2024, respectively and 54.8% and 55.3% for the nine months ended September 30, 2025 and 2024, respectively. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three and nine months ended September 30, 2025 compared to the same period in 2024.

Three Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings Per Share (a)
Earnings Per Share (a)

GAAP Net Income (Loss) Attributable to Common Shareholders
$ 930  $ 2.97  $ 1,200  $ 3.82 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $32 and $72, respectively) (b)
94  0.30  (210) (0.67)
Plant Retirements and Divestitures (net of taxes of $2 and $10, respectively)
(5) (0.02) 30  0.10 
Decommissioning-Related Activities (net of taxes of $187 and $207, respectively) (c)
(117) (0.37) (195) (0.62)
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $3 and $1, respectively)
9  0.03  (2) (0.01)
Acquisition-Related Costs (net of taxes of $10 and $—, respectively) (d)
28  0.09  —  — 
Change in Environmental Liabilities (net of taxes of $— and $2, respectively)
1  —  5  0.02 

ERP System Implementation Costs (net of taxes of $— and $—, respectively)
—  —  1  — 
Income Tax-Related Adjustments (e)
13  0.04  33  0.11 

Noncontrolling Interests (f)
(1) —  (2) (0.01)
Adjusted (non-GAAP) Operating Earnings
$ 952  $ 3.04  $ 860  $ 2.74 

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Nine Months Ended September 30,
2025 2024
(In millions, except per share data) Earnings Per Share (a)
Earnings Per Share (a)

GAAP Net Income (Loss) Attributable to Common Shareholders
$ 1,887  $ 6.02  $ 2,897  $ 9.17 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $163 and $264, respectively) (b)
478  1.52  (786) (2.49)
Plant Retirements and Divestitures (net of taxes of $4 and $23, respectively)
13  0.04  68  0.22 
Decommissioning-Related Activities (net of taxes of $426 and $343, respectively) (c)
(242) (0.77) (227) (0.72)
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $9 and $1, respectively)
27  0.09  2  0.01 
Acquisition-Related Costs (net of taxes of $17 and $—, respectively) (d)
50  0.16  —  — 
Change in Environmental Liabilities (net of taxes of $1 and $20, respectively)
2  0.01  60  0.19 
Separation Costs (net of taxes of $— and $3, respectively)
—  —  9  0.03 
ERP System Implementation Costs (net of taxes of $— and $2, respectively)
—  —  7  0.02 
Income Tax-Related Adjustments (e)
13  0.04  (55) (0.17)

Noncontrolling Interests (f)
(4) (0.01) (5) (0.02)
Adjusted (non-GAAP) Operating Earnings
$ 2,224  $ 7.09  $ 1,970  $ 6.23 
__________
(a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 313 million and 314 million for the three months ended September 30, 2025 and 2024, respectively and 314 million and 316 million for the nine months ended September 30, 2025 and 2024, respectively.
(b) Includes mark-to-market 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.
(d) In 2025, reflects acquisition-related costs associated with the proposed Calpine merger.
(e) Adjustment to deferred income taxes due to changes in forecasted apportionment.
(f) Represents elimination of the noncontrolling interest portion of certain adjustments included above.
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Results of Operations

Three Months Ended September 30, $ Change
Nine Months Ended September 30, $ Change

2025 2024 2025 2024
Operating revenues $ 6,570  $ 6,550  $ 20  $ 19,459  $ 18,186  $ 1,273 
Operating expenses
Purchased power and fuel 3,567  3,119  448  11,083  8,828  2,255 
Operating and maintenance 1,511  1,535  (24) 4,673  4,666  7 
Depreciation and amortization 241  266  (25) 743  868  (125)
Taxes other than income taxes 165  165  —  472  446  26 
Total operating expenses 5,484  5,085  399  16,971  14,808  2,163 

Gain (loss) on sales of assets and businesses
—  2  (2) —  2  (2)

Operating income (loss)
1,086  1,467  (381) 2,488  3,380  (892)
Other income and (deductions)
Interest expense, net (134) (147) 13  (398) (416) 18 
Other, net 443  325  118  729  693  36 
Total other income and (deductions) 309  178  131  331  277  54 
Income (loss) before income taxes
1,395  1,645  (250) 2,819  3,657  (838)
Income tax (benefit) expense
466  449  17  928  768  160 
Equity in income (losses) of unconsolidated affiliates
—  —  —  —  (1) 1 
Net income (loss)
929  1,196  (267) 1,891  2,888  (997)
Net income (loss) attributable to noncontrolling interests
(1) (4) 3  4  (9) 13 
Net income (loss) attributable to common shareholders
$ 930  $ 1,200  $ (270) $ 1,887  $ 2,897  $ (1,010)

Three Months Ended September 30, 2025 Compared to Three Months Ended September 30, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($270) million primarily due to:
• Lower Nuclear PTC revenues in 2025. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information; and
• Unfavorable net unrealized losses on economic hedges.
The unfavorable items were partially offset by:
• Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization; and
• Higher net unrealized gains on equity investments.
Nine Months Ended September 30, 2025 Compared to Nine Months Ended September 30, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($1,010) million primarily due to:
• Lower Nuclear PTC revenues in 2025. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information;
• Unfavorable net unrealized losses on economic hedges; and
• Higher net unrealized losses on equity investments.
The unfavorable items were partially offset by:
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• Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization;
• Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years; and
• Favorable net realized and unrealized NDT fund investment activity.
Operating revenues. Our five reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
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 region.
For the three and nine months ended September 30, 2025 compared to 2024, Operating revenues were as follows:

Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 $ Change
% Change (a)
2025 2024 $ Change
% Change (a)

Mid-Atlantic $ 1,763  $ 1,603  $ 160  10.0  % $ 4,876  $ 4,148  $ 728  17.6  %
Midwest 1,390  1,275  115  9.0  % 4,317  3,537  780  22.1  %
New York 558  507  51  10.1  % 1,655  1,534  121  7.9  %
ERCOT 628  523  105  20.1  % 1,489  1,201  288  24.0  %
Other Power Regions 1,543  1,443  100  6.9  % 4,277  4,252  25  0.6  %
Total reportable segment electric revenues
5,882  5,351  531  9.9  % 16,614  14,672  1,942  13.2  %
Other 844  683  161  23.6  % 3,201  2,745  456  16.6  %
Mark-to-market gains (losses) (156) 516  (672) (356) 769  (1,125)
Total Operating revenues $ 6,570  $ 6,550  $ 20  0.3  % $ 19,459  $ 18,186  $ 1,273  7.0  %

__________
(a) % Change in mark-to-market is not a meaningful measure.
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Sales and Supply Sources. Our sales and supply volumes (GWhs) by region are summarized below:

Three Months Ended September 30, Nine Months Ended September 30,
(GWhs)
2025 2024 Change
% Change 2025 2024 Change
% Change
Nuclear Generation (a)

Mid-Atlantic 13,665  13,420  245  1.8  % 39,105  39,839  (734) (1.8) %
Midwest 23,644  23,835  (191) (0.8) % 71,000  71,381  (381) (0.5) %
New York 6,671  5,893  778  13.2  % 19,585  18,657  928  5.0  %
ERCOT
2,497  2,362  135  5.7  % 7,541  6,340  1,201  18.9  %
Total Nuclear Generation 46,477  45,510  967  2.1  % 137,231  136,217  1,014  0.7  %

Natural Gas, Oil, and Renewables
Mid-Atlantic 242  329  (87) (26.4) % 1,683  1,809  (126) (7.0) %
Midwest 141  151  (10) (6.6) % 785  774  11  1.4  %

ERCOT
4,325  4,783  (458) (9.6) % 10,615  11,890  (1,275) (10.7) %
Other Power Regions 1,466  1,850  (384) (20.8) % 4,556  7,017  (2,461) (35.1) %
Total Natural Gas, Oil, and Renewables 6,174  7,113  (939) (13.2) % 17,639  21,490  (3,851) (17.9) %

Purchased Power
Mid-Atlantic
5,416  6,022  (606) (10.1) % 13,960  12,707  1,253  9.9  %
Midwest 403  107  296  276.6  % 1,366  639  727  113.8  %

ERCOT 714  771  (57) (7.4) % 2,209  2,496  (287) (11.5) %
Other Power Regions 11,451  10,813  638  5.9  % 32,295  30,855  1,440  4.7  %
Total Purchased Power 17,984  17,713  271  1.5  % 49,830  46,697  3,133  6.7  %

Total Supply/Sales by Region
Mid-Atlantic 19,323  19,771  (448) (2.3) % 54,748  54,355  393  0.7  %
Midwest 24,188  24,093  95  0.4  % 73,151  72,794  357  0.5  %
New York 6,671  5,893  778  13.2  % 19,585  18,657  928  5.0  %
ERCOT
7,536  7,916  (380) (4.8) % 20,365  20,726  (361) (1.7) %
Other Power Regions 12,917  12,663  254  2.0  % 36,851  37,872  (1,021) (2.7) %
Total Supply/Sales by Region 70,635  70,336  299  0.4  % 204,700  204,404  296  0.1  %
__________
(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 
 September 30, Nine Months Ended 
 September 30,
2025 2024 2025 2024
Nuclear fleet capacity factor 96.8  % 95.0  % 95.3  % 94.6  %
Refueling outage days 23  37  152  164 
Non-refueling outage days 5  20  27  33 

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 within each region, depending on our net hourly position. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the 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 each of our major regions and does not necessarily reflect prices we ultimately realized.

Three Months Ended September 30, Nine Months Ended September 30,
Location (Region) 2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
PJM West (Mid-Atlantic) $ 46.77  $ 36.98  $ 9.79  26.5  % $ 47.63  $ 33.41  $ 14.22  42.6  %
ComEd (Midwest) 42.72  28.92  13.80  47.7  % 36.37  25.80  10.57  41.0  %
Central (New York) 49.51  33.30  16.21  48.7  % 54.07  31.80  22.27  70.0  %
North (ERCOT) 35.05  26.61  8.44  31.7  % 33.06  27.75  5.31  19.1  %
Southeast Massachusetts (Other) (a)
50.43  38.37  12.06  31.4  % 65.16  37.34  27.82  74.5  %

__________
(a) Reflects New England, which comprises the majority of the activity in the Other region.
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Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. 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 within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/MW Day) for each of our major regions. Prices reflect the weighted average prices for the various auction periods within the three and nine months ended September 30, 2025 and 2024.

Three Months Ended September 30, Nine Months Ended September 30,
Location (Region) 2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic) $ 269.92  $ 53.60  $ 216.32  403.6  % $ 149.74  $ 51.32  $ 98.42  191.8  %
ComEd (Midwest) 269.92  28.92  241.00  833.3  % 136.03  31.81  104.22  327.6  %
Rest of State (New York) 193.33  132.22  61.11  46.2  % 137.52  112.78  24.74  21.9  %
Southeast New England (Other) 87.97  949.57  (861.60) (90.7) % 566.63  459.07  107.56  23.4  %

ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and nine months ended September 30, 2025 and 2024 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

Three Months Ended September 30, Nine Months Ended September 30,
State (Region) (a)
2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
New Jersey (Mid-Atlantic) (b)
$ —  $ 10.00  $ (10.00) (100.0) % $ 10.00  $ 9.97  $ 0.03  0.3  %
Illinois (Midwest )
1.17  9.38  (8.21) (87.5) % 5.73  4.34  1.39  32.0  %
New York (New York) 14.76  18.27  (3.51) (19.2) % 15.93  18.27  (2.34) (12.8) %

__________
(a) See ITEM 1. BUSINESS, Environmental Matters of our 2024 Form 10-K for additional information on the plants receiving payments through state programs.
(b) The New Jersey ZEC program ended 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 $32.50 per MWh for the period June 2023 through May 2024, $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 ($17.11) and $5.54 for the three months ended September 30, 2025 and 2024, respectively, and ($6.53) and $7.73 for the nine months ended September 30, 2025 and 2024, 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 $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. 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 and nine months ended September 30, 2025 compared to 2024:

Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
Nuclear PTC revenue (a)
$ 175  $ 670  $ (495) (73.9) % $ 220  $ 1,380  $ (1,160) (84.1) %
State-sponsored programs net revenue (b)
(220) (115) (105) (91.3) % (30) 10  (40) (400.0) %

__________
(a) Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.
For the three and nine months ended September 30, 2025 compared to 2024, changes in Operating revenues by region were approximately as follows:

Three Months Ended 
 September 30 Nine Months Ended 
 September 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Mid-Atlantic $ 160  10.0  % • favorable retail load revenue of $185 primarily due to higher contracted energy prices and load volumes
• favorable wholesale load revenue of $80 primarily due to higher contracted energy prices; partially offset by
• absence of nuclear PTC revenue of ($160) due to higher energy prices in the current year
$ 728  17.6  % • favorable retail load revenue of $445 primarily due to higher contracted energy prices and load volumes
• favorable realized economic hedges of $410 due to settled prices relative to hedged prices
• favorable wholesale load revenue of $200 primarily due to higher contracted energy prices; partially offset by
• absence of nuclear PTC revenue of ($340) due to higher energy prices in the current year

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Three Months Ended 
 September 30 Nine Months Ended 
 September 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Midwest 115  9.0  % • favorable retail load revenue of $190 primarily due to higher contracted energy prices and load volumes
• favorable realized economic hedges of $175 due to settled prices relative to hedged prices
• favorable net generation and wholesale load revenue of $130 primarily due to higher load volumes and contracted energy prices
• favorable net capacity revenue of $90 due to higher capacity prices; partially offset by
• lower nuclear PTC revenue of ($280) and CMC program revenue of ($155) due to higher energy prices in the current year
780  22.1  % • favorable net generation and wholesale load revenue of $500 primarily due to higher load volumes and contracted energy prices
• favorable realized economic hedges of $540 due to settled prices relative to hedged prices
• favorable retail load revenue of $310 primarily due to higher contracted energy prices and load volumes
• favorable net ZEC revenue of $180 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years and increase in ZEC price
• favorable net capacity revenue of $110 due to higher capacity prices; partially offset by
• lower nuclear PTC revenue of ($710) and CMC program revenue of ($160) due to higher energy prices in the current year

New York 51  10.1  % • favorable net generation revenue of $70 primarily due to higher energy prices
• favorable ZEC program revenue of $50 primarily due to the absence of nuclear PTC revenue; partially offset by
• absence of nuclear PTC revenue of ($60) due to higher energy prices in the current year
121  7.9  % • favorable net generation revenue of $185 primarily due to higher energy prices
• favorable ZEC program revenue of $90 primarily due to the absence of nuclear PTC revenue
• favorable retail load revenue of $85 primarily due to higher contracted energy prices; partially offset by
• absence of nuclear PTC revenue of ($120) due to higher energy prices in the current year
• unfavorable realized economic hedges of ($115) due to settled prices relative to hedged prices

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Three Months Ended 
 September 30 Nine Months Ended 
 September 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

ERCOT 105  20.1  % • favorable wholesale load revenue of $45 primarily due to higher contracted energy prices
288  24.0  % • favorable realized economic hedges of $110 due to settled prices relative to hedged prices
• favorable wholesale load revenue of $95 primarily due to higher contracted energy prices
• favorable retail load revenue of $65 primarily due to higher contracted energy prices

Other Power Regions 100  6.9  % • favorable net wholesale load revenue of $80 primarily due to higher contracted energy prices
25  0.6  % • No individually significant drivers

Other 161  23.6  % • favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $100 primarily due to higher energy prices
• favorable retail gas revenue of $65 primarily due to higher gas prices
456  16.6  % • favorable retail gas revenue of $305 primarily due to higher gas prices
• favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $180 primarily due to higher energy prices

Mark-to-market (b)
(672) • losses on economic hedging activities of ($156) in 2025 compared to gains of $516 in 2024
(1,125) • losses on economic hedging activities of ($356) in 2025 compared to gains of $769 in 2024

Total $ 20  0.3  % $ 1,273  7.0  %

__________
(a) % Change in mark-to-market is not a meaningful measure.
(b) See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
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Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.
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 region.
For the three and nine months ended September 30, 2025 compared to 2024, Purchased power and fuel expense were as follows:

Three Months Ended September 30, Nine Months Ended September 30,
2025 2024 $ Change
% Change (a)
2025 2024 $ Change
% Change (a)

Mid-Atlantic $ 871  $ 794  $ 77  9.7  % $ 2,393  $ 1,906  $ 487  25.6  %
Midwest 447  391  56  14.3  % 1,489  1,185  304  25.7  %
New York 159  150  9  6.0  % 458  460  (2) (0.4) %
ERCOT 213  120  93  77.5  % 589  375  214  57.1  %
Other Power Regions 1,200  1,010  190  18.8  % 3,560  3,157  403  12.8  %
Total electric purchased power and fuel 2,890  2,465  425  17.2  % 8,489  7,083  1,406  19.9  %
Other 702  537  165  30.7  % 2,664  2,149  515  24.0  %
Mark-to-market losses (gains) (25) 117  (142) (70) (404) 334 
Total Purchased power and fuel $ 3,567  $ 3,119  $ 448  14.4  % $ 11,083  $ 8,828  $ 2,255  25.5  %

__________
(a) % Change in mark-to-market is not a meaningful measure.
For the three and nine months ended September 30, 2025 compared to 2024, changes in Purchased power and fuel expense by region were approximately as follows:

Three Months Ended 
 September 30 Nine Months Ended 
 September 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Mid-Atlantic $ 77  9.7  % • unfavorable cost of ($105) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices and net capacity expense
$ 487  25.6  % • unfavorable cost of ($465) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices, lower generation volumes, and higher net capacity expense

Midwest 56  14.3  % • unfavorable cost of ($40) associated with purchased power to supply load relative to generation volumes primarily driven by higher energy prices
304  25.7  % • unfavorable cost of ($270) associated with purchased power to supply load relative to generation volumes primarily driven by higher transmission costs and higher energy prices

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Three Months Ended 
 September 30 Nine Months Ended 
 September 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

New York 9  6.0  % • No individually significant drivers
(2) (0.4) % • No individually significant drivers

ERCOT 93  77.5  % • unfavorable cost of ($60) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices
214  57.1  % • unfavorable cost of ($160) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices
• unfavorable realized economic hedges of ($60) due to settled prices relative to hedged prices

Other Power Regions 190  18.8  % • unfavorable purchased power of ($240) primarily due to higher energy prices; partially offset by
• favorable realized economic hedges of $65 due to settled prices relative to hedged prices
403  12.8  % • unfavorable purchased power of ($1,080)
primarily due to lower generation volumes driven by the retirement of Mystic Units 8 and 9 and higher energy prices; partially offset by
• favorable realized economic hedges of $730
due to settled prices relative to hedged prices

Other 165  30.7  % • unfavorable purchases in the United Kingdom, inclusive of settled economic hedges, of ($110) primarily due to higher energy prices
• unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of ($40) primarily due to higher gas prices
515  24.0  % • unfavorable net wholesale gas purchases, inclusive of realized
economic hedges, of ($250) primarily due to higher gas prices
• unfavorable purchases in the United Kingdom, inclusive of realized economic hedges, of ($205) primarily due to higher energy prices
• unfavorable fair value adjustments related to gas imbalances of ($60)

Mark-to-market (b)
(142) • gains on economic hedging activities of $25 in 2025 compared to losses of ($117) in 2024
334  • gains on economic hedging activities of $70 in 2025 compared to gains of $404 in 2024

Total $ 448  14.4  % $ 2,255  25.5  %

__________
(a) % Change in mark-to-market is not a meaningful measure.
(b) See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

Effective income tax rates were 33.4% and 27.3% for the three months ended September 30, 2025 and 2024, respectively and 32.9% and 21.0% for the nine months ended September 30, 2025 and 2024, respectively. The change in effective tax rate for 2025 is primarily due to the decrease in nuclear PTCs generated, which are not taxable, as well as higher qualified NDT fund income which is taxed at a higher rate. See Note 9 — 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. 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., 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 $9.5 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 12 — 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 nine months ended September 30, 2025 and 2024, respectively:

Nine Months Ended September 30,
2025 2024 $ Change
Cash, restricted cash, and cash equivalents at beginning of period
$ 3,129  $ 454  $ 2,675 
Net cash provided by (used in):
Operating activities 3,432  (1,448) 4,880 
Investing activities (2,221) 5,056  (7,277)
Financing activities (249) (2,180) 1,931 
Net increase (decrease) in cash, restricted cash, and cash equivalents
962  1,428  (466)

Cash, restricted cash, and cash equivalents at end of period
$ 4,091  $ 1,882  $ 2,209 

Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities was $3,432 million for the nine months ended September 30, 2025, compared to cash used in operating activities of ($1,448) million for the nine months ended September 30, 2024. 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. In December 2024, we amended our Accounts Receivable Facility whereby we now retain the rights to our receivables and any changes in our receivable balance flow through operating activities. This increase in cash flows from operating activities was partially offset by cash outflows associated with an increase in collateral postings. See Note 7 — Accounts Receivable and Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
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Net Cash Provided By (Used In) Investing Activities
Cash used in investing activities was ($2,221) million for the nine months ended September 30, 2025, compared to cash provided by investing activities of $5,056 million for the nine months ended September 30, 2024. The change was primarily due to an amendment of our Accounts Receivable Facility. Prior to the amendment, the collection and reinvestment of proceeds associated with the sale of receivables were treated as cash flows from investing activities in the Consolidated Statements of Cash Flows. As a result of the amendment, cash collections of accounts receivable are now treated as Cash flows from operating activities in the Consolidated Statement of Cash Flows. See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.
Net Cash Provided By (Used In) Financing Activities
Cash used in financing activities was ($249) million for the nine months ended September 30, 2025, compared to cash used in financing activities of ($2,180) million for the nine months ended September 30, 2024. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. The remaining change relates to repurchases of common stock during each period. See Note 12 — Debt and Credit Agreements and Note 15 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Quarterly dividends declared by our Board of Directors during the nine months ended September 30, 2025 and for the fourth quarter of 2025 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share
First Quarter of 2025
February 18, 2025 March 7, 2025 March 18, 2025 $ 0.3878 
Second Quarter of 2025
April 29, 2025 May 16, 2025 June 6, 2025 $ 0.3878 
Third Quarter of 2025
August 5, 2025 August 18, 2025 September 5, 2025 $ 0.3878 
Fourth Quarter of 2025
October 29, 2025 November 17, 2025 December 5, 2025 $ 0.3878 

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 September 30, 2025, we have access to facilities with aggregate bank commitments of $9.5 billion. During the quarter, we amended one of our existing revolving credit facilities to both extend the term of the existing facility and to provide up to $2.5 billion in incremental revolving credit commitments upon the satisfaction of certain conditions following the consummation of our acquisition of Calpine. See Note 12 — 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 third quarter of 2025 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 2024 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, including the cash consideration necessary to close on our proposed acquisition of Calpine. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
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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 September 30, 2025 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of September 30, 2025, we had $7.3 billion of available capacity under our credit facilities and $4.0 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 following the announcement of our proposed acquisition of Calpine.
If we had lost our investment grade credit ratings as of September 30, 2025, we would have been required to provide incremental collateral estimated to be approximately $2.4 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.
See Note 11 — Derivative Financial Instruments and Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension and Other Postretirement Benefits
We consider various factors when making qualified pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2025 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 2025 are approximately $19 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $22 million. Expected contributions in 2025 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 2024 Form 10-K for additional information on pension and other postretirement benefits.
Cash Requirements for Other Financial Commitments
Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2024 Form 10-K for additional information on our cash requirements for financial commitments.
Customer Accounts Receivable Financing
We have an accounts receivable financing facility with a number of financial institutions which provides us access to revolving loans secured by certain receivables. See Note 12 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
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Project Financing
Project financing is based upon a nonrecourse 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. Lenders do not have recourse against us in the event of a default. 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. See Note 16 — Debt and Credit Agreements of our 2024 Form 10-K for additional information on project finance credit facilities and nonrecourse debt.
Credit Facilities
We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. See Note 12 — 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 8 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.
As of September 30, 2025, 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 September 30, 2025, 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 2024 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

(Dollars in millions, unless otherwise noted)
We are exposed to market risks associated with adverse changes in commodity prices, counterparty credit, interest rates, and equity prices. We manage these risks through risk management policies and objectives for risk assessment, control and valuation, counterparty credit approval, and the monitoring and reporting of risk exposures. We report risk management issues to the Executive Committee and the Audit and Risk Committee of the Board of Directors. The following discussion serves as an update to ITEM 7A — QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK of our 2024 Annual Report on Form 10-K incorporated herein by reference.
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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 2025 through 2027. We also enter 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 September 30, 2025 for our portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price results in an impact to earnings that is not material for 2025 and a decrease to earnings of approximately $219 million for 2026. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Fuel Procurement
We procure natural gas through long-term and short-term contracts, and spot-market purchases. 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 2025 through 2030 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 more information on the Russia and Ukraine conflict.
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Trading and Non-Trading Marketing Activities
The following table provides detail on changes in our commodity derivative contract net assets (liabilities) balance sheet position from December 31, 2024 to September 30, 2025. This table incorporates the unrealized gains and losses that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 11 — 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 September 30, 2025 and December 31, 2024.

Balance as of December 31, 2024 (a)
$ 317 
Total change in fair value of contracts recorded in results of operations
(317)
Reclassification to realized at settlement of contracts recorded in results of operations 30 

Changes in allocated collateral 190 
Net option premium paid (received)
(49)
Option premium amortization 34 
Upfront payments and amortizations (b) 
(22)
Foreign currency translation (1)
Balance as of September 30, 2025 (a)
$ 182 

__________
(a) Amounts are shown net of collateral paid to and received from counterparties.
(b) Includes derivative contracts acquired or sold through upfront payments or receipts of cash, excluding option premiums, and the associated amortizations.
Fair Values
The following table presents maturity and source of fair value for commodity derivative contract net assets (liabilities). See Note 13 — 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

2025 2026 2027 2028 2029 2030 and Beyond
Normal Operations, Commodity derivative contracts (a)(b) :

Actively quoted prices (Level 1) $ (9) $ 80  $ 32  $ (11) $ (8) $ (1) $ 83 
Prices provided by external sources (Level 2) (39) 111  68  7  7  —  154 
Prices based on model or other valuation methods (Level 3) 186  (85) (111) (31) (22) 8  (55)
Total $ 138  $ 106  $ (11) $ (35) $ (23) $ 7  $ 182 

__________
(a) Represents unrealized gains and losses on commodity derivative contracts that are recorded in the results of operations.
(b) Amounts are shown net of collateral paid to and received from counterparties (and offset against mark-to-market assets and liabilities) of $776 million at September 30, 2025.
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 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
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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 11 — Derivative Financial Instruments and Note 14 — 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.
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, 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 solely 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 and Foreign Exchange 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 nine months ended September 30, 2025. To manage foreign exchange rate exposure associated with international energy purchases in currencies other than U.S. dollars, we utilize foreign currency derivatives, which are typically designated as economic hedges. See Note 11 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
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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 $1,061 million reduction in the fair value of our NDT trust assets as of September 30, 2025. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 8 — Nuclear Decommissioning 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 2024 Form 10-K for further information.

ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
During the third quarter of 2025, 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.
As of September 30, 2025, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective to accomplish their objectives.
Changes in Internal Control Over Financial Reporting
We continually strive to improve our disclosure controls and procedures to enhance the quality of our financial reporting and to maintain dynamic systems that change as conditions warrant. There have been no changes in internal control over financial reporting that occurred during the third quarter of 2025 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 14 — 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 September 30, 2025, our risk factors were consistent with the risk factors described in our 2024 Form 10-K in ITEM 1A. RISK FACTORS.

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

Issuer Purchases of Equity Securities (CEG Parent)
Since 2023, our Board of Directors authorized the repurchase of up to $3 billion of the Company's outstanding common stock. No other repurchase plans or programs have been authorized. In February 2025, we entered into structured repurchase agreements whereby we purchased capped call options to reduce the total cost of our ongoing share repurchase program. Both agreements expired unexercised as of September 30, 2025. See Note 15 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.
There were no open market share repurchases under the program during the nine months ended September 30, 2025.
In June 2025, we entered into an ASR agreement with a financial institution to initiate share repurchases of our common stock for $404 million, inclusive of taxes and other transaction costs. Under the ASR agreement, we received an initial share delivery of approximately 1.1 million shares of our common stock, which resulted in an immediate reduction in the number of our shares outstanding. In the third quarter of 2025, the remaining shares were delivered upon completion of the transaction and were based on the average of the daily-volume weighted average price of our common stock during the term, less a discount.
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The following table provides information regarding our share repurchases under the program during the three months ended September 30, 2025:

Period Total Number of Shares Purchased (a)
Average Price Paid per Share
Approximate Dollar Value of Shares that May Yet Be Purchased Under the Programs (d)

July 1, 2025 to July 31, 2025
—  $ —  $ 540 
August 1, 2025 to August 31, 2025 (b)(c)
183,135  311.84  593 
September 1, 2025 to September 30, 2025
—  —  593 
Total
183,135  $ 593 

__________
(a) We have not made any purchases of shares other than in connection with the publicly announced share repurchase program described above.
(b) Increase in remaining authority as a result of receipt of cash including a nominal cash premium following expiration of capped call option. See Note 15 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
(c) Represents the additional shares delivered under the June 2025 ASR agreement, which was fully settled in the third quarter of 2025.
(d) Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions.

ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.

ITEM 5. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the three months ended September 30, 2025, 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
1 0.1
Second Amended and Restated Credit Agreement dated as of September 19, 2025 among Constellation, JPMorgan Chase Bank, N.A., as Administrative Agent, and the various financial institutions party thereto (File No. 333-85496, Form 8-K dated September 22, 2025, Exhibit 1.1)

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 September 30, 2025 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 Daniel L. Eggers for Constellation Energy Corporation

31.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

31.4
Filed by Daniel L. Eggers 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 September 30, 2025 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 Daniel L. Eggers for Constellation Energy Corporation

32.3
Filed by Joseph Dominguez for Constellation Energy Generation, LLC

32.4
Filed by Daniel L. Eggers 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)

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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/ DANIEL L. EGGERS
Joseph Dominguez Daniel L. Eggers
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)

November 7, 2025
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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/ DANIEL L. EGGERS
Joseph Dominguez Daniel L. Eggers
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)

November 7, 2025
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