CEG 10-K & 10-Q changes, risk factors and insider trading

We operate in a complex market and regulatory environment that involves significant risks, many of which are beyond our direct control. Such risks, which could negatively affect our consolidatedresults of operations or financial statements,condition, fall primarily under the categories below:

•emerging technologies andtechnologies, business models, and demand driven by industry trends, including those related to climate change mitigation and transition to a low-carbonlow-emissions economy.

•the safe, secure and effective operation of our nuclear facilities and the ability to effectively manage the associatednuclear decommissioning obligations,

Risks related to the proposed acquisition of Calpine primarily include:

•no assurance of the dividends at the current rate post-acquisition, reduced ownership and voting power for current shareholders, and potential dilution to earnings per share and significant transaction costs,share,

We are exposed to commodity price risk for natural gasfuel and the unhedged portion of our generation portfolio. Our earnings and cash flows are therefore exposed to variability of spot and forward market prices in the markets in which we operate.

CostGeopolitical andrisks Availabilityspecific of Fuel. We depend onto nuclear fuel,fuel natural gas, and oil to operate most of our generating facilities. The supply markets for nuclear fuel, natural gas, and oil are subject to price fluctuations, availability restrictions, tariffs, counterparty default, and geopolitical risk, includinginclude the ongoing Russia and Ukraine conflict which has yielded sanctions and legislation by the United States, United Kingdom, European Union, Russia, and Canada impacting the exports and imports of Russian nuclear fuel. An example of such sanctions includes the "“Prohibiting Russian Uranium Imports Act"” which bans 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. The cycle of production and utilization of nuclear fuel is complex, and we engage a diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. Non-performance by these suppliers could have a material adverse impact on our consolidatedresults of operations or financial statements.condition. See ITEM 1. BUSINESS – Price and Supply Risk Management and ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK for additional information on the nuclear fuel cycle and procurement.

Demand and Supply. The market price for electricity is also affected by changes in the demand for electricity and the available supply of electricity. Unfavorable economic conditions, milder than normal weather, regulatory intervention, and the growth of energy efficiency and demand response programs can rapidly increase supply or depress demand. In addition, in some markets, the supply of electricity can exceed demand during some hours of the day, resulting in lower market prices, including periods of negative pricing, and loss of revenue for baseload generating plants such as our nuclear plants.

Retail Competition. Our retail operations compete for customers in a competitive environment, which affects the margins we can earn and the volumes we are able to serve. In periods of sustained low natural gas and power prices and low market volatility, retail competitors can aggressively pursue market share because the barriers to entry can be low and wholesale generators (including us) use their retail operations to hedge generation output. Likewise, retail competition is dependent upon continued support of the host state, and state legislative sessions can present repeated opportunities for adjustment and full or partial repeal of retail competition in certain markets.

We aremay potentiallybe affected by emerging technologies that could, over time, affect or transform the energy industry.

Advancements in both distributed and utility-scale power generation technology could impact market prices and demand size and behaviors. For instance, commercial and residential solar generation installations, energy storage improvements that include batteries and fuel cells, and other emerging technologies are improving the cost-effectiveness of customer self-supply of electricity. Improvements in energy efficiency of lighting, appliances, equipment and building materials will also affect energy consumption by customers. Advancements in nuclear technology, carbon capture sequestration,CCUS, storage and advanced geothermal may contribute to a substantial increase in the supply of clean, reliable baseload power, impacting market prices. Carbon sequestrationCCUS technology may also allow for gas generation to continue to be a viable source of clean electricity and provide for future growth of clean gas-powered generation. Further, advancements in AI and other technology could lead to reduced barriers of entry resulting in increased competition from new market participants.

These developments could affect the price of energy, levels of customer-owned generation, customer expectations and current business models and make portions of our generation facilities uneconomic prior to the end of their useful lives. These technologies could also result in further declines in commodity prices or demand for delivered energy. Each of these factors could affect our consolidatedresults of operations or financial statementscondition through, among other things, reduced operating revenues, increased operating and maintenance expenses, increased capital expenditures, and potential asset impairment charges or accelerated depreciation and decommissioning expenses over shortened remaining asset useful lives.

Our business is subject to credit quality standards that could require market participantsus to post collateral for theirour 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.

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 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.

We couldmay be negativelyadversely affected by the impactseffects of weather.sustained inflation.

Long-lived assets – principally, generation assets – represent the single largest asset class on our Consolidated Balance Sheets. In addition, we expect to have a materialsignificant goodwill balance asfollowing the acquisition of DecemberCalpine 31,in 2024.January 2026.

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.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.

Our consolidatedresults of operations and financial statementscondition are significantly affected by our sales and purchases of commodities at market-based rates, as opposed to cost-based or other similarly regulated rates,rates. and federalFederal and state regulatory and legislative developmentsaction relateddesigned to emissions,limit climatemarket-based change,rates through capacity market mitigation, energy price information, resilience, fuel diversity, and RPS.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 on the nuclear PTC.information.

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 clean-upcleanup 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 nowcurrently 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.

Federal and state legislation mandating the implementation of energy conservation programsprograms, 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 aremay potentiallybe affected by emerging technologies that couldcould, over timetime, affect or transform the energy industry” above for additional information.

FERC has the exclusive authority to license most non-federal hydropower projects located on navigable waterways, federal lands, or connected to the interstate electricelectrical 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 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 requirelead to significant expenditures, result in loss of revenue, or restrictthe restriction of existing business activities.

WeWeather periodicallyprojections performsuggest analysesincreases to bettersummer understandtemperature, howhumidity 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 changenorms could affectcontribute ourto facilitiesthe andweather-related operations.impacts discussed above. We primarily operate in the Midwest, Mid-Atlantic, Northeast, and Texas areas that have historically been prone to various types of severe weather events. As such, we have well-developed response and recovery programs based on historical weather events and patterns. However, ourOur 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.

ClimateWe may be exposed to climate mitigation and transition risks includeif 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 athe nation's largest producer of carbon-freeclean 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, ERCOTERCOT, 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, 20242025 compared to the year ended December 31, 2023.2024. For discussion of the year ended December 31, 20232024 compared to the year ended December 31, 2022,2023, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 20232024 Form 10-K, which was filed with the SEC on February 27,18, 2024.2025.

Proposed Acquisition of Calpine Corporation

On January 10,7, 2025,2026, we enteredacquired an agreement and plan100% of merger (Merger Agreement) with Calpine Corporation (Calpine) under which we will acquire all the outstanding equity interests of Calpine infor a cashpurchase price of approximately $22 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and stockapproximately transaction.$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 overapproximately 2723 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 2.5 million customers with 6062 TWhs of load annually.

This acquisition is complementary toto, and aligns strategically withwith, our existing business operations and provides both increased scale and meaningful market diversification. WeThe willmerger couplecouples the largest producer of clean, carbon-freeemissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also createcreates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that will enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine will strengthenstrengthens our essential role in providing clean, reliable, and affordablereliable 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.

Completion of the transaction is conditioned upon review of the transaction by the DOJ, and approval by the FERC, NYPSC, and PUCT, in addition to other regulatory bodies, and is also subject to other customary closing conditions. 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.

During the third quarter ofIn 2024, we executed a 20-year PPA with Microsoft that will supportannounced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center,Center. whichThe wasrestart retiredis insupported 2019by fora economic20-year reasons.PPA Under the agreement,with Microsoft willto purchase the output generated from the renewed plant as part of its goal to help power its data centers in PJM with clean energy. We expect Crane will also be eligible for the technology-neutral clean electricity PTC (45Y) provided for by the IRA for its first 10 years of operations. We estimate the project will require approximately $1.6 billion of cash from operations for capital expenditures necessary to restart the plant, with an estimated in-service date of 2028.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. Additionally, through a separate request, we will pursue obtaining a renewed license that will extend operations at the plant to at least 2054.

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 carbon-freeemissions-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. Governmentgovernment and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term.

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.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.

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. TheAn ARO is not required or permitted to be re-measuredremeasured for changes in the CARFR that occur in isolation. Increases in thean 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 thean ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers. If all our future nominal cash flows associated with the AROAROs were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.2$12.9 billion to approximately $11.2$11.3 billion.

The following table illustrates the significant 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 theour AROAROs:

ARO Sensitivities. Changes in the assumptions underlying thean ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to thean ARO is highly dependent on how the other assumptions may correspondingly change.

PurchaseAcquisition Accounting

In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquireda 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 amount 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. Goodwill is not amortized, instead it is subject to an impairment assessment at least annually to consider whether the reporting unit fair value is more likely than not less than the carrying amount. 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.

WeGoodwill performis not amortized, but rather is subject to an assessment for impairment of goodwillassessment 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.

WhileThe the 20242025 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes.impairments. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of our goodwill, which could be material.goodwill.

Unamortized energy contractUEC assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts and fuel contracts that we have acquired. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract.acquisition. The unamortized energy contractUEC assets and liabilities are amortized over the life of the contract in relationaccordance towith 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.

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 (typically contracted renewable generation).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 groups.group. This includes significant assumptions of the estimated future cash flows generated by the assetlong-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,capital investments, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.

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, supportedinformed by formal depreciation studies of historical asset retirement experience. Depreciation studies are generallyexperiences conducted periodicallyat ifleast 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 event,asset's regulatorycurrent action,estimated useful life will be shortened or changeextended, indepreciation retirementprovisions patternswill indicatebe anadjusted updatewhich iscould necessary.have a material impact on future results of operations.

Changes in estimated useful lives of electric generating assets could have a significant 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.

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 authoritative guidance, could result in previously excluded contracts becoming in scope of newexisting 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 enteredexecuted for economic hedging and for proprietary trading 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 onas to whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.

AsCommodity Contracts. Identification of a partcommodity ofcontract as an economic hedge requires us to determine that the authoritativecontract guidance,is wein 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 the expected changes in the 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.

TheApproximately majorityhalf 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.

Discount Rate. Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality non-callable (or callable with make-whole provisions)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.

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 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-notmore likely than not such benefit will not be realized in future periods.

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 consolidatedresults of operations or financial statements.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,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 consolidatedresults of operations or financial statements.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 theour consolidatedresults of operations or financial statements.condition.

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 servicessustainable 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.

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 expected to be issuedguidance, from the U.S. Treasury and IRSIRS, thatand may materially impact the total amount of benefits we receive. Absence of prescriptive guidance requires the application of judgementjudgment 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, also referred to as mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-marketDerivative 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.

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, 20242025 compared to the same period in 2023.2024. For additional information regarding the financial results for the years ended December 31, 20242025 and 2023,2024, see the discussions of Results of Operations below.

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.part, Forwhich allmay adjustmentsresult exceptin an effective tax rate that differs from the NDTmarginal fundrate. investment returns, which are included in decommissioning-related activities, theThe marginal statutory income tax rate was 25.5%25.6% and 25.1%25.5% for the years ended December 31, 20242025 and 2023, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized and realized gains and losses related to NDT funds were 54.8% and 52.4% for the years ended December 31, 2024 and 2023,2024, 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, 20242025 compared to the same period in 2023.2024.

(b)Includes mark-to-marketunrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

At MarchJune 31,30, 2026, our risk factors were consistent with the risk factors described in our 2025 Form 10-K in ITEM 1A. RISK FACTORS which was inclusive of the risks related to the Calpine acquisition and its operations.

During 2026, our Board of Directors approved a $4.4 billion increase relative to the remaining authorized$0.6 amountbillion toauthorization under our share repurchase our outstanding common stock.program. No other repurchase plans or programs have been authorized. As of the date of this filing, we have approximately $4.7$2.8 billion of remaining authority for repurchases. See Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information regarding our share repurchase program.

No accelerated share repurchases occurred under the program during the threesix months ended MarchJune 31,30, 2026.

DuringExcept as set forth below, during the three months ended MarchJune 31,30, 2026, none of our directors or executive officers (as defined in Rule 16a-1 under the Exchange Act) adopted or terminated any contract, instruction or written plan for the purchase or sale of our securities that was intended to satisfy the affirmative defense conditions of Rule 10b5-1(c) or any "non-Rule 10b5-1 trading arrangement" (as defined in Item 408 under Regulation S-K of the Exchange Act).

MayAugust 11,6, 2026

MayAugust 11,6, 2026

In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustmentsadjustments. andIn remainsAugust 2026, we entered into an agreement with LS Power to divest the Brazos Valley Energy Center (f/k/a Jack A. Fusco Energy Center), a 606 MW natural gas-fired plant in ERCOT for $860 million before closing adjustments. Completion of these transactions is subject to customary closing conditions,conditions includingand receipt of applicable regulatory approvals.approvals, Completion of this transaction, together with the planned divestiture of an additional ERCOT facility,and is expected to satisfy the remaining regulatory commitments related to the merger. We expect the transactions to close by the end of this year.

In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. CalpineWe hashave also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas.

In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired combined-cycle generatingPastoria facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which will be comingcame online duringin the spring/summer ofJuly 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company.

In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460-megawatt,460 MW, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas’ continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state’s economic momentum.

In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar—consisting of a price cap of approximately $325/MW‑day and a price floor of approximately $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM’s tariff revisions, allowing the continued application of the price collar for the specified delivery years. The CommissionFERC found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms. In July 2026, PJM released the results of the 2028/2029 Base Residual Auction and the entire RTO, including all submitted CEG units, cleared at the price cap of $325/MW-day

In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions.exceptions, Unlesssuch reliefas froma determination by PJM that the requirementsunit is providedneeded thisfor couldreliability. requirePJM made such a finding with respect to our natural gas generation facility Zion Energy Center, acquired as part of Calpine, and accordingly Zion plans to shutoperate down bypast January 2030.

Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At MarchJune 31,30, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information.

GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three and six months ended MarchJune 31,30, 2026 and 2025, see the discussions of Results of Operations below.

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 25.5% for the three and six months ended MarchJune 31,30, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025.

(a)Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 354360 million and 314 million for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and 357 million and 314 million for the six months ended June 30, 2026 and 2025, respectively.

Three Months Ended MarchJune 31,30, 2026 Compared to Three Months Ended MarchJune 31,30, 2025. The variance in Net income (loss) attributable to common shareholders was favorableunfavorable by $1,472($326) million primarily due to:

•Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by higher costs related to a significant weather event in the first quarter of 2026 and lower CMC program revenue.revenue;

With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operationsoperations, are reported under Other and not allocated to a segment.

For the three and six months ended MarchJune 31,30, 2026 compared to 2025, Operating revenues were as follows:

Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider EFOF to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three and six months ended MarchJune 31,30, 2026 iswas 4.5%.6.2% and 5.2%, respectively. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies.

Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three and six months ended MarchJune 31,30, 2026 and 2025.

(a)We did not have significant activity at this zone for the three months ended MarchJune 31,30, 2025.

ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three and six months ended MarchJune 31,30, 2026 and 2025 and may not necessarily reflect prices we ultimately realizerealized as a result of interaction with the nuclear PTC discussed below.

Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025 and2025, $33.50 per MWh for the period June 2025 through May 2026.2026, and $34.50 per MWh for the period June 2026 through May 2027. If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us. If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd. The average CMC prices per MWh were ($26.18$5.91) and ($2.04$0.42) for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and ($16.05) and ($1.23) for the six months ended June 30, 2026 and 2025, respectively. The average CMC prices may not necessarily reflect prices we ultimately realizerealized as a result of interaction with the nuclear PTC discussed below.

Nuclear PTC. Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $26.00 per MWh and $44.75 per MWh for 2025.2025 We expect the inflation factor for 2026 to be published in the second or third quarter ofand 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.

The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three and six months ended MarchJune 31,30, 2026 compared to 2025:

For the three and six months ended MarchJune 31,30, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows:

For the three and six months ended MarchJune 31,30, 2026 compared to 2025, Purchased power and fuel expense were as follows:

Natural Gas Prices. As an owner-operator of a large fleet of natural gasgas-fired generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized.

For the three and six months ended MarchJune 31,30, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows:

Depreciation and amortization expense increased by $195$189 million for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025, and increased by $384 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Interest expense, net increased by $107$165 million for the three months ended MarchJune 31,30, 2026 compared to the same period in 2025, and increased by $272 million for the six months ended June 30, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Other, net was favorable for the three and six months ended MarchJune 31,30, 2026 compared to the same period in 2025, due to activity described in the table below:

Effective income tax rates were 24.9%44.2% and 14.6%34.6% for the three months ended MarchJune 31,30, 2026 and 2025, respectively, and 30.7% and 32.4% for the six months ended June 30, 2026 and 2025, respectively. The changeincrease in effective tax rate for 2026the isthree months ended was primarily due to the decrease in share-based payment awards as well as lowerhigher qualified NDT fund income in the second quarter of 2026 which is taxed at a higher rate. The decrease in effective tax rate for the six months ended was primarily due to proportionally lower qualified NDT fund income in 2026 which is taxed at a higher rate as well as a decrease in share-based payment awards. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. WeAnnually, annuallywe evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine 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 $15.1$14.5 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

The following table summarizes our cash flow activities for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively:

Cash provided by operating activities was $425$1,553 million and $107$1,584 million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Additionally, the increaseIncluded in net cash provided by operating activities wasfor duethe six months ended June 30, 2026, are refunds to cashstate inflowsprograms associated with anuclear decrease in collateral posted.PTCs. See Note 126 — DerivativeGovernment Financial InstrumentsAssistance of the Combined Notes to Consolidated Financial Statements for additional information.

Cash used in investing activities was ($3,732$5,101) million and ($886$1,758) million for the threesix months ended MarchJune 31,30, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition.acquisition and an increase in capital expenditures related to the planned restart of Crane, inclusion of Calpine, and co-location infrastructure. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Cash provided by financing activities was $730$877 million for the threesix months ended MarchJune 31,30, 2026, compared to cash used in financing activities of ($408$893) million for the threesix months ended MarchJune 31,30, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the threesix months ended MarchJune 31,30, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. The remaining change is related to repurchases of common stock. See Note 13 — Debt and Credit Agreements and Note 16 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

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 MarchJune 31,30, 2026, we have access to facilities with aggregate bank commitments of $15.1$14.5 billion. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

We had access to the commercial paper markets and had availability under our revolving credit facilities during the firstsecond quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets.

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of MarchJune 31,30, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of MarchJune 31,30, 2026, we had $6.7$7.0 billion of available capacity under our credit facilities and $0.8$0.7 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 MarchJune 31,30, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.0$3.4 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.

As of MarchJune 31,30, 2026, the Crane NDT is fully funded under the SAFSTOR scenario that wasis the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of MarchJune 31,30, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units.