# Constellation Energy Corp (CEG) Informational only - not investment advice. CIK: 0001868275 SIC: 4911 Electric Services SIC breadcrumb: [Transportation, Communications, Electric, Gas, And Sanitary Services](/division/E/) > [Electric, Gas, And Sanitary Services](/major-group/49/) > [SIC 4911 Electric Services](/industry/4911/) Latest 10-K filed: 2026-02-24 SEC page: https://www.sec.gov/edgar/browse/?CIK=1868275 Filing source: https://www.sec.gov/Archives/edgar/data/1868275/000186827526000032/ceg-20251231.htm ## Selected Fundamentals | Metric | Value | Unit | FY | Filed | | --- | ---: | --- | ---: | --- | | Revenue | 25533000000 | USD | 2025 | 2026-02-24 | | Net income | 2319000000 | USD | 2025 | 2026-02-24 | | Assets | 57249000000 | USD | 2025 | 2026-02-24 | ## Financials Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-24. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001868275.json. Derived margins are computed from the extracted annual SEC facts. | Metric | 2019 | 2020 | 2021 | 2022 | 2023 | 2024 | 2025 | | --- | ---: | ---: | ---: | ---: | ---: | ---: | ---: | | Revenue | | 17,603,000,000 | 19,649,000,000 | 24,440,000,000 | 24,918,000,000 | 23,568,000,000 | 25,533,000,000 | | Net income | | 589,000,000 | -205,000,000 | -160,000,000 | 1,623,000,000 | 3,749,000,000 | 2,319,000,000 | | Operating income | | 256,000,000 | -346,000,000 | 495,000,000 | 1,610,000,000 | 4,352,000,000 | 3,086,000,000 | | Diluted EPS | | 0.00 | 0.00 | -0.49 | 5.01 | 11.89 | 7.40 | | Assets | | | 48,086,000,000 | 46,909,000,000 | 50,758,000,000 | 52,926,000,000 | 57,249,000,000 | | Liabilities | | | 36,472,000,000 | 35,537,000,000 | 39,472,000,000 | 39,387,000,000 | 42,396,000,000 | | Stockholders' equity | | | 11,219,000,000 | 11,018,000,000 | 10,925,000,000 | 13,166,000,000 | 14,517,000,000 | | Cash and cash equivalents | 303,000,000 | 226,000,000 | 504,000,000 | 422,000,000 | 368,000,000 | 3,022,000,000 | 3,641,000,000 | | Net margin | | 3.35% | -1.04% | -0.65% | 6.51% | 15.91% | 9.08% | | Operating margin | | 1.45% | -1.76% | 2.03% | 6.46% | 18.47% | 12.09% | ## Macro Cross-References - [CPIAUCSL](/indicator/CPIAUCSL/): Consumer Price Index for All Urban Consumers: All Items in U.S. City Average - [UNRATE](/indicator/UNRATE/): Unemployment Rate - [FEDFUNDS](/indicator/FEDFUNDS/): Federal Funds Effective Rate - [CES0500000003](/indicator/CES0500000003/): Average Hourly Earnings of All Employees, Total Private - [DFEDTARU](/indicator/DFEDTARU/): Federal Funds Target Range - Upper Limit - [DFEDTARL](/indicator/DFEDTARL/): Federal Funds Target Range - Lower Limit - [DGS3MO](/indicator/DGS3MO/): Market Yield on U.S. Treasury Securities at 3-Month Constant Maturity - [DGS2](/indicator/DGS2/): Market Yield on U.S. Treasury Securities at 2-Year Constant Maturity - [DGS10](/indicator/DGS10/): Market Yield on U.S. Treasury Securities at 10-Year Constant Maturity - [DGS30](/indicator/DGS30/): Market Yield on U.S. Treasury Securities at 30-Year Constant Maturity - [T10Y2Y](/indicator/T10Y2Y/): 10-Year Treasury Constant Maturity Minus 2-Year Treasury Constant Maturity - [CPILFESL](/indicator/CPILFESL/): Consumer Price Index for All Urban Consumers: All Items Less Food and Energy - [CPIUFDSL](/indicator/CPIUFDSL/): Consumer Price Index for All Urban Consumers: Food - [CPIENGSL](/indicator/CPIENGSL/): Consumer Price Index for All Urban Consumers: Energy - [CUSR0000SAH1](/indicator/CUSR0000SAH1/): Consumer Price Index for All Urban Consumers: Shelter - [PCEPI](/indicator/PCEPI/): Personal Consumption Expenditures: Chain-type Price Index - [PCEPILFE](/indicator/PCEPILFE/): Personal Consumption Expenditures Excluding Food and Energy: Chain-type Price Index - [PPIACO](/indicator/PPIACO/): Producer Price Index by Commodity: All Commodities - [T10YIE](/indicator/T10YIE/): 10-Year Breakeven Inflation Rate - [U6RATE](/indicator/U6RATE/): Total Unemployed, Plus All Marginally Attached Workers Plus Total Employed Part Time for Economic Reasons - [PAYEMS](/indicator/PAYEMS/): All Employees, Total Nonfarm - [CIVPART](/indicator/CIVPART/): Labor Force Participation Rate - [EMRATIO](/indicator/EMRATIO/): Employment-Population Ratio - [UNEMPLOY](/indicator/UNEMPLOY/): Unemployed - [CE16OV](/indicator/CE16OV/): Employment Level - [ICSA](/indicator/ICSA/): Initial Claims - [JTSJOL](/indicator/JTSJOL/): Job Openings: Total Nonfarm - [JTSQUR](/indicator/JTSQUR/): Quits: Total Nonfarm - [GDPC1](/indicator/GDPC1/): Real Gross Domestic Product - [A191RL1Q225SBEA](/indicator/A191RL1Q225SBEA/): Real Gross Domestic Product: Percent Change from Preceding Period - [INDPRO](/indicator/INDPRO/): Industrial Production: Total Index - [TCU](/indicator/TCU/): Capacity Utilization: Total Index - [HOUST](/indicator/HOUST/): New Privately-Owned Housing Units Started: Total Units - [PERMIT](/indicator/PERMIT/): New Privately-Owned Housing Units Authorized in Permit-Issuing Places: Total Units - [RSAFS](/indicator/RSAFS/): Advance Retail Sales: Retail Trade - [PCE](/indicator/PCE/): Personal Consumption Expenditures - [DSPIC96](/indicator/DSPIC96/): Real Disposable Personal Income - [PSAVERT](/indicator/PSAVERT/): Personal Saving Rate - [M2SL](/indicator/M2SL/): M2 - [BOPGSTB](/indicator/BOPGSTB/): U.S. International Trade in Goods and Services: Balance ## Latest 10-K MD&A Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high 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. 52 Table of Contents 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. 53 Table of Contents 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 units 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: 54 Table of Contents 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. 55 Table of Contents 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. 56 Table of Contents 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. 57 Table of Contents 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 58 Table of Contents 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, 59 Table of Contents 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 60 Table of Contents 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. 61 Table of Contents 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. 62 Table of Contents 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. 63 Table of Contents 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. 64 Table of Contents 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. 65 Table of Contents 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) % 66 Table of Contents 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. 67 Table of Contents 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 68 Table of Contents 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 69 Table of Contents 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. 70 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  71 Table of Contents 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. 72 Table of Contents 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. 73 Table of Contents ◦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  74 Table of Contents 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. 75 Table of Contents 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. 76 Table of Contents 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 77 Table of Contents guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information. If a nuclear plant were to retire before the end of its licensed life, there is a risk that it will no longer meet the NRC minimum funding requirements due to the earlier commencement of decommissioning activities and a shorter time period over which the NDT funds could appreciate in value. A shortfall could require that we address the shortfall by providing additional financial assurances, such as surety bonds, letters of credit, or parent company guarantees for our share of the funding assurance. However, the amount of any assurance will ultimately depend on the decommissioning approach, the associated level of costs, and the NDT fund investment performance going forward. No later than two years after shutting down a plant, we must submit a Post-shutdown Decommissioning Activities Report (PSDAR) to the NRC that includes the planned option for decommissioning the site. Upon issuance of any additional financial assurance mechanisms to address a decommissioning funding shortfall, subject to satisfying various regulatory preconditions, each site would be able to utilize the respective NDT funds for radiological decommissioning costs, which represent the majority of the total expected decommissioning costs. However, under the regulations, the NRC must approve an exemption in order for us to utilize the NDT funds to pay for non-radiological decommissioning costs (i.e., spent fuel management and site restoration costs, if applicable). Any amounts not covered by an exemption would be borne by us without reimbursement. As of December 31, 2025, the Crane NDT is fully funded under the SAFSTOR scenario that was the planned decommissioning option, as described in the Crane PSDAR filed with the NRC in April 2019. We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements. Additionally, as of December 31, 2025, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.