Constellation Energy Corporation
11/09/2026 | Press release | Distributed by Public on 11/09/2026 12:59
Quarterly Report for Quarter Ending September 30, 2026 (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
Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation's largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation's clean energy and delivering the around-the-clock reliability needed to power America's growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future.
Significant Transactions and Developments
Acquisition of Calpine Corporation
On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.
This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation's leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.
In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments. Completion of the transaction is subject to customary closing conditions and receipt of applicable regulatory approvals, and is expected to close by the end of this year.
In October 2026, we completed the divestiture of the Brazos Valley Energy Center (f/k/a Jack A. Fusco Energy Center), a 606 MW natural gas-fired plant in ERCOT, to LS Power for $860 million before closing adjustments.
See Note 2 - Mergers, Acquisitions, and Dispositions and Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
New Data Center Facility at Freestone Energy Center
In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. We have also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas.
Pastoria Solar Project
In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired Pastoria facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, an 80 MW/320 MWh Battery Energy Storage System, which came online in July 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company.
Pin Oak Creek Energy Center
In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460 MW, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas' continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state's economic momentum.
Long-term Nuclear PPAs
In the second quarter of 2026, we signed long-term PPAs with a diverse group of investment-grade customers covering 920 MW of clean, reliable nuclear generation, primarily from our existing fleet. The agreements have terms of 15 to 20 years and are expected to commence between 2029 and 2032. This total includes a 176 MW PPA with Walmart that will support a 30 MW capacity expansion at our Dresden Clean Energy Center in Illinois, as well as additional investments in the facility, its workforce, and the local community.
In September 2026, we announced a 20-year, 690 MW PPA with Amazon and a related retail supply agreement supporting Amazon's operations in PJM. The agreements will enable more than $3 billion of investment in our Calvert Cliffs Clean Energy Center, including facility improvements and a 190 MW capacity expansion expected to come online between 2030 and 2032, while supporting the facility's continued operation and future relicensing.
In October 2026, we announced a 20-year PPA with Google that will enable more than $4.3 billion of investment across 11 of our nuclear units in Illinois, Pennsylvania, and New Jersey to add approximately 890 MW of incremental generation capacity to the PJM grid, with the first uprate expected in 2028. We also entered into a 15-year financial energy load following agreement with Google for 2,700 MW in PJM.
These agreements reflect continued demand from large-load customers for reliable, clean energy. Realization of the anticipated investments and capacity expansions remains subject to regulatory approvals, successful completion of the planned uprates, continued operation and relicensing of the applicable facilities, and other conditions.
Agreement to Acquire Rhode Island State Energy Center
In September 2026, we entered into an agreement to acquire all of the equity interests in RISEC Holdings, LLC, the owner of the Rhode Island State Energy Center, from Shell Energy North America (US), L.P. for $715 million, subject to customary purchase price adjustments. The Rhode Island State Energy Center is a natural gas-fired combined-cycle electric generation facility with a generating capacity of 609 MW. The facility sells electricity and capacity into the competitive ISO New England wholesale power market and is expected to become part of our merchant generation portfolio. Completion of the transaction is subject to receipt of required regulatory approvals and other customary closing conditions.
Conditional DOE Loan Commitment Supporting Nuclear Uprates
In October 2026, we signed a conditional loan commitment with the DOE Office of Energy Dominance Financing. Subject to the execution of a loan agreement, the DOE would issue a guarantee for up to $5.0 billion for an unsecured loan from the Federal Financing Bank to support uprates at various nuclear facilities. The loan would have a 30-year term. Interest rates would be fixed upon each advance at a spread of 0.375% above U.S. Treasuries of comparable maturity.
Other Key Business Drivers
PJM Market Reform
In January 2026, the National Energy Dominance Council, supported by governors in the PJM territory, urged PJM to propose certain tariff revisions with respect to its capacity auction. PJM subsequently initiated stakeholder discussions regarding potential market reforms, including a reliability backstop auction mechanism, enhancements to large load forecasting and measures to accelerate generator interconnection studies. In February 2026, PJM proposed extending the existing RPM capacity market price collar-approximately $325/MW-day and $175/MW-day-for the 2028/2029 and 2029/2030 Base Residual Auctions. FERC accepted the extension in April 2026, citing reliability concerns, significant demand growth, including from data centers, and anticipated market reforms.
In July 2026, PJM proposed a one-time reliability backstop procurement. In September 2026, FERC accepted the proposal and suspended it to become effective February 28, 2027, subject to refund and subject to the outcome of a paper hearing. FERC also encouraged PJM to re-file an updated proposal within 30 days rather than proceeding with the paper hearing. PJM submitted an updated auction filing on October 29, 2026 and proposed that the one-time procurement open March 1, 2027 and close on March 28, 2027, with results announced on May 10, 2027. Many of the proposed auction parameters are the same, with the exception that the load forecast that is used to clear the auction will not be finalized until April 28, 2027. Separately, in August 2026, PJM filed its Interim Resource Adequacy Service proposal, which would have imposed curtailment risk on new large loads over 50 MW coming online after June 1, 2027 that did not contract for new capacity. FERC largely rejected the proposal, finding that it improperly intruded on state jurisdiction over retail rates and that PJM had not established the lawfulness of certain provisions. PJM has indicated that they will make a subsequent filing, but no details are available at this time.
FERC Issues Order in PJM Show Cause Proceeding
In December 2025, FERC issued an order finding the existing PJM Tariff to be unjust and unreasonable and directing PJM to take a number of actions. FERC ordered three new transmission services: an interim interruptible network integration transmission service (IT NITS), which will allow load to take service on an interruptible basis while waiting for the network upgrades required for traditional NITS, and two other services. The IT NITS service allows the load to elect to connect promptly and receive some service from the grid, while avoiding PJM purchases of capacity to serve it, as it will be interruptible. The other services include a firm and non-firm contract demand service for co-located load. FERC also directed several PJM compliance filings and a paper hearing.
In June 2026, FERC ruled on a number of issues presented in the co-location paper hearing and on several PJM compliance filings implementing directives from the December 2025 order. Importantly, FERC pressed PJM to implement changes to accommodate co-located load prior to PJM's proposed June 2029 effective date. In August 2026, PJM submitted its compliance filing and we are awaiting a FERC order on the filing.
FERC also issued a series of orders in the various RTOs in response to the Advance Notice of Proposed Rulemaking (ANOPR) published by DOE last fall. The orders direct filings by RTOs and their transmission owners that are designed to expedite service to large load (regardless of whether it is co-located) and avoid the expense and delay associated with network upgrades to provide service to these loads. Constellation's Load Dependent Capacity at Existing Plants (LCEP) proposal, which would expedite connection of new generation when paired with a large load at an existing plant, was flagged in several RTO orders as a proposal to be considered.
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, in 2026, the DOE began the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. The
Lindsay O. Graham Sanctioning Russia and Iran Act of 2026 (Graham Act) that continued the uranium import waivers but appeared to increase difficulties for shipping fuel from Russia was signed in September 2026. In October 2026, the President issued an Executive Order that waived the application of all the sanctions, restrictions, and tariffs in the Graham Act. 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
California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state's Cap-and-Trade Program through January 1, 2046, and renaming it the "Cap and Invest" Program.
In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions, such as a determination by PJM that the unit is needed for reliability. PJM made such a finding with respect to our natural gas generation facility, Zion Energy Center, acquired as part of Calpine, and accordingly Zion plans to operate past January 2030.
Regulation of GHGs from Power Plants under the Clean Air Act. In February 2026, EPA issued a final rule to repeal the 2009 Endangerment Finding underpinning all GHG regulation by EPA. In September 2026, EPA issued a final rule to repeal its 2024 GHG power plant standards, except for efficiency-based standards that apply to new gas power plants. With the repeal, new baseload gas plants will no longer face compliance obligations based on carbon capture and sequestration/storage beginning in 2032. Both the February 2026 and September 2026 rules have been challenged in the D.C. Circuit. EPA also issued a supplemental proposal in September 2026 to repeal its full suite of power plant GHG regulations, including the efficiency-based standards for new gas power plants, based on its reinterpretation of section 111 of the Clean Air Act. EPA recently accepted comments on the proposal. EPA's approach in the supplemental proposal, if finalized and upheld in court, would limit and/or delay options for future action on climate for the power sector by EPA.
See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to.
Critical Accounting Policies and Estimates
Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At September 30, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF
FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.
Financial Results of Operations
GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three and nine months ended September 30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and nine months ended September 30, 2026 and 2025, see the discussion of Results of Operations below.
| Three Months Ended September 30, |
$ Change
|
Nine Months Ended September 30, |
$ Change
|
||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||||||||||||
|
GAAP Net Income (Loss) Attributable to Common Shareholders
|
$ | 1,835 | $ | 930 | $ | 905 | $ | 3,938 | $ | 1,887 | $ | 2,051 | |||||||||||||||||||||||
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, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.4% and 25.6% for the three and nine months ended September 30, 2026 and 2025, 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, 2026 compared to the same period in 2025.
| Three Months Ended September 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| (In millions, except per share data) |
Earnings Per Share(a)
|
Earnings Per Share(a)
|
|||||||||||||||||||||
| GAAP Net Income (Loss) Attributable to Common Shareholders | $ | 1,835 | $ | 5.19 | $ | 930 | $ | 2.97 | |||||||||||||||
|
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $44 and $32, respectively)(b)
|
(127) | (0.36) | 94 | 0.30 | |||||||||||||||||||
|
Decommissioning-Related Activities (net of taxes of $23 and $187, respectively)(c)
|
56 | 0.16 | (117) | (0.37) | |||||||||||||||||||
|
Amortization of Acquired Commodity Contracts (net of taxes of $13 and $-, respectively)(d)
|
39 | 0.11 | - | - | |||||||||||||||||||
|
Calpine Merger and Integration Costs (net of taxes of $30 and $10, respectively)(e)
|
73 | 0.20 | 28 | 0.09 | |||||||||||||||||||
|
Plant Retirements and Divestitures (net of taxes of $3 and $2, respectively)
|
(9) | (0.03) | (5) | (0.02) | |||||||||||||||||||
|
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $8 and $3, respectively)
|
25 | 0.07 | 9 | 0.03 | |||||||||||||||||||
|
Change in Legal and Environmental Liabilities (net of taxes of $3 and $-, respectively)
|
9 | 0.02 | 1 | - | |||||||||||||||||||
|
Income Tax-Related Adjustments(f)
|
(108) | (0.30) | 13 | 0.04 | |||||||||||||||||||
|
Noncontrolling Interests(g)
|
(1) | - | (1) | - | |||||||||||||||||||
| Adjusted (non-GAAP) Operating Earnings | $ | 1,792 | $ | 5.06 | $ | 952 | $ | 3.04 | |||||||||||||||
| Nine Months Ended September 30, | |||||||||||||||||||||||
| 2026 | 2025 | ||||||||||||||||||||||
| (In millions, except per share data) |
Earnings Per Share(a)
|
Earnings Per Share(a)
|
|||||||||||||||||||||
| GAAP Net Income (Loss) Attributable to Common Shareholders | $ | 3,938 | $ | 11.06 | $ | 1,887 | $ | 6.02 | |||||||||||||||
|
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $175 and $163, respectively)(b)
|
(508) | (1.43) | 478 | 1.52 | |||||||||||||||||||
|
Decommissioning-Related Activities (net of taxes of $354 and $426, respectively)(c)
|
(339) | (0.95) | (242) | (0.77) | |||||||||||||||||||
|
Amortization of Acquired Commodity Contracts (net of taxes of $117 and $-, respectively)(d)
|
342 | 0.96 | - | - | |||||||||||||||||||
|
Calpine Merger and Integration Costs (net of taxes of $69 and $17, respectively)(e)
|
276 | 0.77 | 50 | 0.16 | |||||||||||||||||||
|
Plant Retirements and Divestitures (net of taxes of $3 and $4, respectively)
|
(9) | (0.03) | 13 | 0.04 | |||||||||||||||||||
|
Pension & OPEB Non-Service (Credits) Costs (net of taxes of $22 and $9, respectively)
|
65 | 0.18 | 27 | 0.09 | |||||||||||||||||||
|
Change in Legal and Environmental Liabilities (net of taxes of $15 and $1, respectively)
|
44 | 0.12 | 2 | 0.01 | |||||||||||||||||||
|
Income Tax-Related Adjustments(f)
|
(121) | (0.34) | 13 | 0.04 | |||||||||||||||||||
|
Noncontrolling Interests(g)
|
(4) | (0.01) | (4) | (0.01) | |||||||||||||||||||
| Adjusted (non-GAAP) Operating Earnings | $ | 3,684 | $ | 10.34 | $ | 2,224 | $ | 7.09 | |||||||||||||||
(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 354 million and 313 million for the three months ended September 30, 2026 and 2025, respectively, and 356 million and 314 million for the nine months ended September 30, 2026 and 2025, respectively.
(b)Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.
(c)Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts.
(d)In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition.
(e)Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible.
(f)Adjustment to deferred income taxes due to changes in forecasted apportionment.
(g)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
|
||||||||||||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||||||||||||||
| Operating revenues | $ | 9,550 | $ | 6,570 | $ | 2,980 | $ | 28,176 | $ | 19,459 | $ | 8,717 | |||||||||||||||||||||||
| Operating expenses | |||||||||||||||||||||||||||||||||||
| Purchased power and fuel | 4,400 | 3,567 | 833 | 14,775 | 11,083 | 3,692 | |||||||||||||||||||||||||||||
| Operating and maintenance | 1,991 | 1,511 | 480 | 6,024 | 4,673 | 1,351 | |||||||||||||||||||||||||||||
| Depreciation and amortization | 454 | 241 | 213 | 1,340 | 743 | 597 | |||||||||||||||||||||||||||||
| Taxes other than income taxes | 225 | 165 | 60 | 661 | 472 | 189 | |||||||||||||||||||||||||||||
| Total operating expenses | 7,070 | 5,484 | 1,586 | 22,800 | 16,971 | 5,829 | |||||||||||||||||||||||||||||
|
Gain (loss) on sales of assets
|
12 | - | 12 | 28 | - | 28 | |||||||||||||||||||||||||||||
|
Operating income (loss)
|
2,492 | 1,086 | 1,406 | 5,404 | 2,488 | 2,916 | |||||||||||||||||||||||||||||
| Other income and (deductions) | |||||||||||||||||||||||||||||||||||
| Interest expense, net | (217) | (134) | (83) | (753) | (398) | (355) | |||||||||||||||||||||||||||||
| Other, net | (44) | 443 | (487) | 605 | 729 | (124) | |||||||||||||||||||||||||||||
| Total other income and (deductions) | (261) | 309 | (570) | (148) | 331 | (479) | |||||||||||||||||||||||||||||
|
Income (loss) before income taxes
|
2,231 | 1,395 | 836 | 5,256 | 2,819 | 2,437 | |||||||||||||||||||||||||||||
|
Income tax (benefit) expense
|
405 | 466 | (61) | 1,333 | 928 | 405 | |||||||||||||||||||||||||||||
|
Equity in income (losses) of unconsolidated affiliates
|
9 | - | 9 | 23 | - | 23 | |||||||||||||||||||||||||||||
|
Net income (loss)
|
1,835 | 929 | 906 | 3,946 | 1,891 | 2,055 | |||||||||||||||||||||||||||||
|
Net income (loss) attributable to noncontrolling interests
|
- | (1) | 1 | 8 | 4 | 4 | |||||||||||||||||||||||||||||
|
Net income (loss) attributable to common shareholders
|
$ | 1,835 | $ | 930 | $ | 905 | $ | 3,938 | $ | 1,887 | $ | 2,051 | |||||||||||||||||||||||
Three Months Ended September 30, 2026 Compared to Three Months Ended September 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $905 million primarily due to:
•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 - Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information; and
•Favorable net adjustments to deferred income taxes due to changes in forecasted apportionment.
The favorable items were partially offset by:
•Unfavorable decommissioning-related activities; and
•Lower Nuclear PTC revenues in 2026. See Note 6 - Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.
Nine Months Ended September 30, 2026 Compared to Nine Months Ended September 30, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $2,051 million primarily due to:
•Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 - Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information;
•Favorable net market and portfolio conditions primarily driven by higher capacity revenues;
•Lower net unrealized loss on equity investments;
•Favorable net adjustments to deferred income taxes due to changes in forecasted apportionment; and
•Favorable decommissioning-related activities primarily driven by the 2026 nuclear ARO updates. See Note 9 - Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.
The favorable items were partially offset by:
•Unfavorable Calpine merger and integration costs;
•Unfavorable interest expense primarily driven by increased long-term debt outstanding; and
•Unfavorable impacts from nuclear outages.
Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 - Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments.
With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations, are reported under Other and not allocated to a segment.
For the three and nine months ended September 30, 2026 compared to 2025, Operating revenues were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | ||||||||||||||||||||||||||||||||||||||||
| Mid-Atlantic | $ | 1,877 | $ | 1,763 | $ | 114 | 6.5 | % | $ | 5,279 | $ | 4,876 | $ | 403 | 8.3 | % | |||||||||||||||||||||||||||||||
| Midwest | 1,562 | 1,390 | 172 | 12.4 | % | 4,862 | 4,317 | 545 | 12.6 | % | |||||||||||||||||||||||||||||||||||||
| New York | 569 | 558 | 11 | 2.0 | % | 1,702 | 1,655 | 47 | 2.8 | % | |||||||||||||||||||||||||||||||||||||
| ERCOT | 592 | 628 | (36) | (5.7) | % | 1,408 | 1,489 | (81) | (5.4) | % | |||||||||||||||||||||||||||||||||||||
| Other Power Regions | 1,099 | 1,543 | (444) | (28.8) | % | 3,551 | 4,277 | (726) | (17.0) | % | |||||||||||||||||||||||||||||||||||||
| Calpine | 3,384 | - | 3,384 | 100.0 | % | 7,926 | - | 7,926 | 100.0 | % | |||||||||||||||||||||||||||||||||||||
| Total reportable segment revenues | 9,083 | 5,882 | 3,201 | 54.4 | % | 24,728 | 16,614 | 8,114 | 48.8 | % | |||||||||||||||||||||||||||||||||||||
| Other | 829 | 844 | (15) | (1.8) | % | 2,815 | 3,201 | (386) | (12.1) | % | |||||||||||||||||||||||||||||||||||||
|
Unrealized gains (losses)(a)
|
(362) | (156) | (206) | (a) | 633 | (356) | 989 | (a) | |||||||||||||||||||||||||||||||||||||||
| Total Operating revenues | $ | 9,550 | $ | 6,570 | $ | 2,980 | 45.4 | % | $ | 28,176 | $ | 19,459 | $ | 8,717 | 44.8 | % | |||||||||||||||||||||||||||||||
__________
(a)% Change in unrealized gains (losses) is not a meaningful measure.
Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
|
(GWhs)
|
2026 | 2025 |
Change
|
% Change | 2026 | 2025 |
Change
|
% Change | |||||||||||||||||||||||||||||||||||||||
|
Nuclear Generation(a)
|
|||||||||||||||||||||||||||||||||||||||||||||||
| Mid-Atlantic | 13,659 | 13,665 | (6) | - | % | 39,661 | 39,105 | 556 | 1.4 | % | |||||||||||||||||||||||||||||||||||||
| Midwest | 24,333 | 23,644 | 689 | 2.9 | % | 70,420 | 71,000 | (580) | (0.8) | % | |||||||||||||||||||||||||||||||||||||
| New York | 6,177 | 6,671 | (494) | (7.4) | % | 18,528 | 19,585 | (1,057) | (5.4) | % | |||||||||||||||||||||||||||||||||||||
|
ERCOT
|
2,508 | 2,497 | 11 | 0.4 | % | 6,896 | 7,541 | (645) | (8.6) | % | |||||||||||||||||||||||||||||||||||||
| Total Nuclear Generation | 46,677 | 46,477 | 200 | 0.4 | % | 135,505 | 137,231 | (1,726) | (1.3) | % | |||||||||||||||||||||||||||||||||||||
|
Natural Gas, Oil, and Renewables(a)
|
|||||||||||||||||||||||||||||||||||||||||||||||
| Mid-Atlantic | 377 | 242 | 135 | 55.8 | % | 1,728 | 1,683 | 45 | 2.7 | % | |||||||||||||||||||||||||||||||||||||
| Midwest | 156 | 141 | 15 | 10.6 | % | 773 | 785 | (12) | (1.5) | % | |||||||||||||||||||||||||||||||||||||
|
ERCOT
|
4,626 | 4,325 | 301 | 7.0 | % | 11,106 | 10,615 | 491 | 4.6 | % | |||||||||||||||||||||||||||||||||||||
| Other Power Regions | 1,436 | 1,466 | (30) | (2.0) | % | 4,287 | 4,556 | (269) | (5.9) | % | |||||||||||||||||||||||||||||||||||||
|
Calpine
|
38,387 | - | 38,387 | 100.0 | % | 89,797 | - | 89,797 | 100.0 | % | |||||||||||||||||||||||||||||||||||||
| Total Natural Gas, Oil, and Renewables | 44,982 | 6,174 | 38,808 | 628.6 | % | 107,691 | 17,639 | 90,052 | 510.5 | % | |||||||||||||||||||||||||||||||||||||
| Purchased Power | |||||||||||||||||||||||||||||||||||||||||||||||
|
Mid-Atlantic
|
4,953 | 5,416 | (463) | (8.5) | % | 12,110 | 13,960 | (1,850) | (13.3) | % | |||||||||||||||||||||||||||||||||||||
| Midwest | 326 | 403 | (77) | (19.1) | % | 1,137 | 1,366 | (229) | (16.8) | % | |||||||||||||||||||||||||||||||||||||
| ERCOT | 673 | 714 | (41) | (5.7) | % | 1,999 | 2,209 | (210) | (9.5) | % | |||||||||||||||||||||||||||||||||||||
| Other Power Regions | 9,173 | 11,451 | (2,278) | (19.9) | % | 26,669 | 32,295 | (5,626) | (17.4) | % | |||||||||||||||||||||||||||||||||||||
|
Calpine
|
1,890 | - | 1,890 | 100.0 | % | 6,707 | - | 6,707 | 100.0 | % | |||||||||||||||||||||||||||||||||||||
| Total Purchased Power | 17,015 | 17,984 | (969) | (5.4) | % | 48,622 | 49,830 | (1,208) | (2.4) | % | |||||||||||||||||||||||||||||||||||||
| Total Supply/Sales by Segment | |||||||||||||||||||||||||||||||||||||||||||||||
| Mid-Atlantic | 18,989 | 19,323 | (334) | (1.7) | % | 53,499 | 54,748 | (1,249) | (2.3) | % | |||||||||||||||||||||||||||||||||||||
| Midwest | 24,815 | 24,188 | 627 | 2.6 | % | 72,330 | 73,151 | (821) | (1.1) | % | |||||||||||||||||||||||||||||||||||||
| New York | 6,177 | 6,671 | (494) | (7.4) | % | 18,528 | 19,585 | (1,057) | (5.4) | % | |||||||||||||||||||||||||||||||||||||
|
ERCOT
|
7,807 | 7,536 | 271 | 3.6 | % | 20,001 | 20,365 | (364) | (1.8) | % | |||||||||||||||||||||||||||||||||||||
| Other Power Regions | 10,609 | 12,917 | (2,308) | (17.9) | % | 30,956 | 36,851 | (5,895) | (16.0) | % | |||||||||||||||||||||||||||||||||||||
|
Calpine
|
40,277 | - | 40,277 | 100.0 | % | 96,504 | - | 96,504 | 100.0 | % | |||||||||||||||||||||||||||||||||||||
| Total Supply/Sales by Segment | 108,674 | 70,635 | 38,039 | 53.9 | % | 291,818 | 204,700 | 87,118 | 42.6 | % | |||||||||||||||||||||||||||||||||||||
(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, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
| Nuclear fleet capacity factor | 97.2 | % | 96.8 | % | 94.2 | % | 95.3 | % | |||||||||||||||
| Refueling outage days | 20 | 23 | 205 | 152 | |||||||||||||||||||
| Non-refueling outage days | 6 | 5 | 26 | 27 | |||||||||||||||||||
Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider EFOF to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three and nine months ended September 30, 2026 was 5.9%. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.
Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
|
ISO/RTO
|
2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | |||||||||||||||||||||||||||||||||||||||
|
PJM - PJM West
|
$ | 69.97 | $ | 46.77 | $ | 23.20 | 49.6 | % | $ | 72.84 | $ | 47.63 | $ | 25.21 | 52.9 | % | |||||||||||||||||||||||||||||||
|
PJM - ComEd
|
51.44 | 42.72 | 8.72 | 20.4 | % | 43.82 | 36.37 | 7.45 | 20.5 | % | |||||||||||||||||||||||||||||||||||||
|
NYISO - Central
|
51.07 | 49.51 | 1.56 | 3.2 | % | 67.94 | 54.07 | 13.87 | 25.7 | % | |||||||||||||||||||||||||||||||||||||
|
ERCOT - North
|
34.41 | 35.05 | (0.64) | (1.8) | % | 34.88 | 33.06 | 1.82 | 5.5 | % | |||||||||||||||||||||||||||||||||||||
| ERCOT - Houston | 36.05 | 35.90 | 0.15 | 0.4 | % | 35.74 | 34.86 | 0.88 | 2.5 | % | |||||||||||||||||||||||||||||||||||||
|
ISO-NE - Southeast Massachusetts
|
54.05 | 50.43 | 3.62 | 7.2 | % | 73.68 | 65.16 | 8.52 | 13.1 | % | |||||||||||||||||||||||||||||||||||||
|
CAISO - NP15
|
43.18 | 41.35 | 1.83 | 4.4 | % | 29.82 | 36.31 | (6.49) | (17.9) | % | |||||||||||||||||||||||||||||||||||||
Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have
significant activity. Prices reflect the weighted average prices for the various auction periods within the three and nine months ended September 30, 2026 and 2025.
We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
|
ISO/RTO
|
2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | |||||||||||||||||||||||||||||||||||||||
|
PJM - Eastern Mid-Atlantic Area Council
|
$ | 329.17 | $ | 269.92 | $ | 59.25 | 22.0 | % | $ | 296.25 | $ | 149.74 | $ | 146.51 | 97.8 | % | |||||||||||||||||||||||||||||||
|
PJM - ComEd
|
329.17 | 269.92 | 59.25 | 22.0 | % | 296.25 | 136.03 | 160.22 | 117.8 | % | |||||||||||||||||||||||||||||||||||||
|
NYISO - Rest of State
|
162.67 | 193.33 | (30.66) | (15.9) | % | 156.89 | 137.52 | 19.37 | 14.1 | % | |||||||||||||||||||||||||||||||||||||
|
ISO-NE - Rest of Pool(a)
|
86.24 | 84.37 | 1.87 | 2.2 | % | 85.20 | 83.37 | 1.83 | 2.2 | % | |||||||||||||||||||||||||||||||||||||
__________
(a)We did not have significant activity at this zone for the three months ended September 30, 2025.
ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and nine months ended September 30, 2026 and 2025 and may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
|
State (Segment)(a)
|
2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | |||||||||||||||||||||||||||||||||||||||
|
New Jersey (Mid-Atlantic)(b)
|
$ | - | $ | - | $ | - | - | % | $ | - | $ | 10.00 | $ | (10.00) | (100.0) | % | |||||||||||||||||||||||||||||||
|
Illinois (Midwest)
|
1.02 | 1.17 | (0.15) | (12.8) | % | 1.10 | 5.73 | (4.63) | (80.8) | % | |||||||||||||||||||||||||||||||||||||
| New York (New York) | 14.76 | 14.76 | - | - | % | 14.76 | 15.93 | (1.17) | (7.3) | % | |||||||||||||||||||||||||||||||||||||
__________
(a)See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs.
(b)The New Jersey ZEC program concluded in May 2025.
Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025, $33.50 per MWh for the period June 2025 through May 2026, and $34.50 per MWh for the period June 2026 through May 2027. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($26.54) and ($17.11) for the three months ended September 30, 2026 and 2025, respectively, and ($19.54) and ($6.53) for the nine months ended September 30, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realized as a result of interaction with the nuclear PTC discussed below.
Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025 and 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.
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, 2026 compared to 2025:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | ||||||||||||||||||||||||||||||||||||||||
|
Nuclear PTC revenue(a)
|
$ | 44 | $ | 175 | $ | (131) | (74.9) | % | $ | 69 | $ | 220 | $ | (151) | (68.6) | % | |||||||||||||||||||||||||||||||
|
State-sponsored programs net revenue(b)
|
(280) | (220) | (60) | (27.3) | % | (555) | (30) | (525) | (1750.0) | % | |||||||||||||||||||||||||||||||||||||
__________
(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, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:
|
Three Months Ended September 30 |
|||||||||||||||||
| $ Change | % Change | Description | |||||||||||||||
| Mid-Atlantic | $ | 114 | 6.5 | % |
• favorable retail load revenue of $160 primarily due to higher contracted energy prices; partially offset by • unfavorable realized economic hedges of $70 due to settled prices relative to hedged prices |
||||||||||||
| Midwest | 172 | 12.4 | % |
• favorable net generation and wholesale load revenue of $175 primarily due to higher energy prices • favorable retail load revenue of $130 primarily due to higher contracted energy prices; partially offset by • unfavorable nuclear PTC revenue of $105 due to higher energy and capacity prices • unfavorable CMC program revenue of $55 primarily due to higher energy and capacity prices |
|||||||||||||
| New York | 11 | 2.0 | % | • no individually significant drivers | |||||||||||||
| ERCOT | (36) | (5.7) | % | • no individually significant drivers | |||||||||||||
| Other Power Regions | (444) | (28.8) | % |
• unfavorable retail load revenue of $185 primarily due to lower energy prices in the West and lower load volumes in New England • unfavorable wholesale load revenue of $165 primarily due to lower load volumes in New England • unfavorable revenues of $90 in the West due to the impacts of ISO hourly energy netting |
|||||||||||||
| Calpine | 3,384 | 100.0 | % | • represents the operating revenues associated with our Calpine segment | |||||||||||||
| Other | (15) | (1.8) | % | • current year includes unfavorable amortization of $55 associated with certain commodity contracts related to the Calpine acquisition | |||||||||||||
|
Unrealized gains or losses(a)(b)
|
(206) | (a) |
• losses on economic hedging activities of $362 in 2026 compared to losses of $156 in 2025, inclusive of Calpine
|
||||||||||||||
| Total | $ | 2,980 | 45.4 | % | |||||||||||||
|
Nine Months Ended September 30 |
|||||||||||||||||
| $ Change | % Change | Description | |||||||||||||||
| Mid-Atlantic | $ | 403 | 8.3 | % |
• favorable retail load revenue of $630 primarily due to higher contracted energy prices • favorable wholesale load revenue of $165 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by • unfavorable realized economic hedges of $370 due to settled prices relative to hedged prices |
||||||||||||
| Midwest | 545 | 12.6 | % |
• favorable net generation and wholesale load revenue of $580 primarily due to higher energy prices, partially offset by lower generation volumes • favorable retail load revenue of $455 primarily due to higher contracted energy prices and higher load volumes • favorable net capacity revenue of $185 primarily due to higher prices • favorable realized economic hedges of $80 due to settled prices relative to hedged prices; partially offset by • unfavorable CMC program revenue of $450 primarily due to higher energy and capacity prices • unfavorable ZEC program revenue of $180 primarily due to lower revenue recognized for Illinois ZECs delivered in prior planning years and decrease in ZEC price • unfavorable nuclear PTC revenue of $145 due to higher energy and capacity prices |
|||||||||||||
| New York | 47 | 2.8 | % |
• favorable net generation revenue of $155 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices; partially offset by • unfavorable realized economic hedges of $75 due to settled prices relative to hedged prices |
|||||||||||||
| ERCOT | (81) | (5.4) | % | • unfavorable realized economic hedges of $65 due to settled prices relative to hedged prices | |||||||||||||
| Other Power Regions | (726) | (17.0) | % |
• unfavorable wholesale load revenue of $370 primarily due to lower load volumes in New England • unfavorable retail load revenue of $285 primarily due to lower load volumes in New England and lower energy prices in the West • unfavorable revenues of $115 in the West due to the impacts of ISO hourly energy netting |
|||||||||||||
| Calpine | 7,926 | 100.0 | % | • represents the operating revenues associated with our Calpine segment since the date of acquisition | |||||||||||||
| Other | (386) | (12.1) | % |
• current year includes unfavorable amortization of $475 associated with certain commodity contracts related to the Calpine acquisition • unfavorable revenues in the United Kingdom, inclusive of realized economic hedges, of $55 primarily due to lower energy prices; partially offset by • favorable retail gas revenue of $105 primarily due to higher gas prices |
|||||||||||||
|
Unrealized gains or losses(a)(b)
|
989 | (a) |
• gains on economic hedging activities of $633 in 2026 compared to losses of $356 in 2025, inclusive of Calpine
|
||||||||||||||
| Total | $ | 8,717 | 44.8 | % | |||||||||||||
__________
(a)% Change in unrealized gains or losses is not a meaningful measure.
(b)See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.
Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices.
With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, energy-related activity in the United Kingdom, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment.
For the three and nine months ended September 30, 2026 compared to 2025, Purchased power and fuel expense were as follows:
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
| 2026 | 2025 |
$ Change
|
% Change | 2026 | 2025 |
$ Change
|
% Change | ||||||||||||||||||||||||||||||||||||||||
| Mid-Atlantic | $ | 850 | $ | 871 | $ | (21) | (2.4) | % | $ | 2,451 | $ | 2,393 | $ | 58 | 2.4 | % | |||||||||||||||||||||||||||||||
| Midwest | 630 | 447 | 183 | 40.9 | % | 2,098 | 1,489 | 609 | 40.9 | % | |||||||||||||||||||||||||||||||||||||
| New York | 157 | 159 | (2) | (1.3) | % | 491 | 458 | 33 | 7.2 | % | |||||||||||||||||||||||||||||||||||||
| ERCOT | 247 | 213 | 34 | 16.0 | % | 571 | 589 | (18) | (3.1) | % | |||||||||||||||||||||||||||||||||||||
| Other Power Regions | 839 | 1,200 | (361) | (30.1) | % | 2,734 | 3,560 | (826) | (23.2) | % | |||||||||||||||||||||||||||||||||||||
|
Calpine
|
1,457 | - | 1,457 | 100.0 | % | 3,845 | - | 3,845 | 100.0 | % | |||||||||||||||||||||||||||||||||||||
| Total segment purchased power and fuel | 4,180 | 2,890 | 1,290 | 44.6 | % | 12,190 | 8,489 | 3,701 | 43.6 | % | |||||||||||||||||||||||||||||||||||||
| Other | 702 | 702 | - | - | % | 2,694 | 2,664 | 30 | 1.1 | % | |||||||||||||||||||||||||||||||||||||
|
Unrealized losses (gains)(a)
|
(482) | (25) | (457) | (a) | (109) | (70) | (39) | (a) | |||||||||||||||||||||||||||||||||||||||
| Total purchased power and fuel | $ | 4,400 | $ | 3,567 | $ | 833 | 23.4 | % | $ | 14,775 | $ | 11,083 | $ | 3,692 | 33.3 | % | |||||||||||||||||||||||||||||||
__________
(a)% Change in unrealized losses (gains) is not a meaningful measure.
Natural Gas Prices. As an owner-operator of a large fleet of natural gas-fired generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized.
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||||||||||||||||||||||||||
| Location | 2026 | 2025 | $ Change | % Change | 2026 | 2025 | $ Change | % Change | |||||||||||||||||||||||||||||||||||||||
| Henry Hub | $ | 2.87 | $ | 3.03 | $ | (0.16) | (5.3) | % | $ | 3.56 | $ | 3.48 | $ | 0.08 | 2.3 | % | |||||||||||||||||||||||||||||||
|
Transco Zone 6(a)
|
1.85 | 2.23 | (0.38) | (17.0) | % | 4.46 | 3.55 | 0.91 | 25.6 | % | |||||||||||||||||||||||||||||||||||||
|
Houston Ship Channel(b)
|
2.46 | 2.69 | (0.23) | (8.6) | % | 2.72 | 2.96 | (0.24) | (8.1) | % | |||||||||||||||||||||||||||||||||||||
|
PG&E Citygate(c)
|
3.09 | 3.47 | (0.38) | (11.0) | % | 2.24 | 3.33 | (1.09) | (32.7) | % | |||||||||||||||||||||||||||||||||||||
|
Algonquin Citygate(d)
|
2.24 | 2.96 | (0.72) | (24.3) | % | 6.19 | 5.85 | 0.34 | 5.8 | % | |||||||||||||||||||||||||||||||||||||
__________
(a)Transcontinental Gas pipeline located in Mid-Atlantic region.
(b)Houston-area pipeline and industrial network located in ERCOT region.
(c)Pacific Gas & Electric Company virtual trading point located in West region.
(d)Algonquin Gas Transmission physical delivery point located in New England region.
For the three and nine months ended September 30, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:
|
Three Months Ended September 30 |
|||||||||||||||||
| $ Change | % Change | Description | |||||||||||||||
| Mid-Atlantic | $ | (21) | (2.4) | % |
• favorable realized economic hedges of $75 due to settled prices relative to hedged prices • unfavorable $70 associated with purchased power to supply load, net of generation, primarily due to higher energy prices |
||||||||||||
| Midwest | 183 | 40.9 | % | • unfavorable $175 associated with purchased power to supply load, net of generation, primarily due to higher net transmission costs | |||||||||||||
| New York | (2) | (1.3) | % | • no individually significant drivers | |||||||||||||
| ERCOT | 34 | 16.0 | % | • no individually significant drivers | |||||||||||||
| Other Power Regions | (361) | (30.1) | % |
• favorable $210 associated with purchased power to supply load primarily due to lower load volumes in New England • favorable cost of $90 in the West due to the impacts of ISO hourly energy netting |
|||||||||||||
| Calpine | 1,457 | 100.0 | % | • represents the purchased power and fuel associated with our Calpine segment | |||||||||||||
| Other | - | - | % | • no individually significant drivers | |||||||||||||
|
Unrealized gains or losses(a)(b)
|
(457) | (a) |
• gains on economic hedging activities of $482 in 2026 compared to gains of $25 in 2025, inclusive of Calpine
|
||||||||||||||
| Total | $ | 833 | 23.4 | % | |||||||||||||
|
Nine Months Ended September 30 |
|||||||||||||||||
| $ Change | % Change | Description | |||||||||||||||
| Mid-Atlantic | $ | 58 | 2.4 | % |
• unfavorable $475 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to an extreme weather event in January 2026; partially offset by • favorable realized economic hedges of $390 due to settled prices relative to hedged prices • favorable $65 due to financial transmission rights overfunding in 2026 |
||||||||||||
| Midwest | 609 | 40.9 | % | • unfavorable $565 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026 and net transmission costs | |||||||||||||
| New York | 33 | 7.2 | % | • no individually significant drivers | |||||||||||||
| ERCOT | (18) | (3.1) | % | • no individually significant drivers | |||||||||||||
| Other Power Regions | (826) | (23.2) | % |
• favorable $405 associated with purchased power to supply load primarily due to lower load volumes in New England, and lower energy prices in the West • favorable $185 associated with environmental product sales and lower environmental obligations • favorable cost of $115 in the West due to the impacts of ISO hourly energy netting • favorable realized economic power hedges of $105 due to settled prices relative to hedged prices |
|||||||||||||
| Calpine | 3,845 | 100.0 | % | • represents the purchased power and fuel associated with our Calpine segment since the date of acquisition | |||||||||||||
| Other | 30 | 1.1 | % |
• unfavorable net wholesale gas purchases of $105, inclusive of realized economic hedges, primarily due to higher gas prices • favorable purchases in the United Kingdom, inclusive of realized economic hedges, of $60 primarily due to lower energy prices |
|||||||||||||
|
Nine Months Ended September 30 |
|||||||||||||||||
| $ Change | % Change | Description | |||||||||||||||
|
Unrealized gains or losses(a)(b)
|
(39) | (a) |
• gains on economic hedging activities of $109 in 2026 compared to gains of $70 in 2025, inclusive of Calpine
|
||||||||||||||
| Total | $ | 3,692 | 33.3 | % | |||||||||||||
__________
(a)% Change in unrealized gains or losses is not a meaningful measure.
(b)See Note 12 - Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.
The changes in Operating and maintenance expense consisted of the following:
| 2026 vs. 2025 | |||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||
| Increase (Decrease) |
Increase (Decrease)
|
||||||||||
|
Labor, contracting, and materials(a)
|
$ | 261 | $ | 666 | |||||||
|
Calpine merger and integration costs
|
62 | 273 | |||||||||
|
Nuclear refueling outage costs(b)
|
- | 119 | |||||||||
| Changes in legal and environmental liabilities | 10 | 57 | |||||||||
|
Decommissioning-related activities
|
(16) | (284) | |||||||||
|
Other(c)
|
163 | 520 | |||||||||
| Total increase | $ | 480 | $ | 1,351 | |||||||
__________
(a)Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026.
(b)Includes the co-owned Salem and STP generating units.
(c)Primarily includes administrative expenses such as information technology, regulatory fees, facilities and rentals, and insurance. The increase is driven primarily by the addition of Calpine's operations beginning in January 2026.
Depreciation and amortization expense increased by $213 million for the three months ended September 30, 2026 compared to the same period in 2025, and increased by $597 million for the nine months ended September 30, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 - Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
Interest expense, net increased by $83 million for the three months ended September 30, 2026 compared to the same period in 2025, and increased by $355 million for the nine months ended September 30, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Other, net was unfavorable for the three and nine months ended September 30, 2026 compared to the same period in 2025, due to activity described in the table below:
|
Income (Deductions)
|
|||||||||||||||||||||||
| Three Months Ended September 30, | Nine Months Ended September 30, | ||||||||||||||||||||||
| 2026 | 2025 | 2026 | 2025 | ||||||||||||||||||||
|
Decommissioning-related activities(a)
|
$ | (16) | $ | 373 | $ | 640 | $ | 904 | |||||||||||||||
|
Net unrealized gains (losses) from equity investments(b)
|
(8) | 19 | (32) | (256) | |||||||||||||||||||
|
Other
|
(20) | 51 | (3) | 81 | |||||||||||||||||||
| Other, net | $ | (44) | $ | 443 | $ | 605 | $ | 729 | |||||||||||||||
__________
(a)Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 - Asset Retirement Obligations and Note 18 - Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.
(b)Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.
Effective income tax rates were 18.2% and 33.4% for the three months ended September 30, 2026 and 2025, respectively, and 25.4% and 32.9% for the nine months ended September 30, 2026 and 2025, respectively. The decrease in effective tax rate for the three months ended was primarily driven by the long-term rate change and lower qualified NDT fund income in the third quarter of 2026 which is taxed at a higher rate. The decrease in effective tax rate for the nine months ended was primarily due to proportionally lower qualified NDT fund income in 2026 which is taxed at a higher rate as well as long-term rate change. See Note 10 - 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. Annually, we 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 planned restart of Crane and nuclear uprate projects. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of approximately $14.5 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 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Cash Flow Activities
The following table summarizes our cash flow activities for the nine months ended September 30, 2026 and 2025, respectively:
| Nine Months Ended September 30, | |||||||||||||||||
| 2026 | 2025 | $ Change | |||||||||||||||
|
Cash, restricted cash, and cash equivalents at beginning of period
|
$ | 3,748 | $ | 3,129 | $ | 619 | |||||||||||
| Net cash provided by (used in): | |||||||||||||||||
| Operating activities | 4,979 | 3,432 | 1,547 | ||||||||||||||
| Investing activities | (6,064) | (2,221) | (3,843) | ||||||||||||||
| Financing activities | (1,654) | (249) | (1,405) | ||||||||||||||
|
Net increase (decrease) in cash, restricted cash, and cash equivalents
|
(2,739) | 962 | (3,701) | ||||||||||||||
|
Cash, restricted cash, and cash equivalents at end of period
|
$ | 1,009 | $ | 4,091 | $ | (3,082) | |||||||||||
Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities was $4,979 million and $3,432 million for the nine months ended September 30, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Included in net cash provided by operating activities for the nine months ended September 30, 2026, are refunds to state programs associated with nuclear PTCs. See Note 6 - Government Assistance 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 ($6,064) million and ($2,221) million for the nine months ended September 30, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition and an increase in capital expenditures related to the planned restart of Crane, inclusion of Calpine, nuclear uprate projects, and co-location infrastructure. See Note 2 - Mergers, Acquisitions, and Dispositions 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 ($1,654) million and ($249) million for the nine months ended September 30, 2026 and 2025, respectively. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the nine months ended September 30, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. The remaining change is related to repurchases of common stock. See Note 13 - Debt and Credit Agreements and Note 16 - Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Quarterly dividends declared by our Board of Directors during 2026 were as follows:
| Period | Declaration Date | Shareholder of Record Date | Dividend Payable Date | Cash per Share | ||||||||||||||||||||||
|
First Quarter of 2026
|
February 20, 2026 | March 9, 2026 | March 20, 2026 | $ | 0.4265 | |||||||||||||||||||||
|
Second Quarter of 2026
|
April 28, 2026 | May 15, 2026 | June 5, 2026 | 0.4265 | ||||||||||||||||||||||
|
Third Quarter of 2026
|
August 4, 2026 | August 18, 2026 | September 4, 2026 | 0.4265 | ||||||||||||||||||||||
|
Fourth Quarter of 2026
|
October 30, 2026 | November 16, 2026 | December 4, 2026 | 0.4265 | ||||||||||||||||||||||
Credit Matters and Cash Requirements
We fund liquidity needs for capital expenditures, working capital, energy hedging and other financial commitments through cash flows from operations, public debt offerings, commercial paper markets and large, diversified credit facilities. As of September 30, 2026, we have access to facilities with aggregate bank commitments of approximately $14.5 billion. See Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
We had access to the commercial paper markets and had availability under our revolving credit facilities during the third quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.
We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below.
Security Ratings
Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of September 30, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of September 30, 2026, we had approximately $7.2 billion of available capacity under our credit facilities and $0.6 billion of cash on hand. In the event of a credit downgrade below investment grade and a resulting requirement to provide incremental collateral exceeding available capacity under our credit facilities and cash on hand, we would be required to access additional liquidity through the capital markets. Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements. Our credit ratings were affirmed by Moody's and S&P in January 2026 following the completion of the acquisition of Calpine.
If we had lost our investment grade credit ratings as of September 30, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.6 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.
See Note 12 - Derivative Financial Instruments and Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Pension and Other Postretirement Benefits
We consider various factors when making qualified pension funding decisions, including actuarially-determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2026 for $161 million. Unlike the qualified pension plans, our non-qualified plans are not subject to statutory minimum contribution requirements.
OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension
plans in 2026 are approximately $25 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $64 million. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on pension and other postretirement benefits.
Cash Requirements for Other Financial Commitments
In connection with the acquisition of Calpine in January 2026, we assumed approximately $3 billion of projected cash payments under existing financial commitments with fixed or minimum payments required. These commitments exclude future cash payments for debt service on assumed debt as much of the debt was refinanced or paid off following the acquisition. See Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other than as described above and elsewhere in this Quarterly Report on Form 10-Q, there have been no material changes to the cash requirements from contractual and other obligations disclosed in our 2025 Annual Report on Form 10-K. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on our cash requirements for financial commitments.
Accounts Receivable Facilities
We maintain multiple accounts receivable financing arrangements, including a revolving facility secured by certain accounts receivable and an accounts receivable sales program assumed in connection with our January 2026 acquisition of Calpine. See Note 7 - Accounts Receivable and Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Project Financing
Project financing is based upon a financial structure in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. As a result of our acquisition of Calpine in January 2026, we assumed various project financing arrangements. See Note 16 - Debt and Credit Agreements of our 2025 Form 10-K and Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt.
Credit Facilities
We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. We assumed various credit facilities as part of the acquisition of Calpine. See Note 13 - Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.
NRC Minimum Funding Requirements
NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant's owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 - Asset Retirement
Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC.
As of September 30, 2026, the Crane NDT is fully funded under the SAFSTOR scenario that is 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, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Nuclear Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources - NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.
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