10-Q – 2025-08-07 – ceg-20250630.htm

Regulatory Agreement Units 429   ( 14 ) 311   211  
Non-Regulatory Agreement Units 253   5   230   139  
Regulatory offset to NDT fund-related activities (b)
( 449 ) ( 63 ) ( 552 ) ( 375 )
Total Decommissioning-related activities 437   51   531   347  

Net realized and unrealized gains (losses) from equity investments (c)
( 7 ) ( 58 ) ( 275 ) ( 11 )

Other
10   13   30   32  
Total Other, net $ 440   $ 6   $ 286   $ 368  

__________
(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 16 — Supplemental Financial Information

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

Six Months Ended June 30,
Depreciation, amortization, and accretion 2025 2024
PP&E (a)
$ 492   $ 590  
Nuclear fuel (b)
468   433  
ARO accretion (c)
318   336  
Amortization of energy contract assets and liabilities (d)
12   17  
Amortization of intangible assets, net (a)
10   12  
Total depreciation, amortization, and accretion $ 1,300   $ 1,388  

__________
(a) Included in Depreciation and amortization expense in the Consolidated Statements of Operations and Comprehensive Income.
(b) Included in Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.
(c) Included in Operating and maintenance expense in the Consolidated Statements of Operations and Comprehensive Income.
(d) Included in Operating revenues or Purchased power and fuel expense in the Consolidated Statements of Operations and Comprehensive Income.

CEG Parent Constellation
Six Months Ended June 30, Six Months Ended June 30,
Other non-cash operating activities
2025 2024 2025 2024
Other decommissioning-related activity (a)
$ ( 224 ) $ ( 246 ) $ ( 224 ) $ ( 246 )
Pension and non-pension postretirement benefit costs
76   56   76   56  
Energy-related options (b)
( 23 ) 30   ( 23 ) 30  

Other (c)
150   95   101   78  
Total other non-cash operating activities
$ ( 21 ) $ ( 65 ) $ ( 70 ) $ ( 82 )

__________
(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.
(c) Includes items that are not individually material.
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Combined Notes to Consolidated Financial Statements
(Dollars in millions, unless otherwise noted)

Note 16 — Supplemental Financial Information

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

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

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

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  

June 30, 2024
Cash and cash equivalents $ 311   $ 308  
Restricted cash and cash equivalents 72   64  

Total cash, restricted cash, and cash equivalents $ 383   $ 372  

For additional information on restricted cash, see Note 1 — Basis of Presentation of our 2024 Form 10-K.
Supplemental Balance Sheet Information
The following table provides additional information about material items recorded in the Consolidated Balance Sheets.

Accounts payable and accrued expenses

June 30, 2025 CEG Parent Constellation
Accounts payable
$ 2,446   $ 2,414  
Compensation-related accruals (a)
605   396  
Taxes accrued
205   203  

December 31, 2024
Accounts payable
$ 2,369   $ 2,348  
Compensation-related accruals (a)
907   689  
Taxes accrued
232   223  

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

17. Subsequent Events
One Big Beautiful Bill Act
In July 2025, the OBBBA was signed into law, which, among other things, permanently extends key provisions of the 2017 Tax Cuts and Jobs Act, including full bonus depreciation and immediate deduction of research and development expenses. In addition, the OBBBA preserves transferability and certain federal tax credits from the IRA, specifically, 45U for existing nuclear plants through 2032 and 45Y for new nuclear projects, including uprates, restarts, and new reactors, through 2035, while enhancing the credit to allow advanced nuclear facilities to qualify for the energy communities bonus adder subject to eligibility requirements. As it relates to both 45U and 45Y, certain foreign entity of concern rules must be met to qualify for the respective credits. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. We are currently evaluating the full impact of these provisions, which will be recognized in the third quarter of 2025 and is not expected to have a material impact to our results of operations.
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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
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 eligibility requirements. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. See Note 17 - Subsequent Events for additional information regarding the bill.
Clinton Clean Energy Center
We have 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 nuclear facility 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.
Regulatory approvals for the acquisition were received by the PUCT and NYPSC in June 2025 and by the FERC in July 2025. Completion of the transaction is conditioned upon review by the DOJ and other customary closing conditions. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
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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 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.
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Critical Accounting Policies and Estimates
Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At June 30, 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 six months ended June 30, 2025 compared to the same period in 2024. For additional information regarding the financial results for the three and six months ended June 30, 2025 and 2024, see the discussions of Results of Operations below.

Three Months Ended June 30, $ Change
Six Months Ended June 30, $ Change

2025 2024 2025 2024
GAAP Net Income (Loss) Attributable to Common Shareholders
$ 839  $ 814  $ 25  $ 957  $ 1,697  $ (740)

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 25.5% and 25.1% for the three and six months ended June 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 54.6% and 66.9% for the three months ended June 30, 2025 and 2024, respectively and 54.7% and 56.2% for the six months ended June 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 six months ended June 30, 2025 compared to the same period in 2024.

Three Months Ended June 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
$ 839  $ 2.67  $ 814  $ 2.58 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $37 and $136, respectively) (b)
(121) (0.38) (405) (1.28)
Plant Retirements and Divestitures (net of taxes of $2 and $9, respectively)
7  0.02  26  0.08 
Decommissioning-Related Activities (net of taxes of $208 and $3, respectively) (c)
(144) (0.46) 36  0.11 
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $3 and $—, respectively)
9  0.03  1  — 
Acquisition-Related Costs (net of taxes of $3 and $—, respectively) (d)
9  0.03  —  — 
Change in Environmental Liabilities (net of taxes of $— and $18, respectively)
—  —  55  0.17 
Separation Costs (net of taxes of $— and $1, respectively)
—  —  4  0.01 
ERP System Implementation Costs (net of taxes of $— and $1, respectively)
—  —  2  0.01 

Noncontrolling Interests (f)
—  —  (2) (0.01)
Adjusted (non-GAAP) Operating Earnings
$ 599  $ 1.91  $ 531  $ 1.68 

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Six Months Ended June 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
$ 957  $ 3.05  $ 1,697  $ 5.35 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $131 and $193, respectively) (b)
384  1.22  (575) (1.81)
Plant Retirements and Divestitures (net of taxes of $6 and $13, respectively)
18  0.06  38  0.12 
Decommissioning-Related Activities (net of taxes of $239 and $136, respectively) (c)
(125) (0.40) (32) (0.10)
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $6 and $1, respectively)
18  0.06  4  0.01 
Acquisition-Related Costs (net of taxes of $8 and $—, respectively) (d)
22  0.07  —  — 
Change in Environmental Liabilities (net of taxes of $— and $19, respectively)
1  —  55  0.17 
Separation Costs (net of taxes of $— and $3, respectively)
—  —  9  0.03 
ERP System Implementation Costs (net of taxes of $— and $2, respectively)
—  —  5  0.02 
Income Tax-Related Adjustments (e)
—  —  (88) (0.28)

Noncontrolling Interests (f)
(3) (0.01) (3) (0.01)
Adjusted (non-GAAP) Operating Earnings
$ 1,272  $ 4.05  $ 1,110  $ 3.50 
__________
(a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 314 million and 316 million for the three months ended June 30, 2025 and 2024, respectively and 314 million and 317 million for the six months ended June 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) In 2024, primarily reflects the 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 June 30, $ Change
Six Months Ended June 30, $ Change

2025 2024 2025 2024
Operating revenues $ 6,101  $ 5,475  $ 626  $ 12,889  $ 11,637  $ 1,252 
Operating expenses
Purchased power and fuel 3,132  2,292  840  7,516  5,709  1,807 
Operating and maintenance 1,617  1,645  (28) 3,162  3,131  31 
Depreciation and amortization 254  296  (42) 502  602  (100)
Taxes other than income taxes 147  142  5  307  282  25 
Total operating expenses 5,150  4,375  775  11,487  9,724  1,763 

Operating income (loss)
951  1,100  (149) 1,402  1,913  (511)
Other income and (deductions)
Interest expense, net (118) (142) 24  (264) (269) 5 
Other, net 440  6  434  286  368  (82)
Total other income and (deductions) 322  (136) 458  22  99  (77)
Income (loss) before income taxes
1,273  964  309  1,424  2,012  (588)
Income tax (benefit) expense
440  154  286  462  318  144 
Equity in income (losses) of unconsolidated affiliates
—  (1) 1  —  (2) 2 
Net income (loss)
833  809  24  962  1,692  (730)
Net income (loss) attributable to noncontrolling interests
(6) (5) (1) 5  (5) 10 
Net income (loss) attributable to common shareholders
$ 839  $ 814  $ 25  $ 957  $ 1,697  $ (740)

Three Months Ended June 30, 2025 Compared to Three Months Ended June 30, 2024. The variance in Net income (loss) attributable to common shareholders was favorable by $25 million primarily due to:
• Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years;
• Favorable net realized and unrealized NDT fund investment activity; and
• Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization.
The favorable items were partially offset by:
• Lower Nuclear PTC revenues in 2025. See Note 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information; and
• Unfavorable lower net unrealized gains on economic hedges.
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Six Months Ended June 30, 2025 Compared to Six Months Ended June 30, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by ($740) million primarily due to:
• Unfavorable net unrealized losses on economic hedges;
• Lower Nuclear PTC revenues in 2025. See Note 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information; and
• Higher net unrealized losses on equity investments.
The unfavorable items were partially offset by:
• Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years;
• Favorable market and portfolio conditions primarily driven by higher capacity revenues, higher realized margins on load contracts and generation-to-load optimization; 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 4 — 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 six months ended June 30, 2025 compared to 2024, Operating revenues were as follows:

Three Months Ended June 30, Six Months Ended June 30,
2025 2024 $ Change
% Change (a)
2025 2024 $ Change
% Change (a)

Mid-Atlantic $ 1,448  $ 1,304  $ 144  11.0  % $ 3,113  $ 2,546  $ 567  22.3  %
Midwest 1,524  1,168  356  30.5  % 2,928  2,262  666  29.4  %
New York 535  514  21  4.1  % 1,097  1,027  70  6.8  %
ERCOT 464  357  107  30.0  % 862  678  184  27.1  %
Other Power Regions 1,178  1,184  (6) (0.5) % 2,734  2,808  (74) (2.6) %
Total reportable segment electric revenues
5,149  4,527  622  13.7  % 10,734  9,321  1,413  15.2  %
Other 866  756  110  14.6  % 2,356  2,062  294  14.3  %
Mark-to-market gains (losses) 86  192  (106) (201) 254  (455)
Total Operating revenues $ 6,101  $ 5,475  $ 626  11.4  % $ 12,889  $ 11,637  $ 1,252  10.8  %

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

Three Months Ended June 30, Six Months Ended June 30,
(GWhs)
2025 2024 Change
% Change 2025 2024 Change
% Change
Nuclear Generation (a)

Mid-Atlantic 12,263  13,229  (966) (7.3) % 25,440  26,419  (979) (3.7) %
Midwest 23,760  23,625  135  0.6  % 47,356  47,546  (190) (0.4) %
New York 6,632  6,685  (53) (0.8) % 12,913  12,764  149  1.2  %
ERCOT
2,515  1,775  740  41.7  % 5,044  3,978  1,066  26.8  %
Total Nuclear Generation 45,170  45,314  (144) (0.3) % 90,753  90,707  46  0.1  %

Natural Gas, Oil, and Renewables
Mid-Atlantic 810  612  198  32.4  % 1,442  1,480  (38) (2.6) %
Midwest 258  284  (26) (9.2) % 643  623  20  3.2  %

ERCOT
3,206  3,592  (386) (10.7) % 6,290  7,107  (817) (11.5) %
Other Power Regions 1,286  1,617  (331) (20.5) % 3,090  5,168  (2,078) (40.2) %
Total Natural Gas, Oil, and Renewables 5,560  6,105  (545) (8.9) % 11,465  14,378  (2,913) (20.3) %

Purchased Power
Mid-Atlantic
3,750  3,316  434  13.1  % 8,544  6,685  1,859  27.8  %
Midwest 475  225  250  111.1  % 963  533  430  80.7  %

ERCOT 837  1,060  (223) (21.0) % 1,495  1,725  (230) (13.3) %
Other Power Regions 9,849  9,643  206  2.1  % 20,844  20,042  802  4.0  %
Total Purchased Power 14,911  14,244  667  4.7  % 31,846  28,985  2,861  9.9  %

Total Supply/Sales by Region
Mid-Atlantic 16,823  17,157  (334) (1.9) % 35,426  34,584  842  2.4  %
Midwest 24,493  24,134  359  1.5  % 48,962  48,702  260  0.5  %
New York 6,632  6,685  (53) (0.8) % 12,913  12,764  149  1.2  %
ERCOT
6,558  6,427  131  2.0  % 12,829  12,810  19  0.1  %
Other Power Regions 11,135  11,260  (125) (1.1) % 23,934  25,210  (1,276) (5.1) %
Total Supply/Sales by Region 65,641  65,663  (22) —  % 134,064  134,070  (6) —  %
__________
(a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.
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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

Three Months Ended 
 June 30, Six Months Ended 
 June 30,
2025 2024 2025 2024
Nuclear fleet capacity factor 94.8  % 95.4  % 94.5  % 94.4  %
Refueling outage days 41  49  129  127 
Non-refueling outage days 22  3  22  13 

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 June 30, Six Months Ended June 30,
Location (Region) 2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
PJM West (Mid-Atlantic) $ 42.43  $ 30.80  $ 11.63  37.8  % $ 48.06  $ 31.62  $ 16.44  52.0  %
ComEd (Midwest) 31.09  22.41  8.68  38.7  % 33.20  24.24  8.96  37.0  %
Central (New York) 37.40  27.22  10.18  37.4  % 56.36  31.05  25.31  81.5  %
North (ERCOT) 32.75  30.90  1.85  6.0  % 32.07  28.31  3.76  13.3  %
Southeast Massachusetts (Other) (a)
40.31  29.46  10.85  36.8  % 72.53  36.82  35.71  97.0  %

__________
(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 six months ended June 30, 2025 and 2024.

Three Months Ended June 30, Six Months Ended June 30,
Location (Region) 2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic) $ 125.71  $ 50.86  $ 74.85  147.2  % $ 89.65  $ 50.18  $ 39.47  78.7  %
ComEd (Midwest) 109.25  32.39  76.86  237.3  % 69.09  33.26  35.83  107.7  %
Rest of State (New York) 132.89  98.33  34.56  35.1  % 109.61  102.42  7.19  7.0  %
Southeast New England (Other) 662.37  360.97  301.40  83.5  % 805.97  213.82  592.15  276.9  %

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 six months ended June 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 June 30, Six Months Ended June 30,
State (Region) (a)
2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
New Jersey (Mid-Atlantic) (b)
$ 10.00  $ 9.97  $ 0.03  0.3  % $ 10.00  $ 9.96  $ 0.04  0.4  %
Illinois (Midwest )
6.64  3.33  3.31  99.4  % 8.01  1.81  6.20  342.5  %
New York (New York) 14.76  18.27  (3.51) (19.2) % 16.52  18.27  (1.75) (9.6) %

__________
(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. The ZEC price is expected to be approximately $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update in August 2024, the ZEC price for the delivery period beginning June 2023 through May 2024 was calculated to be $9.95/MWh.

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 ($0.42) and $10.10 for the three months ended June 30, 2025 and 2024, respectively, and ($1.23) and $8.83 for the six months ended June 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.
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Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively. We evaluated and expect to meet the annual prevailing wage requirements at all of our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.
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 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.
The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three and six months ended June 30, 2025 compared to 2024:

Three Months Ended June 30, Six Months Ended June 30,
2025 2024 $ Change
% Change 2025 2024 $ Change
% Change
Nuclear PTC revenue (a)
$ 45  $ 408  $ (363) (89) % $ 45  $ 712  $ (667) (93.7) %
State-sponsored programs net revenue (b)
75  51  24  47  % 190  120  70  58.3  %

__________
(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 5 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.
For the three and six months ended June 30, 2025 compared to 2024, changes in Operating revenues by region were approximately as follows:

Three Months Ended 
 June 30 Six Months Ended 
 June 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Mid-Atlantic $ 144  11.0  % • favorable realized economic hedges of $100 due to settled prices relative to hedged prices
• favorable retail load revenue of $110 primarily due to higher contracted energy prices; partially offset by
• absence of nuclear PTC revenue of ($95) in the current year
$ 567  22.3  % • favorable realized economic hedges of $360 due to settled prices relative to hedged prices
• favorable retail load revenue of $265 primarily due to higher contracted energy prices and load volumes
• favorable wholesale load revenue of $120 primarily due to higher contracted energy prices and load volumes; partially offset by
• absence of nuclear PTC revenue of ($180) in the current year

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Three Months Ended 
 June 30 Six Months Ended 
 June 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Midwest 356  30.5  % • favorable ZEC revenue of $175 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years
• favorable net generation and wholesale load revenue of $170 primarily due to higher load volumes and contracted energy prices
• favorable realized economic hedges of $165 due to settled prices relative to hedged prices
• favorable retail load revenue of $75 primarily due to higher contracted energy prices and load volumes; partially offset by
• lower nuclear PTC revenue of ($230) in the current year
666  29.4  % • favorable net generation and wholesale load revenue of $385 primarily due to higher load volumes and contracted energy prices
• favorable realized economic hedges of $365 due to settled prices relative to hedged prices
• favorable ZEC revenue of $220 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years and increase in ZEC price
• favorable retail load revenue of $125 primarily due to higher contracted energy prices and load volumes; partially offset by
• lower nuclear PTC revenue of ($425) in the current year

New York 21  4.1  % • No individually significant drivers
70  6.8  % • favorable net generation revenue of $115 primarily due to higher energy prices
• favorable retail load revenue of $75 primarily due to higher contracted energy prices; partially offset by
• unfavorable realized economic hedges of ($100) due to settled prices relative to hedged prices
• absence of nuclear PTC revenue of ($65) in the current year

ERCOT 107  30.0  % • favorable realized economic hedges of $60 due to settled prices relative to hedged prices
184  27.1  % • favorable realized economic hedges of $70 due to settled prices relative to hedged prices
• favorable wholesale load revenue of $50 primarily due to higher contracted energy prices
• favorable retail load revenue of $50 primarily due to higher contracted energy prices

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Three Months Ended 
 June 30 Six Months Ended 
 June 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Other Power Regions (6) (0.5) % • No individually significant drivers
(74) (2.6) % • unfavorable net wholesale load revenue of ($140) primarily due to lower contracted prices; partially offset by
• favorable retail load revenue of $55 primarily due to higher contracted energy prices

Other 110  14.6  % • favorable gas revenue of $100 primarily due to higher gas prices
294  14.3  % • favorable gas revenue of $240 primarily due to higher gas prices
• favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $85 primarily due to higher energy prices

Mark-to-market (b)
(106) • gains on economic hedging activities of $86 in 2025 compared to gains of $192 in 2024
(455) • losses on economic hedging activities of ($201) in 2025 compared to gains of $254 in 2024

Total $ 626  11.4  % $ 1,252  10.8  %

__________
(a) % Change in mark-to-market is not a meaningful measure.
(b) See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by 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 six months ended June 30, 2025 compared to 2024, Purchased power and fuel expense were as follows:

Three Months Ended June 30, Six Months Ended June 30,
2025 2024 $ Change
% Change (a)
2025 2024 $ Change
% Change (a)

Mid-Atlantic $ 666  $ 544  $ 122  22.4  % $ 1,522  $ 1,111  $ 411  37.0  %
Midwest 488  403  85  21.1  % 1,042  794  248  31.2  %
New York 138  141  (3) (2.1) % 299  310  (11) (3.5) %
ERCOT 193  143  50  35.0  % 377  254  123  48.4  %
Other Power Regions 997  891  106  11.9  % 2,359  2,148  211  9.8  %
Total electric purchased power and fuel 2,482  2,122  360  17.0  % 5,599  4,617  982  21.3  %
Other 731  567  164  28.9  % 1,963  1,613  350  21.7  %
Mark-to-market losses (gains) (81) (397) 316  (46) (521) 475 
Total Purchased power and fuel $ 3,132  $ 2,292  $ 840  36.6  % $ 7,516  $ 5,709  $ 1,807  31.7  %

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

Three Months Ended 
 June 30 Six Months Ended 
 June 30
$ Change
% Change (a)
Description
$ Change
% Change (a)
Description

Mid-Atlantic $ 122  22.4  % • unfavorable cost of ($110) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices and lower generation volumes
$ 411  37.0  % • unfavorable cost of ($360) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices and increased load served

Midwest 85  21.1  % • unfavorable cost of ($70) associated with purchased power to supply load relative to generation volumes primarily driven by higher net transmission costs
248  31.2  % • unfavorable cost of ($225) associated with purchased power to supply load relative to generation volumes primarily driven by higher net transmission costs

New York (3) (2.1) % • No individually significant drivers
(11) (3.5) % • No individually significant drivers

ERCOT 50  35.0  % • No individually significant drivers
123  48.4  % • unfavorable cost of ($100) associated with purchased power to supply load relative to generation volumes primarily due to higher energy prices

Other Power Regions 106  11.9  % • unfavorable purchased power of ($220) primarily due to higher energy prices; partially offset by
• favorable realized economic hedges of $110 due to settled prices relative to hedged prices
211  9.8  % • unfavorable purchased power of ($840) 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 $665 due to settled prices relative to hedged prices

Other 164  28.9  % • unfavorable net gas purchases, inclusive of realized economic hedges, of ($115) primarily due to higher gas prices
350  21.7  % • unfavorable net gas purchases, inclusive of realized economic hedges, of ($200) primarily due to higher gas prices
• unfavorable purchases in the United Kingdom, inclusive of realized economic hedges, of ($95) primarily due to higher energy prices
• unfavorable fair value adjustments related to gas imbalances of ($50)

Mark-to-market (b)
316  • gains on economic hedging activities of $81 in 2025 compared to gains of $397 in 2024
475  • gains on economic hedging activities of $46 in 2025 compared to gains of $521 in 2024

Total $ 840  36.6  % $ 1,807  31.7  %

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__________
(a) % Change in mark-to-market is not a meaningful measure.
(b) See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.
Other, net was favorable for the three and six months ended June 30, 2025 compared to the same period in 2024, due to activity described in the table below:

Income (Deductions)

Three Months Ended June 30, Six Months Ended June 30,
2025 2024 2025 2024
Decommissioning-related activities (a)
$ 437  $ 51  $ 531  $ 347 

Net realized and unrealized gains (losses) from equity investments (b)
(7) (58) (275) (11)

Other
10  13  30  32 
Other, net $ 440  $ 6  $ 286  $ 368 

__________
(a) Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 7 — Nuclear Decommissioning and Note 16 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.
(b) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Investments on the Consolidated Balance Sheets based on quoted market price of the stock.

Effective income tax rates were 34.6% and 16.0% for the three months ended June 30, 2025 and 2024, respectively and 32.4% and 15.8% for the six months ended June 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 8 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Liquidity and Capital Resources
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. 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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
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Cash Flow Activities
The following table summarizes our cash flow activities for the six months ended June 30, 2025 and 2024, respectively:

Six Months Ended June 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 1,584  (1,336) 2,920 
Investing activities (1,758) 2,650  (4,408)
Financing activities (893) (1,385) 492 
Net increase (decrease) in cash, restricted cash, and cash equivalents
(1,067) (71) (996)

Cash, restricted cash, and cash equivalents at end of period
$ 2,062  $ 383  $ 1,679 

Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities was $1,584 million for the six months ended June 30, 2025, compared to cash used in operating activities of ($1,336) million for the six months ended June 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 6 — Accounts Receivable and Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Net Cash Provided By (Used In) Investing Activities
Cash used in investing activities was ($1,758) million for the six months ended June 30, 2025, compared to cash provided by investing activities of $2,650 million for the six months ended June 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 6 — 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 ($893) million for the six months ended June 30, 2025, compared to cash used in financing activities of ($1,385) million for the six months ended June 30, 2024. The change primarily relates to repurchases of common stock during each period. The remaining change relates primarily to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. See Note 11 — Debt and Credit Agreements and Note 14 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
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Quarterly dividends declared by our Board of Directors during the six months ended June 30, 2025 and for the third 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 

Credit Matters and Cash Requirements
We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of June 30, 2025, we have access to facilities with aggregate bank commitments of $9.5 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during the second 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.
Security Ratings
Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of June 30, 2025 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of June 30, 2025, we had $7.2 billion of available capacity under our credit facilities and $2.0 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 June 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 10 — Derivative Financial Instruments and Note 11 — 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
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$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 11 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
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 11 — 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 7 — Nuclear Decommissioning of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.
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As of June 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 June 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.
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 5 — 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 for our entire economic hedge portfolio associated with a $5/MWh reduction in the annual average around-the-clock energy price based on June 30, 2025 market conditions and hedged position results in an impact to earnings that is not material for 2025 and 2026, respectively, largely due to the nuclear PTC. See Note 10 — 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
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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.
Trading and Non-Trading Marketing Activities
The following table provides detail on changes in our commodity mark-to-market net assets (liabilities) balance sheet position from December 31, 2024 to June 30, 2025. This table incorporates the mark-to-market activities that are immediately recorded in earnings. This table excludes all NPNS contracts. See Note 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on the balance sheet classification of the mark-to-market commodity contract net assets (liabilities) recorded as of June 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
(39)
Reclassification to realized at settlement of contracts recorded in results of operations (119)

Changes in allocated collateral 261 
Net option premium paid (received)
(18)
Option premium amortization 23 
Upfront payments and amortizations (b) 
(1)

Balance as of June 30, 2025 (a)
$ 424 

__________
(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.
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Fair Values
The following table presents maturity and source of fair value for mark-to-market commodity contract net assets (liabilities). See Note 12 — 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) $ 12  $ 86  $ 40  $ (11) $ (4) $ 1  $ 124 
Prices provided by external sources (Level 2) 6  72  69  9  7  —  163 
Prices based on model or other valuation methods (Level 3) 358  (167) (39) (11) (16) 12  137 
Total $ 376  $ (9) $ 70  $ (13) $ (13) $ 13  $ 424 

__________
(a) Represents mark-to-market 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 $847 million at June 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for a detailed discussion of credit risk.
Credit-Risk-Related Contingent Features
As part of the normal course of business, we routinely enter into physically or financially settled contracts for the purchase and sale of capacity, electricity, fuels, emissions allowances, and other energy-related products. In accordance with the contracts and applicable law, if we are downgraded by a credit rating agency, especially if such downgrade is to a level below investment grade, it is possible that a counterparty would attempt to rely on such a downgrade as a basis for making a demand for adequate assurance of future performance. Depending on our net position with a counterparty, the demand could be for the posting of collateral. In the absence of expressly agreed-to provisions that specify the collateral that must be provided, collateral requested will be a function of the facts and circumstances of the situation at the time of the demand. See Note 10 — Derivative Financial Instruments and Note 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information regarding the letters of credit supporting the cash collateral.
We sell output through bilateral contracts. The bilateral contracts are subject to credit risk, which relates to the ability of counterparties to meet their contractual payment obligations. Any failure to collect these payments from counterparties could have a material impact on our consolidated financial statements. As market prices rise above or fall below contracted price levels, we are required to post collateral with purchasers; as market prices fall below contracted price levels, counterparties are required to post collateral with us. To post collateral, we depend on access to bank credit facilities, which serve as liquidity sources to fund collateral requirements. See ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Liquidity and Capital Resources — Credit Matters and Cash Requirements — Credit Facilities for additional information.
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RTOs and ISOs
We participate in all of the established wholesale energy markets that are administered by PJM, ISO-NE, NYISO, CAISO, MISO, SPP, AESO, 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 six months ended June 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 10 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Equity Price Risk
We maintain trust funds, as required by the NRC, to fund the costs of decommissioning our nuclear plants. Our NDT funds are reflected at fair value in the Consolidated Balance Sheets. The mix of securities in the trust funds is designed to provide returns to be used to fund decommissioning and to compensate us for inflationary increases in decommissioning costs; however, the equity securities in the trust funds are exposed to price fluctuations in equity markets, and the value of fixed-rate, fixed-income securities are exposed to changes in interest rates. We actively monitor the investment performance of the trust funds and periodically review asset allocations in accordance with our NDT fund investment policy.
A hypothetical 25 basis points increase in interest rates and 10% decrease in equity prices would have resulted in a $981 million reduction in the fair value of our NDT trust assets as of June 30, 2025. This calculation holds all other variables constant and assumes only the discussed changes in interest rates and equity prices. See Note 7 — 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.
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ITEM 4. CONTROLS AND PROCEDURES

Disclosure Controls and Procedures
During the second 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 June 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 second 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 13 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements in PART I, ITEM 1. FINANCIAL STATEMENTS of this report. Such descriptions are incorporated herein by these references.

ITEM 1A. RISK FACTORS

At June 30, 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. During the second quarter of 2025, one agreement expired unexercised. The remaining agreement expires in August 2025. See Note 14 — 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 six months ended June 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. The remaining shares will be delivered upon completion of the transaction in the third quarter of 2025 and will be based on the average of the daily-volume weighted average price of our common stock during the term, less a discount.    
The following table provides information regarding our share repurchases under the program during the three months ended June 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)

April 1, 2025 to April 30, 2025
—  $ —  $ 841 
May 1, 2025 to May 31, 2025 (b)
—  —  944 
June 1, 2025 to June 30, 2025 (c)
1,099,580  —  540 
Total
1,099,580  $ —  $ 540 

__________
(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 following expiration of capped call option. See Note 14 — Shareholders' Equity for additional information.
(c) Represents shares delivered under the ASR agreement. The total number of shares delivered and the average price per share under the ASR agreement will be determined at the end of the ASR period which is expected to occur in the third quarter of 2025.
(d) Approximate dollar value of shares that may yet be purchased under the program includes taxes and commissions.
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ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.

ITEM 5. OTHER INFORMATION
Rule 10b5-1 Trading Plans
During the three months ended June 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).

ITEM 6. EXHIBITS

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

August 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)

August 7, 2025
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