10-K – 2026-02-24 – ceg-20251231.htm

obligations. The asset values are subject to market fluctuations and will yield uncertain returns, which could fall below our projected return rates. A decline in the market value of the NDT fund investments could increase our funding requirements to decommission our nuclear plants. A decline in the market value of the pension and OPEB plan assets would increase the funding requirements associated with our pension and OPEB plan obligations. Additionally, our pension and OPEB plan liabilities are sensitive to changes in interest rates. As interest rates decrease, the liabilities increase, potentially increasing benefit costs and funding requirements. See Note 10 — Asset Retirement Obligations and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information.
We could be negatively affected by unstable capital and credit markets and increased volatility in commodity markets.
We rely on the capital markets, particularly for publicly offered debt, as well as the banking and commercial paper markets, to meet our financial commitments and short-term liquidity needs. Disruptions in the capital and credit markets in the United States or abroad could negatively affect our ability to access the capital markets or draw on our bank revolving credit facilities. The banks may not be able to meet their funding commitments to us if they experience shortages of capital and liquidity or if they experience excessive volumes of borrowing requests within a short period of time. The inability to access capital markets or credit facilities, and longer-term disruptions in the capital and credit markets as a result of uncertainty, changing or increased regulation, reduced alternatives or failures of significant financial institutions could result in the deferral of discretionary capital expenditures, affect our ability to effectively hedge our generation portfolio, require changes to our hedging strategy in order to reduce collateral posting requirements, or require a reduction in discretionary uses of cash. In addition, we have exposure to worldwide financial markets, including Europe, Canada, and Asia. Disruptions in these markets could reduce or restrict our ability to secure sufficient liquidity or secure liquidity at reasonable terms. As of December 31, 2025, approximately 26%, 8%, and 13% of our available credit facilities were with European, Canadian, and Asian banks, respectively.
The strength and depth of competition in energy markets depend heavily on active participation by multiple trading parties, which could be negatively affected by disruptions in the capital and credit markets and legislative and regulatory initiatives that could affect participants in commodities transactions. Reduced capital and liquidity and failures of significant institutions that participate in the energy markets could diminish the liquidity and competitiveness of energy markets that are important to our business. Perceived weaknesses in the competitive strength of the energy markets could lead to pressures for greater regulation of those markets or attempts to replace market structures with other mechanisms for the sale of power, including the requirement of long-term contracts.
If we were to experience a downgrade in our credit ratings to below investment grade or otherwise fail to satisfy the credit standards in our agreements with our counterparties or regulatory financial requirements, we would be required to provide significant amounts of collateral that could affect our liquidity and we could experience higher borrowing costs.
Our business is subject to credit quality standards that could require us to post collateral for our obligations upon a decline in ratings. We are also subject to certain financial requirements under NRC regulations as a result of our operation of nuclear power plants that could require us to provide cash collateral or surety bonds if those requirements are not met. One or both events could adversely affect available liquidity and, in the case of a rating downgrade, borrowing and credit support costs.
See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources – Credit Matters and Cash Requirements – Security Ratings and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information regarding the potential impacts of credit downgrades on our cash flows.
If we fail to meet project-specific financing agreement requirements, we could experience an impairment or loss of the financed project.
We have project-specific financing arrangements and must meet the requirements of various agreements relating to those financings. Failure to meet those arrangements could give rise to a project-specific financing default which, if not cured or waived, could result in the specific project being required to repay the associated debt or

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other borrowings earlier than otherwise anticipated, and if such repayment were not made, the lenders or security holders would generally have broad remedies, including rights to foreclose against the project assets and related collateral or to force our subsidiaries in the project-specific financings to enter bankruptcy proceedings. The impact of bankruptcy could result in the impairment or loss of certain project assets. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
The impacts of significant economic downturns (i.e., recession) could lead to decreased volumes delivered and increased expense for uncollectible customer balances.
The impacts of significant economic downturns on our retail customers, such as less demand for the products and services provided by our C&I customers, could result in an increase in the number of uncollectible customer balances and related expense.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on our credit risk.
We may be adversely affected by the effects of sustained inflation.
An increase in inflation rates could result in higher interest rates and capital costs, increased costs of labor, and other similar effects. If inflation rates rise or become elevated for a sustained period, they could have a material adverse effect on our business, financial condition, results of operations and liquidity. Although we may take measures to mitigate the impact of inflation, those measures may not be effective.
Long-lived assets, goodwill, and other assets could become impaired.
Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. In addition, we expect to have a significant goodwill balance following the acquisition of Calpine in January 2026.
In accordance with GAAP, the acquisition of Calpine will be accounted for as a business combination. We expect that the consideration transferred is greater than the fair value of the net assets acquired, and therefore we anticipate recording goodwill on the opening balance sheet. The acquired goodwill will be allocated to the appropriate reporting units of the combined company.
We evaluate the recoverability of the carrying value of long-lived assets to be held and used whenever events or circumstances indicating a potential impairment may exist. Factors such as, but not limited to, the business climate, including current and future energy and market conditions, environmental regulation, and the condition of assets are considered. We assess goodwill for impairment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. Changes in significant assumptions, including discount rates, energy prices, projected operating costs, and cash flows could potentially result in future impairments of goodwill.
An impairment would require us to reduce the carrying value of the long-lived asset and goodwill to fair value through a non-cash charge to expense by the amount of the impairment and could have a material adverse impact on our future operating results or financial condition. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Critical Accounting Policies and Estimates, Note 1 — Basis of Presentation, Note 8 — Property, Plant, and Equipment, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information on long-lived asset impairments.
We could incur substantial costs in the event of non-performance by third parties under indemnification agreements. We are exposed to other credit risks in the power markets that are beyond our control.
We have entered into various agreements with counterparties that require those counterparties to reimburse us and hold us harmless against specified obligations and claims. To the extent that any of these counterparties are

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affected by deterioration in their creditworthiness or the agreements are otherwise determined to be unenforceable, we could be held responsible for the obligations.
We have issued indemnities to third parties regarding environmental or other matters in connection with purchases and sales of assets, including several of the Exelon utilities in connection with our absorption of their former generating assets. We could incur substantial costs to fulfill our obligations under these indemnities.
In the bilateral markets, we are exposed to the risk that counterparties that owe us money or are obligated to purchase energy or fuel from us will not perform under their obligations for operational or financial reasons. In the event the counterparties to these arrangements fail to perform, we could be forced to purchase or sell energy or fuel in the wholesale markets at less favorable prices and incur additional losses, to the extent amounts, if any, were already paid to the counterparties. In the spot markets, we are exposed to risk as a result of default sharing mechanisms that exist within certain markets, primarily RTOs and ISOs. We are also a party to agreements with entities in the energy sector that have experienced rating downgrades or other financial difficulties. In addition, our retail sales subject us to credit risk through competitive electricity and natural gas supply activities to serve C&I companies, governmental entities, and residential customers. Retail credit risk results when customers default on their contractual obligations. This risk represents the loss that could be incurred due to the nonpayment of a customer’s account balance, as well as the loss from the resale of energy previously committed to serve the customer.
Expiration or termination of our PPAs and other contractual agreements may significantly reduce our revenue and allow the counterparty or customer to seek liquidated damages.
A material portion of our portfolio is sold under PPAs that expire at various times. We seek to extend contracts or sell any generation not sold under PPAs on a short-term basis as market opportunities arise. Our non-contracted generation is generally sold on the spot market at current market prices as merchant energy. When the terms of each of our various PPAs expire, it is possible that the price paid to us for generation under subsequent arrangements or in short-term markets may be significantly less than the price paid to us under the PPA. Without the benefit of PPAs, we may not be able to sell any or all of the capacity from these generation facilities at commercially attractive rates, and these generation facilities may not be able to operate profitably.
The counterparty or customer may terminate or fail to comply with the terms of our PPAs, construction agreements, commodity contracts, maintenance agreements and other contractual arrangements. Additionally, if we fail to meet our contractual obligations they may seek to enforce the liquidated damages provisions contained in such agreements.
Risks Related to Legislative, Regulatory, and Legal Factors
Federal or state legislative or regulatory actions could negatively affect the scope and functioning of the wholesale markets.
Approximately 70% of our generating resources, which include directly owned assets and capacity obtained through long-term contracts, are in the area encompassed by PJM. Our future results of operations are impacted by (1) FERC’s and PJM's level of support for policies that favor the preservation of competitive wholesale power markets, recognize the value of emissions-free electricity and resiliency, complement states' energy objectives and policies and (2) the absence of material changes to market structures that would limit or otherwise negatively affect us. Market rules in other regions could affect us in a similar fashion. We could also be affected by state laws, regulations or initiatives to subsidize existing or new generation.
FERC’s requirements for market-based rate authority could pose a risk that we may no longer satisfy FERC’s tests for market-based rates. A loss of market-based rate authority would mean that we would sell power at cost-based rates.
Our business is highly regulated and could be negatively affected by legislative and/or regulatory actions.
Substantial aspects of our business are subject to comprehensive federal or state legislation and/or regulation.

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Our results of operations and financial condition are significantly affected by our sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates. Federal and state regulatory and legislative action designed to limit market-based rates through capacity market mitigation, energy and capacity pricing restrictions, new generation mandates, or other means, may negatively impact our results of operations. Federal or state legislative and regulatory efforts to preserve the environmental attributes and reliability benefits of zero-emission nuclear-powered generating facilities could be subject to legal and regulatory challenges and, if overturned, could result in the early retirement of certain of our nuclear plants. The PTC benefiting existing nuclear plants included in the IRA (starting January 1, 2024) and affirmed by the OBBBA continues to be the subject of additional guidance issued from the U.S. Treasury and IRS, which may negatively impact the amount of benefits we ultimately receive. In addition, the duration of the PTC program, the value of the PTC, and/or the existence of the PTC could be affected by legislative action and may have significant adverse effects on our financial performance depending on the future gross receipts received by our nuclear units. Additionally, Federal Power Act Section 202(c) authorizes the issuance of emergency orders requiring power plants to operate or to mandate temporary electricity connections to prevent grid failure during emergencies such as severe weather, fuel shortages, or sudden demand spikes. The exercise of such authority could have an adverse impact on our results of operations if we are required to operate units when it is not economical.
Fundamental changes in regulations or other adverse legislative actions affecting our business would require changes in our business planning models and operations. We cannot predict when or whether legislative and regulatory proposals could become law or what their effect would be. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information.
NRC actions could negatively affect the operations and profitability of our nuclear generating fleet.
Regulatory Risk. A change in the Atomic Energy Act or the applicable regulations or licenses could require a substantial increase in capital expenditures or could result in increased operating or decommissioning costs. Events at nuclear plants owned by others, as well as those owned by us, could cause the NRC to initiate such actions.
Spent Nuclear Fuel Storage. Our nuclear operations produce various types of nuclear waste materials, including SNF. The approval of a national repository for the storage of SNF and the timing of that facility opening will significantly affect the costs associated with storage of SNF and the ultimate amounts received from the DOE to reimburse us for these costs.
Any regulatory action relating to the timing and availability of a repository for SNF could adversely affect our ability to decommission fully our nuclear units. We cannot predict whether a fee may be established or to what extent, in the future for SNF disposal. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
We could be subject to higher costs and/or penalties related to mandatory reliability standards.
We, as a user of the bulk power transmission system, are subject to mandatory reliability standards promulgated by NERC and enforced by FERC. The standards are based on the functions that need to be performed to ensure the bulk power system operates reliably and are guided by reliability and market interface principles. Compliance with or changes in the reliability standards could subject us to higher operating costs and/or increased capital expenditures. If we were found in non-compliance with the federal and state mandatory reliability standards, we could be subject to remediation costs as well as sanctions, which could include substantial monetary penalties.
We could incur substantial costs to fulfill our obligations related to environmental and other matters.
We are subject to extensive environmental regulation and legislation by local, state and federal authorities. These laws and regulations affect the way we conduct our operations and make capital expenditures, including how we handle air and water emissions, hazardous and solid waste, and activities affecting surface waters, groundwater, and aquatic and other species. Violations of these requirements could subject us to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs for remediation and cleanup

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costs, civil penalties and exposure to third parties’ claims for alleged health or property damages or operating restrictions to achieve compliance. In addition, we are subject to liability under these laws for the remediation costs for environmental contamination of property currently or formerly owned by us and of property contaminated by hazardous substances we generated or released. Also, we are currently involved in several proceedings relating to sites where hazardous substances have been deposited and could be subject to additional proceedings in the future. See ITEM 1. BUSINESS – Environmental Matters and Regulation and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
We could be negatively affected by federal and state RPS and/or energy conservation legislation, along with energy conservation by customers.
Changes to current state legislation or the development of federal legislation that requires the use of clean, renewable and alternate fuel sources could significantly impact us. The impact could include reduced use of some of our generating facilities with effects on our operating revenues and costs.
Federal and state legislation mandating the implementation of energy conservation programs, GHG emission limitations, and new energy consumption technologies could cause declines in customer energy consumption and lead to a decline in our operating revenues. We could incur costs to further limit the GHG emissions from our operations or otherwise comply with applicable requirements. To the extent such additional regulation or legislation does not become effective, the potential competitive advantage offered by our low-emissions profile may be reduced. See ITEM 1. BUSINESS – Environmental Matters and Regulation – Renewable and Clean Energy Standards and “We may be affected by emerging technologies that could, over time, affect or transform the energy industry” above for additional information.
Our financial performance could be negatively affected by risks arising from our ownership and operation of hydroelectric facilities.
FERC has the exclusive authority to license most non-federal hydropower projects located on navigable waterways, federal lands, or connected to the interstate electrical grid. If FERC does not issue new operating licenses for our hydroelectric facilities in the future or a station cannot be operated through the end of its current operating license, our results of operations could be adversely affected by increased depreciation rates and accelerated future decommissioning costs, since depreciation rates and decommissioning cost estimates are currently based on the available license term for each facility. We could also lose operating revenues and incur increased purchased power and fuel expense to meet our supply commitments. In addition, conditions could be imposed as part of the license renewal process that could adversely affect operations, require a substantial increase in capital expenditures, result in increased operating costs or render the project uneconomic. Similar effects could result from a change in the Federal Power Act or the applicable regulations due to events at hydroelectric facilities owned by others, as well as those owned by us. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for additional information regarding the license renewal for the Conowingo hydroelectric project.
We could be negatively affected by challenges to tax positions taken, tax law changes and the inherent difficulty in quantifying potential tax effects of business decisions.
We are required to make judgments in order to estimate our obligations to taxing authorities. These tax obligations include income, real estate, sales and use, and employment-related taxes and ongoing appeal issues related to these tax matters. These judgments include reserves established for potential adverse outcomes regarding tax positions that have been taken that could be subject to challenge by the tax authorities. See Note 1 — Basis of Presentation and Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Following the Calpine acquisition in January 2026, we have several government awards for projects involving cost-share agreements with the DOE, which could be affected by our inadvertent failure to comply with certain laws, rules, and regulations.
At five facilities, Calpine has completed or commenced front-end engineering design studies for post-combustion CCUS technology and has also received funding from the DOE for certain geothermal drilling technologies for the Geysers Assets.

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As a recipient of federal funds under grants and cooperative agreements, in addition to our ordinary contractual obligations, we must comply with various rules and regulations applicable to entities that perform awards in support of government entities. Many of these additional obligations are contained in the terms of the awards themselves and in federal regulations, which regulate the formation, administration and performance of non-procurement federal financial assistance awards, which are subject to change. We must also comply with various national policy requirements prescribed by statute, executive order, policy guidance issued by the Executive Office of the President or other regulations subject to change.
Additionally, our contractors must also comply with these federal requirements, and any non-compliance by our contractors or their subcontractors could similarly affect our grant status and expose us to additional risks and liabilities. While we will continue to implement audits and monitor contractual rights for our contractors, failure by our contractors to comply with all regulatory requirements fully could materially affect our business and prospects.
Our performance under our U.S. government awards and our compliance with the terms of those awards and applicable laws and regulations are subject to periodic investigation audits, reviews and investigations by various U.S. government agencies. The current environment may lead to increased regulatory scrutiny and sanctions for non-compliance by such agencies.
Compliance with these laws and regulations affects how we do business and may impose added costs on our business. Failure to comply may lead to penalties, including whole or partial suspension or termination of our U.S. government awards and/or suspension or debarment from contracting with federal agencies.
Legal proceedings could result in a negative outcome, which we cannot predict.
We are involved in legal proceedings, claims, and litigation arising from our business operations. Our material legal proceedings, claims, and litigation are summarized in Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Adverse outcomes in these proceedings could lead to significant expenditures, loss of revenue, or the restriction of existing business activities.
We could be subject to adverse publicity and reputational risks, which make us vulnerable to negative customer perception and could lead to increased regulatory oversight or other consequences.
We could be the subject of public criticism. Adverse publicity of this nature could render public service commissions and other regulatory and legislative authorities less likely to view energy companies in a favorable light, and could cause those companies, including us, to be susceptible to less favorable legislative and regulatory outcomes, as well as increased regulatory oversight and more stringent legislative or regulatory requirements.
Risks Related to Operational Factors
We are subject to risks associated with weather, including its effect on the supply and demand for electricity, as well as impacts from climate change, including extreme weather events.
Our operations are affected by weather, which impacts demand for electricity and natural gas, the price of energy commodities, and operating conditions. Warmer weather in the summer or colder weather in the winter than assumed could require greater resources to meet our contractual commitments. Extreme weather conditions or storms could affect the availability of generation and the transmission of electricity, limiting our ability to source electricity or transmit it to our customers. It could also impair our ability to transport natural gas to our generating assets and regassification facilities as well as our ability to supply natural gas to our customers. Drought-like conditions limiting water usage could impact our ability to run certain generating assets at full capacity. These conditions, which cannot be accurately predicted, could cause us to seek additional replacement supply at a time when supply is constrained.
Various forms of power generation and energy-intensive activities, such as data centers, depend on water access to operate. Certain of our assets in the West and Texas Regions, including Calpine's Geysers Assets acquired in January 2026, have experienced drought conditions in the recent past. Disruptions in water

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availability such as droughts, curtailment, or high prices may impact our ability to generate energy or serve customers, adversely impacting our operations and financial condition. Further, disruptions in water availability at the Geysers Assets may affect the water injection program, steam production and generation levels.
Weather projections suggest increases to summer temperature, humidity trends, and more erratic precipitation and storm patterns over the long term in the areas where we have generation assets. The frequency of weather conditions outside the current expected climate norms could contribute to the weather-related impacts discussed above. We primarily operate in areas that have historically been prone to various types of severe weather events. Our physical facilities could be placed at greater risk of damage should changes in the global climate impact temperature and weather patterns, and result in more intense, frequent and extreme weather events, unprecedented levels of precipitation, sea level rise, increased surface water temperatures, and/or other effects. Over time, we may need to make additional investments to protect our facilities from physical climate-related risks.
We may be exposed to climate mitigation and transition risks if we are adversely affected by changes to the energy systems as a result of new technologies, changing customer expectations and/or voluntary GHG goals, as well as local, state or federal regulatory requirements intended to reduce GHG emissions.
See ITEM 1. BUSINESS – Environmental Matters and Regulation – GHG & Climate Risks for additional information.
We are subject to certain risks associated with the operation and maintenance of generation facilities.
Operations at any of our generation facilities that we operate as well as those that we own and are operated by others could degrade to the point where the operator must shut down the plant or operate at less than full capacity. If this were to happen, identifying and correcting the causes could require significant time and expense. The operator could choose to close a plant rather than incurring the expense of restarting it or returning the plant to full capacity. In either event, we could lose revenue and incur increased purchased power and fuel expense to meet supply commitments.
In addition, we depend on facilities and assets that we do not own or control for the transmission to our customers or the distribution to our generation facilities. If these transmission and distribution systems are disrupted or the capacity of those systems is inadequate, our ability to sell and deliver power products or obtain fuel may be hindered.
Our financial performance could be negatively affected by matters arising from our ownership and operation of nuclear facilities.
Nuclear capacity factors. Capacity factors for nuclear generating units significantly affect our results of operations. Lower capacity factors could decrease our revenues and increase operating costs by requiring us to produce additional energy from our natural gas and oil-fueled facilities or purchase additional energy in the spot or forward markets in order to satisfy our supply obligations to committed third-party sales. These sources generally have higher costs to produce energy relative to our nuclear stations.
Nuclear refueling outages. In general, refueling outages are planned to occur once every 18 to 24 months. The total number of refueling outages, along with their duration, could have a significant impact on our results of operations. When refueling outages last longer than anticipated or we experience unplanned outages, capacity factors decrease, and we face lower margins due to higher energy replacement costs and/or lower energy sales and higher operating and maintenance costs.
Nuclear fuel. In addition to the risks around the cost and availability of nuclear fuel discussed previously, the quality of nuclear fuel we use could affect the efficiency and costs of our operations. Remediation actions could result in increased costs due to accelerated fuel amortization, increased outage costs and/or increased costs due to decreased generation capabilities.
We do not procure the fuel for the sites we do not operate. If the operator is unable to procure fuel sufficient to operate the plant or at an uneconomical price, our results of operations could be adversely impacted.

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Additionally, if we are required to arrange for the safe and permanent disposal of SNF beyond current expectations, this could lead to substantial expense or capital expenditures. See “NRC actions could negatively affect the operations and profitability of our nuclear generating fleet” above for additional information on the storage of SNF.
Nuclear major incident risk and insurance. The consequences of a major incident could be severe and include loss of life and property damage. Any resulting liability from a nuclear plant major incident within the United States, owned or operated by us or owned by others, could exceed our resources, including insurance coverage. We are a member of an industry mutual insurance company, NEIL, which provides property and accidental outage insurance for our nuclear operations. Uninsured losses and other expenses, to the extent not recovered from insurers or the nuclear industry, could be borne by us. Additionally, an accident or other significant event at a nuclear plant within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy.
As required by the Price-Anderson Act, we carry the maximum available amount of nuclear liability insurance, $500 million for each operating site. Claims exceeding that amount are covered through mandatory participation in a financial protection pool. In addition, the U.S. Congress could impose revenue-raising measures on the nuclear industry to pay claims exceeding the $16.3 billion limit for a single incident.
See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on nuclear insurance.
Decommissioning obligation and funding. NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that funds will be available in certain minimum amounts at the end of the life of the facility to decommission the facility.
Actual costs to decommission our nuclear facilities may substantially exceed our estimates as a result of changes in the approach and timing of decommissioning activities, changes in decommissioning costs, changes in federal or state regulatory requirements, other changes in our estimates or our ability to effectively execute on planned decommissioning activities.
We have recourse to collect additional amounts from utility customers through PECO (subject to certain limitations and thresholds) for former PECO units and through CenterPoint and AEP Texas for STP units. If circumstances changed such that there was an inability to continue to make contributions to the trust funds of the former PECO or STP units based on amounts collected from utility customers, or if we no longer had recourse to collect additional amounts from the respective utility customers if there was a shortfall of funds for decommissioning, the adequacy of the trust funds related to these units could be negatively affected. Any changes to the utilities' regulatory agreements could impact our ability to offset decommissioning-related activities for these units within our results of operations, and the impact to our results of operations or financial condition could be material.
Should the expected value of the NDT fund for any former ComEd unit fall below the amount of the expected decommissioning obligation for that unit, the accounting to offset decommissioning-related activities for that unit may be temporarily suspended or discontinued, and the decommissioning-related activities would be recognized in our results of operations, the impact of which could be material.
Forecasting trust fund investment earnings and costs to decommission nuclear generating stations requires significant judgment, and actual results could differ significantly from current estimates. If the investments held by our NDT funds are not sufficient to fund the decommissioning of our nuclear units, we could be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and that current and future NRC minimum funding requirements are met.
See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

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The productivity of Calpine's geothermal resources acquired in January 2026 may be lower than expected, and it is possible that certain of leases for geothermal steam fields may not be renewed or may be renewed at less favorable terms.
Geothermal resource productivity can decline unexpectedly, leading to insufficient reserves for sustained power generation at desired power capacity. Mismanagement or inaccurate estimates of steam reserves could adversely affect our results of operations or financial condition.
Geothermal steam fields are leased for the Geysers Assets, with most leases lasting 5 to 20 years initially and continuing as long as resources are produced and sold. Many leases are over 30 years old and remain active. Federal leases start at 10 years and can be renewed for up to 50 years. Most other leases continue for the economic life of the assets, with renewal options if resources remain commercially viable. While we expect to renew leases as needed, some may not be renewed or could have less favorable terms.
We are subject to evolving physical security, cybersecurity, and third-party reliability risks.
Threat actors continue to seek to exploit potential vulnerabilities in the energy sector associated with protection of sensitive and confidential information, grid infrastructure, and other energy infrastructures. These attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Security incidents such as ransomware attacks are becoming increasingly prevalent and severe, as well as increasingly difficult to detect. In addition, geopolitical issues, to include conflicts in the Ukraine and the Middle East, as well as tensions between the U.S. and China, may motivate cyber-attacks which could impact the U.S. energy sector and our Company via supply chain disruptions or direct targeting.
A security breach, including, but not limited to, physical or electronic intrusions, computer viruses, malware, attacks by cyber criminals or nation state threat actors, ransomware attacks, phishing attacks, supply chain attacks, third-party breaches, and other similar breaches of our physical assets or information systems, or those of our competitors, vendors, business partners and interconnected entities in RTOs, ISOs, and other energy markets, or regulators have the potential to disrupt our business and result in harm to the Company. Security breaches can also occur as a result of non-technical issues, including intentional or inadvertent actions by our employees, third-party service providers or their personnel or other parties. Our customers depend on the continuous availability of our commercial and generation operations. A failure, interruption, or breach of our operational or information security systems, or those of our third-party service providers, as a result of cyber-attacks or information security breaches could disrupt our business, result in the disclosure or misuse of confidential or proprietary information, damage our reputation, cause loss of customers or revenue, increase our costs, result in litigation and/or regulatory action, and/or cause other losses, any of which might have a materially adverse impact on our business operations and our financial condition or results of operations. Operational harm could be in the form of impact to the generation fleet, our commercial operations, and/or reliability of the bulk power system. Impacts to confidential or proprietary information could include inappropriate release of certain types of information, including critical infrastructure, sensitive customer, vendor and employee, trading, export control or other confidential information. If a significant security breach were to occur, our reputation could be negatively affected, customer confidence in us or others in the industry could be diminished, or we could be subject to legal claims, loss of revenues, increased costs, regulatory penalties, or operational shutdown.
We currently utilize a mix of third-party managed service providers to host and support our information technology, customer support, and generation operations. For example, our data centers are hosted in vendor-managed co-location facilities; we also host infrastructure with major cloud service providers and utilize enterprise business systems. Consequently, we may be subject to short- and long-term interruptions, delays and outages in service and availability due to third-party cybersecurity or reliability incidents that are outside of our direct control. In the future we may experience interruptions, delays and outages in service and availability from time to time due to a variety of factors, including infrastructure changes, human or software errors, website hosting disruptions and capacity constraints. Coordinated physical and or cyber-attacks that disrupt multiple key electric or natural gas assets of unaffiliated, interconnected parties (such as parties responsible for real-time planning and management of the bulk power system) could impact our ability to provide generation, potentially resulting in localized and regional blackouts affecting third parties and the public, many of which might have no direct commercial relationship with the Company.

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We cannot anticipate, detect, repel, or implement fully effective preventative measures against all cyber threats, particularly because the techniques used are constantly evolving. Similarly, we cannot guarantee uninterrupted availability of third-party managed systems that may be affected by factors unrelated to cybersecurity incidents. Our implementation of generative AI to improve business and operational performance has led to the introduction of enhanced technologies that pose distinct governance and security risk management challenges. Continued implementation of advanced digital technologies, including generative AI and machine learning, increases the potentially unfavorable impacts of such attacks and reliability, and may introduce new vulnerabilities and threat tactics. For example, threat actors could use AI to develop malicious code and sophisticated phishing attempts. As threats continue to evolve, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities. While we have not experienced a material breach or disruption to our network or information systems or our operations to date, future attacks or reliability may negatively impact our business, reputation, or financial results.
Although we maintain insurance coverage for cyber events, the amount and scope of insurance maintained against losses resulting from a significant event or security breach may not be sufficient to cover losses or otherwise adequately compensate for any business disruptions that could result. There can be no assurance that such insurance will be available on commercially reasonable terms in the future. In addition, new or updated security regulations or new vulnerabilities identified by security researchers, third-party suppliers, or threat actors could require changes in current measures taken by security or our business operations and could adversely affect our results of operations or financial condition.
Our acquisition of Calpine in January 2026 introduces expanded cybersecurity and physical security risks. As part of the integration, we have and expect to continue to evolve our systems, processes, and technical controls in connection with Calpine's information technology and operational technology. Our acquisition of Calpine and the visibility of the transaction will likely increase attention from potential cyber threat actors, potential insider threats, and opportunistic adversaries.
We are continuously evolving our cybersecurity strategy and technical controls to prepare for, identify, protect, detect, respond, and recover our technology systems, information and operations from such attacks. See ITEM 1C. CYBERSECURITY for more information.
The rapid development and integration of AI technologies into our processes presents several risks to our business.
The use of AI technologies in our operations presents risks that could adversely affect our business, financial condition, results of operations and reputation. AI systems, whether developed internally or used by our vendors, service providers or business partners, may produce inaccurate, biased or misleading outputs or experience errors, security vulnerabilities or other failures, which could result in operational disruptions, flawed decision‑making, data loss, cybersecurity incidents or reputational harm. The use of AI may also increase the risk of inadvertent disclosure or misuse of proprietary, confidential or personal information. In addition, the legal and regulatory landscape governing AI technologies is rapidly evolving and uncertain, and compliance with new or changing requirements may impose significant costs or limit our ability to develop, deploy or use AI. If we fail to keep pace with the rapid evolution of AI technologies in our industry and the segments we serve, our competitive position and business results could be negatively impacted.
Our employees, contractors, customers and the general public could be exposed to a risk of injury due to the nature of the energy industry.
Employees and contractors throughout the organization work in, and the general public could be exposed to, potentially dangerous environments near our operations. As a result, employees, contractors and the general public are at some risk for serious injury, including loss of life. These risks include, but are not limited to, nuclear accidents, dam failure, gas explosions, and electric contact cases.
Natural disasters, war, acts and threats of terrorism, pandemic and other significant events could negatively impact our results of operations, ability to raise capital, and future growth.
Our fleet of power plants and the transmission infrastructure to which they are connected could be affected by natural disasters and extreme weather events, which could result in increased costs, including supply chain costs. Natural disasters and other significant events increase our risk that the NRC or other regulatory or

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legislative bodies could change the laws or regulations governing, among other things, operations, maintenance, operating licenses, decommissioning, SNF storage, insurance, emergency planning, security and environmental and radiological matters. In addition, natural disasters could affect the availability of a secure and economical supply of water in some locations, which is essential for our continued operation, particularly the cooling of generating units.
Some of Calpine's geothermal, natural gas power plants, and battery storage sites, which were acquired in January 2026 are exposed to frequent minor earthquakes and wildfire risks, mainly in the West. Severe weather and wildfires, especially in California, have disrupted operations and damaged assets like the Geysers Assets. Such events can cause injuries, property damage, and service interruptions, resulting in significant liabilities. Electric utilities may shut down power for public safety reasons during periods of extreme fire hazard. Any shutdown that halts operation at our power plants may reduce our revenues.
The impact that potential terrorist attacks could have on the industry and on us is uncertain. We face a risk that our operations would be direct targets or indirect casualties of an act of terror. Any retaliatory military strikes or sustained military campaign could affect our operations in unpredictable ways, such as changes in insurance markets and disruptions of fuel supplies and markets, particularly uranium and oil. Furthermore, these catastrophic events could compromise the physical or cybersecurity of our facilities, which could adversely affect our ability to manage our business effectively. Instability in the financial markets as a result of terrorism, war, natural disasters, pandemic, credit crises, recession or other factors also could result in a decline in energy consumption or interruption of fuel or the supply chain. In addition, the implementation of security guidelines and measures has resulted in and is expected to continue to result in increased costs.
We could be significantly affected by the outbreak of a pandemic. We have plans in place to respond to a pandemic. However, depending on the severity of a pandemic and the resulting impacts to workforce and other resource availability, the ability to operate our generating assets could be adversely affected.
We maintain a level of insurance coverage consistent with industry practices against property, casualty, and cybersecurity losses subject to unforeseen occurrences or catastrophic events that could damage or destroy assets or interrupt operations. However, there can be no assurance that the amount of insurance will be adequate to address such property and casualty losses. Furthermore, the scenarios above could result in adverse changes in insurance deductibles, premiums, coverage and/or limits.
Our business is capital intensive, and our assets could require significant expenditures to maintain and are subject to operational failure, which could result in potential liability.
Our business is capital intensive and requires significant investments in electric generating facilities. The operation of power plants and battery storage facilities involves risks, including the breakdown or failure of power generation or storage equipment, transmission lines, pipelines or other equipment or processes, performance below expected levels of output or efficiency, and other issues beyond our control that could be costly to remedy. Our results of operations or financial condition could be negatively affected if we were unable to effectively manage our capital projects or raise the necessary capital. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS – Liquidity and Capital Resources for additional information regarding our potential future capital expenditures.
Our performance could be negatively affected if we fail to attract and retain an appropriately qualified workforce.
Certain events, such as an employee strike, loss of employees, loss of contract resources due to a major event, and an aging workforce without appropriate replacements, could lead to operating challenges and increased costs for us. The challenges include lack of resources, loss of knowledge, and a lengthy time period associated with skill development. In this case, costs, including costs for contractors to replace employees, productivity costs and safety costs, could arise. We are particularly affected due to the specialized knowledge required of the technical and support employees for generation operations.

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We could make acquisitions or investments in new business initiatives and new markets, which may not be successful or achieve the intended financial results.
We could continue to pursue growth in our existing businesses and markets and seek further diversification across the competitive energy value chain. This could include opportunistic emissions-free energy acquisitions, creating new value from our existing fleet through nuclear uprates, renewable repowerings, development of additional capacity for battery storage, natural gas, and CCUS, co-location of customer load, growing sustainability solutions for our customers, and investment opportunities in other emerging technologies and innovations. Such initiatives could involve significant risks and uncertainties, including distraction of management from current operations, inadequate return on capital, and unidentified issues not discovered during diligence performed prior to launching an initiative or entering a market. Additionally, it is possible that FERC, state public utility commissions, or others could limit our ability to make acquisitions or investments or otherwise impose certain restrictions on such transactions due to market power concerns in certain regions or other factors. All these factors could result in higher costs or lower revenues than expected, resulting in lower than planned returns on investment.
We are actively implementing the restart of our Crane nuclear generation facility. The restart is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. Additionally, through separate requests, we will pursue obtaining a renewed license to operate the plant and a FERC interconnection agreement. Failure to obtain the necessary approvals could result in the impairment of amounts capitalized. The restart is a complex undertaking including procuring or restoring specialized components on a critical timeline. Failure to meet contractual timelines could result in significant penalties. Overages in costs, potential interconnection delays, or other unforeseen issues could result in lower than planned returns on the investment.
The demand for our generation may be impacted by changes in industry trends, including the demand associated with the developing data economy.
Industry trends can significantly impact the demand and market pricing of our generation portfolio. This includes the demand and perceived value of certain attributes of our generation, such as reliability or clean energy, as well as the overall demand for energy in the markets in which we operate.
Recently, we have benefited from increased demand for our generation as a result of the developing data economy, including demand driven by data centers and AI and other high-performance computing applications, evidenced by the execution of long-term contracts with technology companies as well as increased interest in prospective contracts from our customers. Demand associated with data centers and AI applications may be subject to technological change, shifts in customer behavior, regulatory developments, or changes in capital investment cycles and may not grow at the pace currently anticipated by the market. Our results of operations, growth opportunities, and the price of our common stock could be adversely impacted if the demand for energy driven by the data economy does not continue or fails to achieve current market expectations.
Risks Related to the Acquisition of Calpine
We cannot assure that we will continue paying dividends at the current rate.
We currently expect to pay dividends in an amount consistent with the dividend policy in effect prior to the completion of the merger. However, there is no assurance that our shareholders will receive the same dividends following the merger for reasons that may include capital spending plans, financing agreements, cash flow or financial condition. Decisions on whether, when, and in which amounts to make any future distributions will remain at all times entirely at the discretion of our Board of Directors, which reserves the right to change our dividend practices at any time and for any reason.
Our shareholders prior to the merger have a reduced ownership and voting power after the merger, and former Calpine stockholders are not obligated to maintain their ownership interest indefinitely.
We issued 50 million newly issued shares of common stock to Calpine stockholders as noted in the Merger Agreement (including shares of our common stock issuable pursuant to Calpine restricted stock units and other

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equity-based awards). Our prior shareholders and former Calpine stockholders owned approximately 86% and 14% of the outstanding shares of our common stock, respectively, immediately following the consummation of the merger. Each shareholder prior to the merger that remained a shareholder has a percentage ownership of the combined company that is smaller than the shareholder’s percentage held prior to the merger. As a result of this reduced ownership percentage, prior shareholders will have less influence on the policies of the combined company. Additionally, upon the expiration of certain lock-up restrictions on transfers or sales of our securities, former Calpine stockholders will not be subject to any obligation to maintain their ownership interest in us and reducing their ownership interest could adversely impact the price of our common stock. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
The merger may not be accretive to earnings and may cause dilution to our earnings per share, which may negatively affect the market price of our common stock.
We currently anticipate that the merger will be accretive to earnings per share in 2026. This expectation is based on preliminary estimates that are subject to change. We may also encounter additional transaction and integration-related costs, may fail to realize all the benefits anticipated in the merger, or be subject to other factors that affect preliminary estimates. Any of these factors could negatively impact our operating results or decrease or delay the expected accretive effect of the merger and contribute to a decrease in the price of our common stock.
We have incurred and will incur significant transaction- and merger-related costs, and these costs may be more than anticipated, negatively impacting our operating results.
We have incurred and expect to incur non-recurring costs associated with consummation of the transaction. Most of these costs will be transaction-related, including fees paid to financial and legal advisors for the merger and related financing arrangements, and employment-related costs, such as change-in-control payments made to certain Calpine executives. We will also incur transition costs related to formulating integration plans. We may incur additional unanticipated costs in the integration of the businesses, which could negatively impact our operating results. We expect that the elimination of costs, as well as the realization of other efficiencies related to the integration of the businesses, will exceed incremental transaction- and merger-related costs over time.
We may not realize all the expected benefits of the merger because of integration challenges.
The success of the merger will depend, in part, on our ability to realize all or some of the anticipated benefits from integrating Calpine’s business with our existing businesses. The integration process will be complex, costly and time-consuming. Even if achieved, anticipated benefits and efficiencies from the merger may take longer to realize, or require greater costs to achieve, than currently expected. The challenges associated with integrating the operations of Calpine’s business include, among others:
• customer retention risk, as well as the inability to finalize certain transactions currently in progress between Calpine and its customers;
• delay in implementation of our business plan for the combined business;
• unanticipated issues or costs in integrating financial, information technology, communications and other systems;
• complexities associated with managing the larger, more complex, combined business;
• potential unknown liabilities and unforeseen expenses, delays or regulatory conditions associated with the merger;
• integrating relationships with industry contacts and business partners;
• possible inconsistencies in standards, controls, procedures and policies, and compensation structures; and
• performance of Calpine’s generating assets and the costs to operate and maintain them, relative to expectations.

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It is possible that the integration process could result in the disruption of, or the loss of momentum in, our ongoing businesses or inconsistencies in standards, controls, procedures and policies, which could negatively impact the combined company.
Uncertainties associated with the merger may cause a loss of management personnel and other key employees, which could adversely affect the future business and operations of the combined company.
We are dependent on the experience and industry knowledge of our officers and other key employees to execute our business plans. The success of the combined company will depend in part upon our ability to retain key management personnel and other key employees of both companies. Employees may experience uncertainty about their future roles within the combined company following completion of the merger, which may have an adverse effect on our ability to attract or retain key management and other key personnel. Accordingly, no assurance can be given that the combined company will be able to attract or retain key management personnel and other key employees to the same extent that we have previously been able to attract or retain our employees.
The merger may divert significant attention of our management team, which could detract from efforts to meet business goals.
Merger integration efforts could place a burden on management and internal resources. Any significant diversion of management attention away from ongoing business concerns and any difficulties encountered in the transition and integration process may negatively impact our results of operations or financial condition.

ITEM 1B. UNRESOLVED STAFF COMMENTS
None.

ITEM 1C.
CYBERSECURITY

Risk Management and Strategy
We have established technical systems programs and processes to manage material risks from cybersecurity threats including assessing and identifying existing cybersecurity risks, as well as continuously monitoring for developing risks. Our cybersecurity risk management strategy is established at the executive level and is implemented through our cybersecurity program which deploys risk-based security controls and services to protect our customers, personnel, information and cyber assets. The program aligns enterprise cyber and physical security controls with the National Institute of Standards & Technology (NIST) Cybersecurity Framework (CSF) and other industry standards such as the NERC and NRC cybersecurity standards. Our cybersecurity program is aligned to the five functions of the NIST Cybersecurity Framework – identify, detect, protect, respond, and recover. Cybersecurity risk is assessed and reported in our enterprise risk management program, which utilizes the Three Lines Model adapted from the Institute of Internal Auditors, for risk management to assign clear risk responsibilities across the enterprise. Through coordination with operational teams, we align on cybersecurity risk classification, categorization, likelihood, and potential impact to the Company. At the highest level, our program includes multi-layered oversight by the Board of Directors and Board Committees.
Our cybersecurity and physical security controls are implemented through technical systems, policies and procedures we utilize for planning, performing, managing, assessing, innovating, and improving our security controls. To protect our information and cyber assets, we implement practices for training and screening of personnel, access management, network defense, asset configuration management, vulnerability assessment (including penetration testing), third-party security, and privacy and information protection. Our defense-in-depth strategy to protect our cyber assets and sensitive information reduces the potential severity and duration of a cybersecurity incident by leveraging security measures across various layers of the enterprise. Cross-functional executive steering committees and peer groups, with business unit and technical stakeholder participation, are maintained to support oversight, security controls development, change management, implementation, evaluation, continuous improvement, and sustainment.

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To assist in detecting cybersecurity events, we deploy security logging and monitoring, malicious code detection, and data loss protection tools. If we are the target of a cybersecurity attack, we have established processes for incident response and crisis management to triage potential incidents, determine severity, contain, and eradicate a threat. These processes require notifications to regulatory and other governmental authorities of cybersecurity events as required by law, including providing notice to investors for material cybersecurity events. To recover our systems and information, we utilize established system recovery plans, data and configuration backup strategies, and business continuity plans.
As part of our process to continuously improve, we utilize our internal audit, risk, and legal functions to evaluate security controls and risk management practices. We also engage third-party subject matter experts to independently assess our programs, processes and technical controls, as needed. For our regulated cyber assets associated with critical infrastructure, such as those within the scope of NERC and the NRC, regulatory auditors and inspectors monitor our adherence to mandatory cybersecurity requirements on a regular frequency using a variety of compliance monitoring and enforcement mechanisms.
Board Governance and Management
Our Board is actively engaged in monitoring the performance of the Company's cybersecurity program and maintains oversight of the Company’s enterprise risk program, including with respect to commodity markets, market design, enterprise security (physical and cyber), operating risks, and financial performance. While the full Board retains ultimate responsibility and oversight of the Company's cybersecurity risk management practices, the Nuclear Oversight Committee and the Audit and Risk Committee also have cybersecurity risk management as part of their charters. The Nuclear Oversight Committee is tasked with overseeing compliance with policies and procedures to manage and mitigate cybersecurity risks associated with our nuclear assets. The Audit and Risk Committee oversees policies and processes established by management to identify, assess, monitor, manage and control technology and cyber risks, among other risks. Our Chief Information Officer (CIO) and Chief Information Security Officer (CISO) provide regular reports to the Board, or one or both of its designated Committees, regarding the security of our operational and information technology programs, systems, and risks. We also report on the state of our cybersecurity program, provide key risk indicators to track performance, and schedule additional informational sessions on cybersecurity practices, as needed. Emergent matters or events are reported to the Board between scheduled meetings on an ad hoc basis through our incident response and crisis management protocols.
At the executive and management level, the Chief Administration Officer, via delegations to the cybersecurity organization, is authorized to govern and functionally oversee our security controls and services on behalf of the enterprise. Our cybersecurity organization, under the direction of the CISO who reports to the CIO, implements and provides governance and functional oversight for cybersecurity controls and services, including coordination with our corporate security function. Our CIO has over 20 years of experience with information systems, including management roles in operational security, technical design and engineering, and platform architecture cybersecurity, governance and compliance, and business continuity. Our CISO has over 20 years of experience in cybersecurity, governance and compliance, physical security and business continuity. In addition, cybersecurity risk is assessed and tracked through the Company's enterprise risk management program.
Although the risks from cyber threats have not materially affected our business strategy, results of operations, or financial condition to date, we continue to closely monitor cyber risk. Overall, our Company has implemented tactical processes for assessing, identifying, and managing material risks from cybersecurity threats to the Company including governance at the Board level and accountability in our executive management for the execution of our cyber risk management strategy and the controls designed to protect our operations. See ITEM 1A. RISK FACTORS for additional information regarding the Company’s cybersecurity risks.

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ITEM 2. PROPERTIES

The following table presents our interests in net electric generating capacity by station at December 31, 2025:

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

Midwest
Braidwood Braidwood, IL 2 Uranium Baseload
2,386 
Byron Byron, IL 2 Uranium Baseload
2,350 
LaSalle Seneca, IL 2 Uranium Baseload
2,320 
Dresden Morris, IL 2 Uranium Baseload
1,845 
Quad Cities Cordova, IL 2 75  Uranium Baseload
1,403 
Clinton Clinton, IL 1 Uranium Baseload
1,092 
Michigan Wind 2 Sanilac County, MI
50 51  (e)
Wind Intermittent 46 
Beebe Gratiot County, MI
34 51  (e)
Wind Intermittent 42 
Michigan Wind 1 Huron County, MI
46 51  (e)
Wind Intermittent 35 
Harvest 2 Huron County, MI
33 51  (e)
Wind Intermittent 30 
Harvest Huron County, MI
31 51  (e)
Wind Intermittent 26 
Beebe 1B Gratiot County, MI
21 51  (e)
Wind Intermittent 26 
Clinton Battery Storage Blanchester, OH 1 Energy Storage Peaking 5 
Total Midwest 11,606 

Mid-Atlantic
Limerick Sanatoga, PA
2 Uranium Baseload
2,315 
Calvert Cliffs Lusby, MD 2 Uranium Baseload
1,789 
Peach Bottom Delta, PA 2 50  Uranium Baseload
1,324 
Salem Lower Alloways 
Creek Township, NJ
2 42.59  Uranium Baseload
988 
Conowingo Darlington, MD 11 Hydroelectric Baseload
497 
Criterion Oakland, MD 28 51  (e)
Wind Intermittent 36 
Fair Wind Garrett County, MD 12 Wind Intermittent 30 
Fourmile Ridge Garrett County, MD 16 51  (e)
Wind Intermittent 20 
Solar Horizons Emmitsburg, MD 1 51  (e)
Solar Intermittent 8 
Solar New Jersey 3 Middle Township, NJ 4 51  (e)
Solar Intermittent 1 
Muddy Run Drumore, PA 8 Hydroelectric Intermediate 1,058 
Eddystone 3, 4 Eddystone, PA 2 Oil/Gas Peaking 760 
Perryman Aberdeen, MD 5 Oil/Gas Peaking 404 
Croydon West Bristol, PA 8 Oil Peaking 391 
Handsome Lake Kennerdell, PA 5 Gas Peaking 268 
Richmond Philadelphia, PA 2 Oil Peaking 98 
Philadelphia Road Baltimore, MD 4 Oil Peaking 60 
Eddystone Eddystone, PA 4 Oil Peaking 60 
Delaware Philadelphia, PA 4 Oil Peaking 56 
Southwark Philadelphia, PA 4 Oil Peaking 52 
Falls Morrisville, PA 3 Oil Peaking 51 

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

Moser Lower Pottsgrove Township, PA
3 Oil Peaking 51 
Chester Chester, PA 3 Oil Peaking 39 
Schuylkill Philadelphia, PA 2 Oil Peaking 30 
Total Mid-Atlantic 10,386 

ERCOT
STP
 Bay City, TX 2 44  (g)
Uranium Baseload
1,164 
Whitetail Webb County, TX 57 51  (e)
Wind Intermittent 47 
Sendero Jim Hogg and Zapata Counties, TX
39 51  (e)
Wind Intermittent 40 
Colorado Bend II Wharton, TX 3 Gas Intermediate 1,143 
Wolf Hollow II Granbury, TX 3 Gas Intermediate 1,103 
Handley 3 Fort Worth, TX 1 Gas Intermediate 375 
Handley 4, 5 Fort Worth, TX 2 Gas Peaking 870 
Total ERCOT 4,742 

New York
NMP 1
Scriba, NY 1 Uranium Baseload
620 
NMP 2
Scriba, NY 1 82  Uranium Baseload
1,055 
FitzPatrick Scriba, NY 1 Uranium Baseload
842 
Ginna Ontario, NY 1 Uranium Baseload
576 
Total New York 3,093 

Other
Antelope Valley Lancaster, CA 1 Solar Intermittent 242 
Bluestem Beaver County, OK 60 51  (e)(f)
Wind Intermittent 101 
Shooting Star Kiowa County, KS
65 51  (e)
Wind Intermittent 53 
Bluegrass Ridge King City, MO 26 51  (e)
Wind Intermittent 29 
Conception Barnard, MO 23 51  (e)
Wind Intermittent 26 
Cow Branch Rock Port, MO 23 51  (e)
Wind Intermittent 26 
Mountain Home Glenns Ferry, ID 20 51  (e)
Wind Intermittent 21 
High Mesa Elmore County, ID
19 51  (e)
Wind Intermittent 20 
Echo 1 Echo, OR 21 50.49  (e)
Wind Intermittent 17 
Sacramento PV Energy Sacramento, CA
4 51  (e)
Solar Intermittent 15 
Cassia Buhl, ID 13 51  (e)
Wind Intermittent 14 
Wildcat Lovington, NM 13 51  (e)
Wind Intermittent 14 
Echo 2 Echo, OR 9 51  (e)
Wind Intermittent 9 
Tuana Springs Hagerman, ID 8 51  (e)
Wind Intermittent 9 
Greensburg Greensburg, KS 10 51  (e)
Wind Intermittent 6 
Threemile Canyon
Boardman, OR 6 51  (e)
Wind Intermittent 5 
Loess Hills Rock Port, MO 4 Wind Intermittent 5 
Denver Airport Solar Denver, CO 1 51  (e)
Solar Intermittent 2 
Hillabee Alexander City, AL
3 Gas Intermediate 753 

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

Wyman 4 Yarmouth, ME 1 5.9  Oil Intermediate 34 
West Medway II West Medway, MA 2 Oil/Gas Peaking 189 
West Medway West Medway, MA 3 Oil Peaking 123 
Grand Prairie Alberta, Canada 1 Gas Peaking 105 
Framingham Framingham, MA 3 Oil Peaking 31 
Total Other 1,849 
Total 31,676 

__________
(a) All nuclear stations are boiling water reactors except Braidwood, Byron, Calvert Cliffs, Ginna, Salem, and STP units which are pressurized water reactors.
(b) 100%, unless otherwise indicated.
(c) Baseload units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods.
(d) Net generation capacity is stated at proportionate ownership share. For nuclear stations, capacity reflects the annual mean rating. All other facilities reflect a summer rating.
(e) Reflects the prior sale of 49% of CRP to a third party. See Note 21 — Variable Interest Entities of the Combined Notes to Consolidated Financial Statements for additional information.
(f) CRP owns 100% of the Class A membership interests and a tax equity investor owns 100% of the Class B membership interests of the entity that owns the Bluestem generating assets.
(g) Within the 44% undivided ownership interest in STP, 2% interest was recorded as held for sale as of December 31, 2025. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities.
We also own EMT, which is a liquefied natural gas import facility located on the Mystic River in Everett, MA. EMT connects to two interstate pipeline systems as well as a local gas utility's distribution system.
We maintain property insurance against loss or damage to our principal plants and properties by fire or other perils, subject to certain exceptions. For additional information on insurance specific to our nuclear facilities, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. For our insured losses, we are self-insured to the extent that any losses are within the policy deductible or exceed the amount of insurance maintained. Any such losses could have a material adverse effect on our results of operation or financial condition.

ITEM 3. LEGAL PROCEEDINGS
We are parties to various lawsuits and regulatory proceedings in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 3 — Regulatory Matters and Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements. Such descriptions are incorporated herein by these references.

ITEM 4. MINE SAFETY DISCLOSURES
Not Applicable.

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PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

CEG Parent
Our common stock is listed on the Nasdaq (trading symbol: CEG). As of January 31, 2026, there were approximately 62,892 record holders of common stock.
Stock Performance Graph
The performance graph below illustrates a four-year comparison of cumulative total returns based on an initial investment of $100 in CEG Parent common stock, as compared with the S&P 500 Stock Index and the Philadelphia Utility Sector Index (UTY), for the period 2022 through 2025.
This performance chart assumes:
• $100 invested on February 1, 2022, in CEG Parent common stock, the S&P 500 Stock Index, and the UTY, and
• All dividends are reinvested.

Value of Investment

2/1/22 12/31/22 12/31/23 12/31/24 12/31/25
CEG $100 $175 $240 $462 $734
S&P 500 $100 $86 $108 $135 $160
UTY $100 $107 $96 $116 $136

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Constellation
As of January 31, 2026, CEG Parent directly held the entire membership interest in Constellation.
Dividends
Our Board of Directors approved a 10% increase in the 2026 quarterly dividend per share compared to the 2025 quarterly dividend per share. The 2026 quarterly dividend will be $0.4265 per share.
The following table sets forth Constellation’s quarterly cash dividends per share paid during 2025 and 2024.

2025 2024

Fourth Quarter
Third Quarter
Second Quarter
First Quarter
Fourth Quarter
Third Quarter
Second Quarter
First Quarter

$ 0.3878  $ 0.3878  $ 0.3878  $ 0.3878  $ 0.3525  $ 0.3525  $ 0.3525  $ 0.3525 

First Quarter 2026 Dividend
On February 20, 2026, our Board of Directors declared a regular quarterly dividend of $0.4265 per share on our common stock for the first quarter of 2026. The dividend is payable on Friday, March 20, 2026, to shareholders of record as of 5 p.m. Eastern time on Monday, March 9, 2026.
Unregistered Sales of Equity Securities
None.
Issuer Purchases of Equity Securities
Our Board of Directors considers share buybacks to be one of several ways we can provide value to our shareholders through our deployment of capital. The first is to maintain strong investment grade metrics in addition to the pursuit of organic and inorganic growth consistent with our role as a leader in the clean energy transition. Our deployment of capital can also include the repurchase of shares if they can be acquired at attractive prices and increases to our dividend, which currently targets a 10% annual growth rate. We take into account the excise taxes imposed and other administrative costs when assessing our repurchase program. We believe that our share buyback policy is in the best interests of our Company and its shareholders and is also consistent with the interest of our other stakeholders.
Since 2023, our Board of Directors authorized the repurchase of up to $3 billion of the Company's outstanding common stock. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program. There were no share repurchases under our share repurchase program during the three months ended December 31, 2025. As of December 31, 2025, there was $593 million of remaining authority to repurchase shares of the Company's outstanding common stock.

ITEM 6. RESERVED
Not Applicable.

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ITEM 7.
MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
(Dollars in millions, unless otherwise noted)

Executive Overview
We are the nation's largest producer of clean energy and a leading 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. The following Management’s Discussion and Analysis of Financial Condition and Results of Operations summarizes results for the year ended December 31, 2025 compared to the year ended December 31, 2024. For discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K, which was filed with the SEC on February 18, 2025.

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 $22 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 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.
See Note 2 — Mergers, Acquisitions, and Dispositions and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Crane Clean Energy Center
In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center. The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies.
In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center. The loan will mature in October 2055. Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S. Treasuries of comparable maturity. Cash from operations will fund the remaining capital expenditures.

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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 of the Combined Notes to Consolidated Financial Statements 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.

Other Key Business Drivers
PJM Market Reform
On January 16, 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to address reliability and pricing within its capacity auctions. These changes aim to increase supply which is increasingly important as energy-intensive sectors expand. The proposed changes include: 1) providing revenue certainty to new generation (for instance, through a Reliability Backstop Auction to procure new, out of market capacity resources), 2) protecting residential customers from capacity price increases, 3) allocating costs to data centers through the Reliability Backstop Auctions, 4) improving load forecasting, specifically large load modeling, 5) accelerating ongoing generator interconnection studies, and 6) performing market studies to ensure the long-term viability of the PJM capacity market. While this is an emerging issue and tariff revisions have not been developed, this has the potential to impact future revenues received by our fleet.
FERC Issues Order in PJM Show Cause Proceeding
In December 2025, FERC found PJM's tariff unjust and unreasonable because it lacked sufficient clarity and consistency regarding rates, terms, and conditions of service for serving co-located load. The order also found that the existing behind-the-meter generation rules permitting netting of load and supply were no longer just and reasonable, with certain limited exceptions. FERC also directed that PJM make three new transmission services available to co-located loads: an interim, interruptible network integration transmission service, a permanent firm contract demand service, and a non-firm contract demand service. The rates, terms and conditions for these services will be developed in upcoming compliance filings and a paper hearing at FERC in 2026, as will the scope of technical studies required to pursue service of co-located load ion such services.
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. It also preserves tax credits which benefit our efforts to commercialize CCUS for natural gas power generation and maintains tax credits for geothermal and certain other investments. Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets. See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information.

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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 that were previously appropriated to support expansion of the domestic nuclear fuel cycle within the United States to improve emissions-free energy security. In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S. but allowing for a special Russian export license to be issued for individual shipments. Our nuclear fuel is obtained predominantly through long-term uranium supply and service contracts. We work with a diverse set of domestic and international suppliers years in advance to procure our nuclear fuel to support our refueling needs regardless of the risk 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.

Critical Accounting Policies and Estimates
The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements. Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods, which could have a material impact to our results of operations or financial condition. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.
Nuclear Decommissioning Asset Retirement Obligations
The AROs associated with decommissioning our nuclear un its were $12.9 billion at December 31, 2025. The authoritative guidance requires that we estimate our obligation for the future decommissioning of our nuclear generating plants. To estimate that liability, we use an internally-developed, probability-weighted, discounted cash flow model which, on a unit-by-unit basis, considers multiple decommissioning outcome scenarios.
Over the past decade, nuclear operators and third-party service providers have continued to obtain more information about costs associated with decommissioning activities. At the same time, regulators are gaining more information about decommissioning activities which could result in changes to existing decommissioning requirements. In addition, over time, it is possible that technological advances will be identified that could create efficiencies and lead to a reduction in decommissioning costs. The amount of NDT funds could also impact the timing of the decommissioning activities. Additionally, certain factors such as changes in regulatory requirements during plant operations or the profitability of a nuclear plant could impact the timing of plant retirements. These factors could result in material changes to our current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.
The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

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Decommissioning Cost Studies. We use unit-by-unit decommissioning cost studies to provide a marketplace assessment of the expected costs (in current year dollars) and timing of decommissioning activities, which are validated by comparison to current decommissioning projects within the industry and other estimates. Decommissioning cost studies are updated, on a rotational basis, for each of our nuclear units at least every five years, unless circumstances warrant more frequent updates. As part of the annual cost study update process, we evaluate newly assumed costs or substantive changes in previously assumed costs to determine if the cost estimate impacts are sufficiently material to warrant application of the updated estimates to the AROs across the nuclear fleet outside of the normal five-year rotating cost study update cycle.
Cost Escalation Factors. We use cost escalation factors to escalate the decommissioning costs from the decommissioning cost studies discussed above through the assumed decommissioning period for each of the units. Cost escalation studies, updated on an annual basis, are used to determine escalation factors, and are based on inflation indices for labor, equipment and materials, energy, LLRW disposal, and other costs. All the nuclear AROs are adjusted each year for updated cost escalation factors.
Probabilistic Cash Flow Models. Our probabilistic cash flow models include the assignment of probabilities to various scenarios for decommissioning cost levels, decommissioning approaches, and timing of plant shutdown on a unit-by-unit basis. Probabilities assigned to cost levels include an assessment of the likelihood of costs 20% higher (high-cost scenario) or 15% lower (low-cost scenario) than the base-cost scenario. The assumed decommissioning scenarios generally include the following three alternatives: (1) DECON, which assumes major decommissioning activities begin shortly after the cessation of operation, (2) Shortened SAFSTOR, which generally assumes a 30-year delay prior to onset of major decommissioning activities, and (3) SAFSTOR, which assumes the nuclear facility is placed and maintained in such condition during decommissioning, so that the nuclear facility can be safely stored and subsequently decontaminated within 60 years after cessation of operations. In each decommissioning scenario, spent fuel is transferred to dry cask storage as soon as possible until DOE acceptance for disposal.
The actual decommissioning approach selected will be determined at the time of shutdown and may be influenced by multiple factors including the funding status of the NDT funds at the time of shutdown and regulatory or other commitments.
The plant shutdown timing scenarios consider four alternatives: (1) the probability of early plant retirement, (2) the probability of operating through the original 40-year nuclear license term, (3) the probability of operating through an initial 20-year license renewal term, and (4) the probability of a second 20-year license renewal term. As power market and regulatory environment developments occur, we evaluate and incorporate, as necessary, the impacts of such developments into our nuclear ARO assumptions and estimates.
Our probabilistic cash flow models also include an assessment of the timing of DOE acceptance of SNF for disposal. We currently assume DOE will begin accepting SNF from the industry in 2040. The SNF acceptance date assumption is based on management’s estimates of the amount of time required for DOE to select a site location and develop the necessary infrastructure for long-term SNF storage. For additional information regarding SNF, see Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements.
Discount Rates. The probability-weighted estimated future cash flows for the various assumed scenarios are discounted using our specific credit-adjusted, risk-free rates (CARFR) or a AAA-rated U.S. company proxy CARFR for the units that maintain the ability to collect decommissioning costs from utility customers (former PECO and STP units). We initially recognize an ARO at fair value and subsequently adjust it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions. An ARO is not required or permitted to be remeasured for changes in the CARFR that occur in isolation. Increases in an ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO. Any decrease in the estimated undiscounted future cash flows relating to an ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR used in creating the initial ARO cost layers. If all our future nominal cash flows associated with AROs were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.9 billion to approximately $11.3 billion.

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The following table illustrates the impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of our AROs:

Change in the CARFR applied to the annual ARO update Increase (Decrease) to AROs as of December 31, 2025

2024 CARFR rather than the 2025 CARFR
$ 100 
2025 CARFR increased by 50 basis points
(100)
2025 CARFR decreased by 50 basis points
125 

ARO Sensitivities. Changes in the assumptions underlying an ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to an ARO is highly dependent on how the other assumptions may correspondingly change.
The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant:

Change in ARO Assumption Increase (Decrease) to AROs as of December 31, 2025
Cost escalation studies
Uniform increase in escalation rates of 50 basis points $ 2,175 
Probabilistic cash flow models
Increase the estimated costs to decommission the nuclear plants by 10%
750 
Increase the likelihood of the DECON scenario by 10% and decrease the likelihood of the SAFSTOR scenario by 10% (a)
100 
Shorten each unit's probability-weighted operating life assumption by 10% (b)
250 
Extend the estimated date for DOE acceptance of SNF to 2045
(75)

__________
(a) Excludes any sites in which management has committed to a specific decommissioning approach.
(b) Excludes Zion as the ARO is associated with its SNF storage facility.
See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.
Acquisition Accounting
In accordance with authoritative guidance, the assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. Changes to these estimates and assumptions could result in material changes to the fair value of assets and liabilities as of the acquisition date. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. Authoritative guidance provides that the allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.
The difference between the purchase price and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value, or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Goodwill is assigned to reporting units that are expected to benefit from the acquisition. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

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Goodwill
Goodwill is not amortized, but rather is subject to an impairment assessment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount. A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment. Our current operating segments and reporting units 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 our reportable segments. Goodwill is primarily reported within our ERCOT segment. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
For reporting units with goodwill, we perform a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value. As part of the qualitative assessment, we evaluate macroeconomic conditions, such as deterioration in general economic conditions, industry and market considerations, cost factors, and overall financial performance. If we determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required.
If the qualitative test determines that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to its carrying amount. The fair value of the reporting units is calculated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables in our industry. The income approach uses our internal forecasts to determine estimated cash flows and uses significant assumptions including, but not limited to growth rates, discount rates, customer attrition rates, useful lives, and tax rates. These assumptions are used to arrive at estimated cash flows which are inherently uncertain. Similarly, while comparables used in the market approach are determined to be a reasonable proxy for the fair value of the reporting unit, there is judgment involved and the actual fair value may be different than the fair value implied by the market approach. If the carrying amount of the reporting unit is greater than its fair value, the reporting unit’s goodwill is impaired. The goodwill impairment loss is the difference between the reporting unit’s fair value and carrying amount, and is recorded as a reduction to goodwill and a charge to operating expense.
The 2025 annual assessments indicated no impairments. Adverse regulatory actions or changes in significant assumptions could result in future impairments of our goodwill.
The acquisition of Calpine is expected to add a significant amount of goodwill to our balance sheet which will be assessed for impairment in accordance with our policy described above.
See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Unamortized Energy Contract Assets and Liabilities
UEC assets and liabilities represent the remaining unamortized balances of non-derivative energy and fuel contracts that we have acquired. The initial amount recorded represents the fair value of the contracts at the time of acquisition. The UEC assets and liabilities are amortized over the life of the contract in accordance with the expected realization of the underlying cash flows. Amortization of the unamortized energy and fuel contract assets and liabilities are recorded through Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract. See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.
Impairment of Long-Lived Assets
We regularly monitor and evaluate the carrying value of long-lived assets or asset groups for recoverability whenever events or changes in circumstances indicate that the carrying value of those assets may not be recoverable. Indicators of potential impairment may include a deteriorating business climate, including, but not limited to, declines in energy prices, condition of the asset, or plans to dispose of a long-lived asset significantly before the end of its useful life.

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The review of long-lived assets or asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. Forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. The lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generating units and the hedging strategies related to those units. The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group), given the interdependency of cash flows generated from the customer supply and risk management activities within each region. In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets.
On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value. The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the long-lived asset or asset group. This includes significant assumptions of the estimated future cash flows generated by the long-lived assets or asset groups and market discount rates. Events and circumstances often do not occur as expected, resulting in differences between prospective financial information and actual results, which may be material. The determination of fair value is driven by both internal assumptions that include significant unobservable inputs, such as revenue and generation forecasts, projected capital investments, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.
Depreciable Lives of Property, Plant, and Equipment
We have significant investments in electric generating assets. These assets are generally depreciated on a straight-line basis, using the group, composite or unitary methods of depreciation. The group approach is typically for groups of similar assets that have approximately the same useful lives and the composite approach is used for heterogeneous assets that have different lives. Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group. The estimation of asset useful lives requires management judgment, informed by formal depreciation studies of historical asset retirement experiences conducted at least every five years and other factors, including expected energy market conditions, operating costs, and capital investment requirements. Management reassesses these estimates when events or changes in circumstances indicate that revisions may be necessary. When a determination has been made that an asset's current estimated useful life will be shortened or extended, depreciation provisions will be adjusted which could have a material impact on future results of operations.
See Note 1 — Basis of Presentation and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated useful lives of the property, plant and equipment.
Accounting for Derivative Instruments
We use derivative instruments to manage commodity price risk, foreign currency exchange risk and interest rate risk related to ongoing business operations. Our derivative activities are in accordance with our RMP. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
We account for derivative financial instruments under the applicable authoritative guidance. Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities. Changes in management’s assessment of contracts and the liquidity of their markets, and changes in

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authoritative guidance, could result in previously excluded contracts becoming in scope of existing authoritative guidance.
All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS. Derivatives executed for economic hedging purposes are recorded at fair value through earnings. NPNS transactions are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment as to whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.
Commodity Contracts. Identification of a commodity contract as an economic hedge requires us to determine that the contract is in accordance with the RMP. We make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and expected changes in fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, we categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.
Derivative contracts are traded in both exchange-based and non-exchange-based markets. Exchange-based derivatives that are valued using unadjusted quoted prices in active markets are generally categorized in Level 1 in the fair value hierarchy.
Certain derivative pricing is verified using indicative price quotations available through brokers or over-the-counter, online exchanges. The price quotations reflect the average of the mid-point of the bid-ask spread from observable markets that we believe provide the most liquid market for the commodity. The price quotations are reviewed and corroborated to ensure the prices are observable and representative of an orderly transaction between market participants. Our derivatives are traded predominantly at liquid trading points. The remaining derivative contracts are valued using models that consider inputs such as contract terms, including maturity, and market parameters, and assumptions of the future prices of commodities, interest rates, volatility, credit worthiness and credit spread. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the model inputs are generally observable. Such instruments are categorized in Level 2.
For derivatives that trade in less liquid markets with limited pricing information, the model inputs generally would include both observable and unobservable inputs and are categorized in Level 3.
We consider non-performance risk, including credit risk in the valuation of derivative contracts, and both historical and current market data in our assessment of non-performance risk. The impacts of non-performance and credit risk to date have not been material to the consolidated financial statements.
See ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK and Note 15 — Derivative Financial Instruments and Note 17 — Fair Value of Financial Assets and Liabilities of the Combined Notes to Consolidated Financial Statements for additional information regarding derivative instruments.
Defined Benefit Pension and Other Postretirement Employee Benefits
Approximately half of our employees participate in the defined benefit pension and OPEB plans that we sponsor. Measuring plan obligations and costs involves various factors, including valuation assumptions and inputs and accounting policy elections. When developing the required assumptions, we consider historical information as well as future expectations. The measurement of these benefit obligations and costs is affected by several assumptions including the discount rate, the long-term expected rate of return on plan assets, the anticipated rate of increase of health care costs, our contributions, the rate of compensation increases, and the long-term expected investment rate credited to employees of certain plans, among others. The assumptions are updated annually and during any interim remeasurement.
Pension and OPEB plan assets include U.S. and international equity securities, fixed income securities, and alternative investments such as real assets, private equity, private credit, and hedge funds.
Expected Rate of Return on Plan Assets. To determine the EROA, we consider forecasted future long-term capital market performance, weighted by our target asset class allocations. We calculate the expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year,

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considering anticipated contributions and benefit payments to be made during the year. The MRV for pension and OPEB plan assets is based on either fair value or a calculated value that systematically and rationally recognizes changes in fair value over multiple years. For the majority of pension plan assets, we use a calculated value that adjusts for 20% of the difference between fair value and expected MRV, resulting in less volatile expected asset returns to be recognized as a component of pension cost from year to year. For OPEB plan assets and certain pension plan assets, we use fair value to calculate the MRV.
Discount Rate. Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality corporate bonds with similar maturities to the pension and OPEB obligations. These spot rates discount the estimated future benefit distribution amounts for the pension and OPEB plans. The discount rate is the single level rate that matches the spot rate curve. We utilize an analytical tool developed by our actuaries to determine these rates.
Mortality. The mortality assumption includes a base table for the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. Upon remeasurement as of December 31, 2024 and 2025, we utilized the mortality tables and projection scales released by the SOA.
Sensitivity to Changes in Key Assumptions. The following table illustrates the effects of changing certain of the actuarial assumptions reflected above and as discussed in Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant:

Pension OPEB Change in Assumption
Increase / (Decrease)
Actuarial Assumption Pension OPEB Total
Change in 2026 cost:

Discount rate (a)
5.38  % 5.30  % 0.5  % $ (19) $ 2  $ (17)
5.38  % 5.30  % (0.5) % 19  3  22 
EROA 6.50  % 6.00  % 0.5  % (36) (3) (39)
6.50  % 6.00  % (0.5) % 36  3  39 
Change in benefit obligation as of December 31, 2025:

Discount rate (a)
5.38  % 5.30  % 0.5  % (328) (63) (391)
5.38  % 5.30  % (0.5) % 356  69  425 
__________
(a) Generally, the discount rate will have a larger impact on the pension and OPEB cost and obligation as the rate moves closer to 0%. Therefore, the sensitivities above cannot be extrapolated for larger changes in the discount rate. Additionally, our liability-driven hedging investment strategy for our pension asset portfolio is not reflected in the sensitivities shown, which do not account for the offsetting impact that discount rate changes may have on pension asset returns.
See Note 1 — Basis of Presentation and Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information regarding the accounting for the defined benefit pension and OPEB plans.
Taxation
Significant management judgment is required in determining our provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We account for uncertain income tax positions using a benefit recognition model with a two-step approach, including a more-likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement. Management evaluates each position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements.
We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax

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assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate our inability to realize our deferred tax assets. Based on the combined assessment, we record valuation allowances for deferred tax assets when it is more likely than not such benefit will not be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, our forecasted financial condition and results of operations, failure to successfully implement tax planning strategies, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.
Accounting for Loss Contingencies
In the preparation of our financial statements, we make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved and may have a material impact to our results of operations or financial condition.
Environmental Costs. Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which we will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities. These matters, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.
Other, Including Personal Injury Claims. For accidents we maintain insurance coverage for general liability, automotive liability, workers’ compensation, and personal injury claims and are self-insured to the extent that losses are within policy deductibles or exceed the amount of insurance maintained. We have reserves for both open claims asserted, and an estimate of claims incurred but not reported (IBNR). The IBNR reserve is estimated based on actuarial assumptions and analysis and is updated annually. Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated. Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition.
Revenue Recognition
Sources of Revenue and Determination of Accounting Treatment. We earn revenue from various business activities including competitive sales of power, natural gas, and other energy-related products and sustainable solutions.
The accounting treatment for revenue recognition is based on the nature of the underlying transaction and applicable authoritative guidance. We primarily apply the Revenue from Contracts with Customer, Government Assistance, and Derivatives and Hedging guidance to recognize revenue, as discussed in more detail below.
Revenue from Contracts with Customers. We recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas and other energy-related products and sustainable solutions are provided to the customer. Transactions within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with RTOs and ISOs.
The determination of our retail power and natural gas sales to individual customers is based on systematic readings of customer meters, generally monthly. Energy delivered to customers that has not yet been billed as of the reporting period is estimated and corresponding unbilled revenue is recorded. The measurement of unbilled revenue is based upon individual customer meter readings, forecasted volumes, and applicable rates. See Note 1 — Basis of Presentation and Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information.

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Government Assistance. Our existing nuclear plants are eligible for federal government incentives including transferable tax credits for qualifying electric production volumes. The nuclear PTC is subject to legislative and regulatory changes, which can affect the availability and amount of credits. Repeal or significant reduction or modification of the PTC could have a material impact on our financial performance depending on gross receipts received by our nuclear units each year. Further, the nuclear PTC continues to be the subject of additional guidance, from the U.S. Treasury and IRS, and may materially impact the total amount of benefits we receive. Absence of prescriptive guidance requires the application of judgment in determining annual gross receipts, a primary component in the determination of the credit. We closely monitor developments in relevant tax laws and regulations to anticipate and mitigate potential risks. Given that the nuclear PTC is a function of annual gross receipts, quarterly results rely on forecasted gross receipts for the fiscal year. Energy prices are volatile and are impacted by various factors beyond our control. Significant deviations in market prices from those we’ve forecasted could materially impact our quarterly recognition of nuclear PTC revenues as we progress through the calendar year. See ITEM 1. BUSINESS – Price and Supply Risk Management for additional information on how we mitigate market price risk. See Note 6 — Government Assistance of the Combined Notes to the Consolidated Financial Statements for additional information.
Derivative Revenues. We record revenues and expenses using the fair value method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Derivative revenues and expenses include inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

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 year ended December 31, 2025 compared to 2024. For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations below.

For the Years Ended December 31, $ Change

2025 2024
GAAP Net Income (Loss) Attributable to Common Shareholders
$ 2,319  $ 3,749  $ (1,430)

Adjusted (non-GAAP) Operating Earnings. We utilize Adjusted (non-GAAP) Operating Earnings (and/or its per share equivalent) in our internal analysis, and in communications with investors and analysts, as a consistent measure for comparing our financial performance and discussing the factors and trends affecting our business. The presentation of Adjusted (non-GAAP) Operating Earnings is intended to complement and should not be considered an alternative to, nor more useful than, the presentation of GAAP Net Income.

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The table below provides a reconciliation of GAAP Net Income to Adjusted (non-GAAP) Operating Earnings. Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.
Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part, which may result in an effective tax rate that differs from the marginal rate. The marginal statutory income tax rate was 25.6% and 25.5% for the years ended December 31, 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 year ended December 31, 2025 compared to 2024.

For the Years Ended December 31,
2025 2024
Earnings Per Share (a)
Earnings Per Share (a)

GAAP Net Income (Loss) Attributable to Common Shareholders
$ 2,319  $ 7.40  $ 3,749  $ 11.89 
Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes $243 and $346, respectively) (b)
709  2.26  (1,026) (3.25)
Plant Retirements and Divestitures (net of taxes $5 and $9, respectively)
15  0.05  28  0.09 
Decommissioning-Related Activities (net of taxes $535 and $244, respectively) (c)
(254) (0.81) (50) (0.16)
Pension & OPEB Non-Service (Credits) Costs (net of taxes $13 and $2, respectively)
38  0.12  5  0.02 
Acquisition-Related Costs (net of taxes $4 and $2, respectively) (d)
97  0.31  6  0.02 
Change in Environmental Liabilities (net of taxes $2 and $22, respectively)
5  0.02  65  0.21 
Separation Costs (net of taxes $— and $3, respectively)
—  —  9  0.03 
ERP System Implementation Costs (net of taxes $— and $3, respectively)
—  —  8  0.02 

Income Tax-Related Adjustments (e)
22  0.07  (52) (0.17)
Noncontrolling Interests (f)
(7) (0.02) (7) (0.02)
Adjusted (non-GAAP) Operating Earnings
$ 2,944  $ 9.39  $ 2,735  $ 8.67 
__________
(a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 314 million and 315 million for the years ended December 31, 2025 and 2024, 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) Reflects acquisition-related costs associated with the Calpine merger. The majority of these expenses are not tax deductible.
(e) Adjustment to deferred income taxes due to changes in forecasted apportionment.
(f) Represents elimination of the noncontrolling interest portion of certain adjustments included above.

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Results of Operations

2025 2024 $ Change

Operating revenues $ 25,533  $ 23,568  $ 1,965 
Operating expenses
Purchased power and fuel 14,681  11,419  3,262 
Operating and maintenance 6,159  6,159  — 
Depreciation and amortization 985  1,123  (138)
Taxes other than income taxes 622  586  36 
Total operating expenses 22,447  19,287  3,160 
Gain (loss) on sales of assets and businesses
—  71  (71)
Operating income (loss)
3,086  4,352  (1,266)
Other income and (deductions)
Interest expense, net (511) (506) (5)
Other, net 936  670  266 
Total other income and (deductions) 425  164  261 
Income (loss) before income taxes 3,511  4,516  (1,005)
Income tax (benefit) expense
1,187  774  413 
Equity in income (losses) of unconsolidated affiliates (1) (4) 3 
Net income (loss) 2,323  3,738  (1,415)
Net income (loss) attributable to noncontrolling interests
4  (11) 15 
Net income (loss) attributable to common shareholders $ 2,319  $ 3,749  $ (1,430)

Year Ended December 31, 2025 Compared to Year Ended December 31, 2024. The variance in Net income (loss) attributable to common shareholders was unfavorable by $1,430 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.

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For the year ended December 31, 2025 compared to 2024, Operating revenues were as follows:

2025 vs. 2024
2025 2024 $ Change % Change

Mid-Atlantic $ 6,487  $ 5,522  $ 965  17.5  %
Midwest 5,804  4,805  999  20.8  %
New York 2,190  2,050  140  6.8  %
ERCOT 1,904  1,550  354  22.8  %

Other Power Regions 5,583  5,506  77  1.4  %
Total reportable segment electric revenues 21,968  19,433  2,535  13.0  %
Other 4,370  3,819  551  14.4  %
Unrealized gains (losses) (a)
(805) 316  (1,121)
Total Operating revenues $ 25,533  $ 23,568  $ 1,965  8.3  %
__________
(a) % Change in unrealized gains (losses) is not a meaningful measure.
Sales and Supply Sources. Our sales and supply volumes (GWhs) by region are summarized below:

2025 vs. 2024
(GWhs)
2025 2024 Change
% Change
Nuclear Generation (a)

Mid-Atlantic 52,914  52,898  16  —  %
Midwest 93,866  95,321  (1,455) (1.5) %
New York
26,339  25,134  1,205  4.8  %
ERCOT 9,571  8,358  1,213  14.5  %
Total Nuclear Generation 182,690  181,711  979  0.5  %

Natural Gas, Oil and Renewables (a)

Mid-Atlantic 1,966  2,137  (171) (8.0) %
Midwest 1,121  1,116  5  0.4  %

ERCOT
12,933  14,778  (1,845) (12.5) %

Other Power Regions
6,234  8,692  (2,458) (28.3) %
Total Natural Gas, Oil and Renewables 22,254  26,723  (4,469) (16.7) %

Purchased Power
Mid-Atlantic
17,140  15,729  1,411  9.0  %
Midwest 1,777  928  849  91.5  %

ERCOT 3,028  3,249  (221) (6.8) %

Other Power Regions
42,054  41,077  977  2.4  %
Total Purchased Power 63,999  60,983  3,016  4.9  %

Total Supply/Sales by Region
Mid-Atlantic 72,020  70,764  1,256  1.8  %
Midwest 96,764  97,365  (601) (0.6) %
New York
26,339  25,134  1,205  4.8  %
ERCOT
25,532  26,385  (853) (3.2) %

Other Power Regions
48,288  49,769  (1,481) (3.0) %
Total Supply/Sales
268,943  269,417  (474) (0.2) %

__________
(a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

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Nuclear Fleet Capacity Factor. The following table presents nuclear fleet operating data for our plants that reflects our ownership percentage for stations operated by us and excludes Salem and STP, which are operated by PSEG and STPNOC, respectively. The nuclear fleet capacity factor presented in the table is defined as the ratio of the actual output of a unit (or combination of units) over a period of time to its output if the unit had operated at net monthly mean capacity for that time period. We consider capacity factor to be a useful measure to analyze the nuclear fleet performance between periods. We have included the analysis below as a complement to the financial information provided in accordance with GAAP. However, these measures are not a presentation defined under GAAP and may not be comparable to other companies’ presentations or be more useful than the GAAP information provided elsewhere in this report.

2025 2024
Nuclear fleet capacity factor 94.7  % 94.6  %
Refueling outage days 215  230 
Non-refueling outage days 57  36 

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.

2025 vs. 2024
Location (Region) 2025 2024 $ Change % Change
PJM West (Mid-Atlantic) $ 50.19  $ 33.74  $ 16.45  48.8  %
ComEd (Midwest) 36.62  25.50  11.12  43.6  %
Central (New York) 56.31  34.12  22.19  65.0  %
North (ERCOT) 32.94  26.97  5.97  22.1  %
Southeast Massachusetts (Other) (a)
68.56  41.70  26.86  64.4  %

__________
(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 years ended December 31, 2025 and 2024.

2025 vs. 2024
Location (Region) 2025 2024 $ Change % Change
Eastern Mid-Atlantic Area Council (Mid-Atlantic)
$ 179.79  $ 51.89  $ 127.90  246.5  %
ComEd (Midwest) 169.50  31.09  138.41  445.2  %
Rest of State (New York) 134.56  106.44  28.12  26.4  %
Southeast New England (Other) 446.97  581.69  (134.72) (23.2) %

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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 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 years ended December 31, 2025 and 2024 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

2025 vs. 2024
State (Region) (a)
2025 2024 $ Change % Change
New Jersey (Mid-Atlantic) (b)
$ 10.00  $ 9.98  $ 0.02  0.2  %
Illinois (Midwest) (c)
4.59  5.60  (1.01) (18.0) %
New York (New York) 15.64  18.27  (2.63) (14.4) %

__________
(a) See ITEM 1. BUSINESS, Environmental Matters and Regulation for additional information on the plants receiving payments through state programs.
(b) The New Jersey ZEC program concluded in May 2025.
(c) See Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZEC program.
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 ($7.58) and $8.05 for the years ended December 31, 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 year ended December 31, 2025 compared to 2024:

2025 vs. 2024
2025 2024 $ Change % Change
Nuclear PTC revenue (a)
$ 320  $ 2,080  $ (1,760) (84.6) %
State-sponsored programs net revenue (b)
(125) (50) (75) 150.0  %

__________
(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.

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For the year ended December 31, 2025 compared to 2024, changes in Operating revenues by segment were approximately as follows:

2025 vs. 2024
$ Change % Change
Description
Mid-Atlantic $ 965  17.5  % • favorable retail load revenue of $700 primarily due to higher contracted energy prices and load volumes
• favorable realized economic hedges of $450 due to settled prices relative to hedged prices
• favorable wholesale load revenue of $325 primarily due to higher contracted energy prices; partially offset by
• unfavorable activity due to absence of nuclear PTC revenue of $515 due to higher energy and capacity prices in the current year

Midwest 999  20.8  % • favorable net generation and wholesale load revenue of $730 primarily due to higher energy prices, partially offset by lower generation volumes
• favorable realized economic hedges of $720 due to settled prices relative to hedged prices
• favorable retail load revenue of $520 primarily due to higher contracted energy prices and load volumes
• favorable net capacity revenue of $195 primarily due to higher prices
• favorable net ZEC revenue of $130 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years; partially offset by
• unfavorable activity due to lower nuclear PTC revenue of $1,090 and lower net CMC program revenue of $210 due to higher energy and capacity prices in the current year

New York 140  6.8  % • favorable net generation revenue of $255 associated with the sale of generation volumes relative to purchase power to supply load primarily due to higher energy prices and generation volumes
• favorable retail load revenue of $110 primarily due to higher contracted energy prices
• favorable ZEC program revenue of $105 primarily due to the absence of the refund associated with nuclear PTC revenue; partially offset by
• unfavorable activity due to absence of nuclear PTC revenue of $150 due to higher energy prices in the current year
• unfavorable realized economic hedges of $185 due to settled prices relative to hedged prices

ERCOT 354  22.8  % • favorable realized economic hedges of $150 due to settled prices relative to hedged prices
• favorable wholesale load revenue of $120 primarily due to higher contracted energy prices, partially offset by lower load volumes
• favorable retail load revenue of $75 primarily due to higher contracted energy prices and load volumes

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2025 vs. 2024
$ Change % Change
Description
Other Power Regions 77  1.4  % • favorable retail load revenue of $50 primarily due to higher contracted energy prices

Other 551  14.4  % • favorable retail gas revenue of $410 primarily due to higher gas prices
• favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $160 primarily due to higher energy prices

Unrealized gains or losses (a)(b)
(1,121) • losses on economic hedging activities of $805 in 2025 compared to gains of $316 in 2024

Total $ 1,965  8.3  %

__________
(a) % Change in unrealized gains or losses is not a meaningful measure.
(b) See Note 15 — 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 region, nuclear fleet capacity factor, capacity prices, and electricity prices.
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 region.
For the year ended December 31, 2025 compared to 2024, Purchased power and fuel expense were as follows:

2025 vs. 2024
2025 2024 $ Change % Change

Mid-Atlantic $ 3,076  $ 2,442  $ 634  26.0  %
Midwest 2,102  1,603  499  31.1  %
New York 590  597  (7) (1.2) %
ERCOT 767  503  264  52.5  %

Other Power Regions 4,764  4,238  526  12.4  %
Total electric purchased power and fuel 11,299  9,383  1,916  20.4  %
Other 3,569  2,997  572  19.1  %
Unrealized losses (gains) (a)
(187) (961) 774 
Total purchased power and fuel $ 14,681  $ 11,419  $ 3,262  28.6  %

__________
(a) % Change in unrealized losses (gains) is not a meaningful measure.
For the year ended December 31, 2025 compared to 2024, changes in Purchased power and fuel expense by segment were approximately as follows:

2025 vs. 2024
$ Change % Change
Description
Mid-Atlantic $ 634  26.0  % • unfavorable cost of $660 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, as well as higher prices associated with net capacity costs; partially offset by
• favorable realized economic hedges of $105 due to settled prices relative to hedged prices

Midwest 499  31.1  % • unfavorable cost of $460 associated with purchased power to supply load, net of generation, primarily due to higher transmission costs and energy prices

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2025 vs. 2024
$ Change % Change
Description
New York (7) (1.2) % • no individually significant drivers

ERCOT 264  52.5  % • unfavorable cost of $210 associated with purchased power to supply load, net of generation, primarily due to higher energy prices
• unfavorable realized economic hedges of $60, due to settled prices relative to hedged prices

Other Power Regions 526  12.4  % • unfavorable purchased power of $1,330 primarily due to lower generation volumes driven by the retirement of Mystic Units 8 and 9, higher energy prices, and higher ancillary charges; partially offset by
• favorable realized economic hedges of $835 due to settled prices relative to hedged prices

Other 572  19.1  % • unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $315 primarily due to higher gas prices
• unfavorable purchases in the United Kingdom, inclusive of realized economic hedges, of $190 primarily due to higher energy prices
• unfavorable fair value adjustments related to gas imbalances of $65

Unrealized gains or losses (a)(b)
774  • gains on economic hedging activities of $187 in 2025 compared to gains of $961 in 2024

Total $ 3,262  28.6  %
__________
(a) % Change in unrealized gains or losses is not a meaningful measure.
(b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.
Other, net was favorable for the year ended December 31, 2025 compared to 2024, due to activity described in the table below:

Income (Deductions)

For the Years Ended December 31,
2025 2024
Decommissioning-related activities (a)
$ 1,112  $ 567 

Net unrealized gains (losses) from equity investments (b)
(304) 11 

Other
128  92 
Other, net $ 936  $ 670 
__________
(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 10 — Asset Retirement Obligations and Note 22 — 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 33.8% and 17.1% for the years ended December 31, 2025 and 2024, respectively. The change in effective tax rate in 2025 compared to 2024 is primarily due to the decrease in nuclear PTCs generated, which are not taxable, as well as higher qualified NDT fund income that is taxed at a higher rate. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

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Liquidity and Capital Resources
For discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to the Liquidity and Capital Resources section of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K which was filed with the SEC on February 18, 2025.
All results included throughout the liquidity and capital resources section are presented on a GAAP basis.
Our operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from bank borrowings and other capital market sources. Our business is capital intensive and requires considerable capital resources. We regularly evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade credit ratings while meeting our cash needs to fund capital requirements, including funding construction expenditures, retiring debt, paying dividends, funding pension and OPEB obligations, and investing in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $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 16 — 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 years ended December 31, 2025 and 2024, respectively:

For the Years Ended December 31,
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 4,237  (2,464) 6,701 
Investing activities (3,198) 7,428  (10,626)
Financing activities (420) (2,289) 1,869 
Net increase (decrease) in cash, restricted cash, and cash equivalents
619  2,675  (2,056)
Cash, restricted cash, and cash equivalents at end of period
$ 3,748  $ 3,129  $ 619 

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Net Cash Provided By (Used In) Operating Activities
Cash provided by operating activities was $4,237 million for the year ended December 31, 2025, compared to cash used in operating activities of ($2,464) million for the year ended December 31, 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 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.
Net Cash Provided By (Used In) Investing Activities
Cash used in investing activities was ($3,198) million for the year ended December 31, 2025, compared to cash provided by investing activities of $7,428 million for the year ended December 31, 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 Statements 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 ($420) million for the year ended December 31, 2025, compared to cash used in financing activities of ($2,289) million for the year ended December 31, 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 primarily relates to repurchases of common stock during each period. See Note 16 — Debt and Credit Agreements and Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.
Debt Issuances and Redemptions
See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our long-term debt. Debt activity for 2025 and 2024 was as follows:
During 2025, the following long-term debt was issued (redeemed):

Type Interest Rate Maturity Amount
2025 Senior Notes 3.25% June 2025 $ (900)
West Medway II Nonrecourse Debt 1-month SOFR + 3.225% - 3.350%
March 2026 (52)
CR Nonrecourse Debt 3-month SOFR + 2.00% - 2.25% (a)
December 2027 (34)
Continental Wind Nonrecourse Debt 6.00% February 2033 (31)
Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26)
Tax Exempt Pollution Control Revenue Bonds 4.45% March 2025 (23)
RPG Nonrecourse Debt 4.11% March 2035 (7)
Energy Efficiency Project Financing (b)
2.20% - 4.96% December 2025 - March 2026 (3)
Total long-term debt issued (redeemed)
$ (1,076)

__________
(a) The interest rate for long-term debt redemptions prior to October 2025 were based on SOFR + 2.25%. Beginning in October 2025, these redemptions are based on SOFR + 2.00%.
(b) Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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During 2024, the following long-term debt was issued (redeemed):

Type Interest Rate Maturity Amount
Green Senior Notes (a)
5.75% March 2054 $ 900 
Energy Efficiency Project Financing (b)
2.20% - 5.51% March 2025 - April 2028 21 
CR Nonrecourse Debt 3-month SOFR + 2.25% (c)
December 2027 (22)
Continental Wind Nonrecourse Debt 6.00% February 2033 (28)
West Medway II Nonrecourse Debt 1-month SOFR + 3.225%
March 2026 (36)
Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26)
RPG Nonrecourse Debt 4.11% March 2035 (9)
Total long-term debt issued (redeemed)
$ 800 

__________
(a) Issued to finance or refinance, in whole or in part, one or more new or existing Eligible Projects. Eligible Projects are defined as investments and expenditures made by us in the 24 months prior to or after the issuance of the notes within the following eligible green categories: clean generation fleet, clean hydrogen, energy storage, and clean commercial offerings.
(b) Represents funding to install energy conservation measures. The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.
(c) The interest rate for long-term debt redemptions prior to July 2024 were based on SOFR + 2.76%. Beginning in July 2024 these redemptions are based on SOFR + 2.25%.
Calpine Acquisition
In January 2026, upon completion of the acquisition of Calpine, we assumed all of Calpine's outstanding obligations including approximately $12.6 billion of debt composed of approximately $7.6 billion of long-term debt and approximately $5 billion of various project financing arrangements. The acquisition of Calpine had the following impacts on our liquidity position:
• The purchase price included cash consideration of approximately $4.5 billion which was funded through cash on hand from normal operating activities at the time of acquisition.
• We assumed approximately $7.6 billion of long-term debt including senior unsecured and secured notes, and corporate term loans. In December 2025, we commenced private exchange offers and related consent solicitations (“Exchange Offers”) with respect to certain outstanding debt of Calpine. Pursuant to the Exchange Offers, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes. Using the proceeds from our January 2026 bond issuance, as described more fully below, along with cash on hand and short-term debt, we repaid Calpine corporate term loans totaling $2.5 billion immediately after the acquisition closing and repaid additional Calpine senior secured first lien notes totaling $1.25 billion in February 2026. Following the debt exchange and redemptions discussed, approximately $1.5 billion of long-term Calpine corporate debt remains outstanding, which matures primarily in March 2028. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
• We assumed approximately $5 billion of various project financing arrangements including:
◦ Calpine Construction Finance Company, L.P. (CCFC) term loan, a first lien senior secured facility with $2.1 billion outstanding at acquisition. The CCFC term loan matures July 2030 and is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants.
◦ Geysers Power Company, LLC (GPC) term loan and credit facility, a first lien senior secured term loan facility, with approximately $1.35 billion and $45 million of borrowings outstanding under the term loan and credit facility, respectively, at acquisition. The GPC term loan and credit facility mature May 2029. The GPC term loan and credit facility is secured by certain real and personal property of GPC and subsidiaries primarily consisting of the Geysers Assets.

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◦ Nova Power, LLC (Nova Power) credit agreement, comprising credit facilities intended to finance a portion of the cost of the development, construction and operation of the Nova Power battery storage project. These facilities include a first lien term loan with $591 million outstanding at acquisition and letter of credit facilities. The Nova Power credit agreement matures September 2031 and is secured by Nova Power's real and personal property.
◦ Greenfield LP (Greenfield) loan facility which includes a term loan with $342 million outstanding at acquisition and several letters of credit facilities. The Greenfield loan facility matures November 2030 and is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada.
◦ Pin Oak Creek Energy Center loan pursuant to the TEF with lender, PUCT, with an outstanding amount of $230 million at acquisition. The proceeds were used to finance anticipated eligible costs for the development, construction, and installation of Pin Oak Creek Energy Center in Texas. The loan will mature in October 2045.
◦ Calpine Development Holdings, LLC Revolver (CDHI Revolver) with total capacity of approximately $1.2 billion and borrowings totaling $319 million outstanding at acquisition. The CDHI Revolver matures March 2028.
• During 2025, we amended our RCF to increase the capacity from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition. As a result, Calpine's revolving credit facility and commodity linked revolver were both paid off and terminated at the time of acquisition. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
• We issued senior unsecured notes in January 2026 totaling $2.75 billion, the proceeds from which were used to retire certain outstanding indebtedness of Calpine following completion of the Calpine acquisition. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
• In addition to the Calpine revolving credit facility and commodity linked revolver referenced above, we assumed credit facilities totaling approximately $2.3 billion of capacity, which is reduced by outstanding borrowings under the GPC term loan facility and CDHI Revolver totaling $364 million. At the time of the acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion. These facilities consist of secured and unsecured Calpine facilities and project facilities including the CDHI Revolver.
• We assumed Calpine's accounts receivable sales program with a financial institution which allows for the sale of, at a discount, up to $500 million of certain Calpine receivables. The program is set to mature November 2026. At the time of acquisition, there was $399 million of accounts receivable sold into the program outstanding.
Dividends
Quarterly dividends declared by our Board of Directors during 2025 and for the first quarter of 2026 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 
First Quarter of 2026
February 20, 2026 March 9, 2026 March 20, 2026 $ 0.4265 

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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 December 31, 2025, we have access to facilities with aggregate bank commitments of $9.5 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 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 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 used to close on our 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 security 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 December 31, 2025 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of December 31, 2025, we had $7.4 billion of available capacity under our credit facilities and $3.6 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 December 31, 2025, we would have been required to provide incremental collateral estimated to be approximately $2.7 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 15 — Derivative Financial Instruments and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.
Capital Expenditures
Our most recent estimate of capital expenditures, inclusive of Calpine, is approximately $5.7 billion and $4.7 billion for 2026 and 2027, respectively. Approximately 29% of projected capital expenditures is for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply. Additionally, the above estimates of capital expenditures include $3.9 billion of growth capital expenditures, including our planned restart of Crane, nuclear uprates, co-location infrastructure, and license renewals. The remaining amounts primarily reflect additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages). See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict.
Planned additions, upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory actions, impacts of inflation, changes in the cost of materials and labor, and financing costs.
We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings.

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Pension and Other Postretirement Benefits
We consider various factors when making qualified pension funding decisions, including actuarially determined minimum contribution requirements under ERISA, contributions required to avoid benefit restrictions and at-risk status as defined by the Pension Protection Act, and management of the pension obligation. The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification). The contributions in the table below reflect a funding strategy to make annual contributions to offset the growth of the liability. Unlike the qualified pension plans, our non-qualified pension 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.
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. See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and OPEB contributions.
Cash Requirements for Other Financial Commitments
The following table summarizes our projected cash payments as of December 31, 2025 under existing financial commitments with fixed or minimum payments required:

2026 Beyond 2026
Total Time Period
Long-term debt $ 92  $ 7,311  $ 7,403  2026 - 2054

Interest payments on long-term debt (a)
415  5,377  5,792  2026 - 2054

Operating leases (b)
56  353  409  2026 - 2056

Purchase power obligations (c)
772  1,199  1,971  2026 - 2043

Fuel purchase agreements (d)
1,742  9,087  10,829  2026 - 2040

Other purchase obligations (e)
1,873  2,825  4,698  2026 - 2057

SNF obligation —  1,426  1,426  2026 - 2040

Pension contributions (f)
162  650  812  2026 - 2031

Cash consideration for the acquisition of Calpine (g)
4,500  —  4,500  2026 
Total cash requirements $ 9,612  $ 28,228  $ 37,840 

__________
(a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2025 and do not reflect anticipated future refinancing, early redemptions, or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2025.
(b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $48 million and $181 million for 2026 and beyond 2026, respectively and $229 million in total.
(c) Purchase power obligations primarily include REC purchases and capacity payments that are not unit contingent.
(d) Represents commitments to purchase nuclear fuel and related services and natural gas-related transportation and capacity.
(e) Represents the future estimated value at December 31, 2025 of the cash flows associated with all contracts, both cancellable and non-cancellable, entered into with third parties for the provision of services and materials, entered into in the normal course of business not specifically reflected elsewhere in this table. These estimates are subject to significant variability from period to period.
(f) These amounts represent our expected contributions to our qualified pension plans.
(g) In January 2026, we acquired all of the outstanding equity interest of Calpine in a cash and stock transaction. The aggregate purchase price included approximately $4.5 billion in cash. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Combined Consolidated for additional information.

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See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on our other commitments potentially triggered by future events. Additionally, see below for where to find additional information regarding the financial commitments in the table above in the Combined Notes to Consolidated Financial Statements.

Item Location within Combined Notes to Consolidated Financial Statements
Long-term debt Note 16 — Debt and Credit Agreements
Interest payments on long-term debt Note 16 — Debt and Credit Agreements
Operating leases Note 11 — Leases
SNF obligation Note 18 — Commitments and Contingencies
Pension contributions Note 14 — Retirement Benefits

Accounts Receivable Facility
We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain customer accounts receivables. See Note 16 — 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 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. During 2025, we increased the capacity of our RCF from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition in January 2026. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.
Capital Structure
At December 31, 2025, our capital structure consisted of the following:

Percentage of Capital Structure
Commercial paper and notes payable 7  %
Long-term debt 31  %

Member’s equity 62  %

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

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