Constellation Energy Corporation

11/07/2025 | Press release | Distributed by Public on 11/07/2025 10:50

Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

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
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
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.
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
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.
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:
•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.
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.
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.
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.
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 revenuesby 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
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
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.
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 fuelexpense 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
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.
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.
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.
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.
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.
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