Constellation Energy Corp 10-Q

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions except per share data, unless otherwise noted) Executive Overview Constellation Energy Corporation, a Fortune 200 company headquartered in Baltimore, is the largest private-sector power producer in the world and the nation’s largest producer of clean and reliable energy. With 55 gigawatts of capacity from nuclear, natural gas, oil, geothermal, hydro, wind and solar facilities, our fleet has the generating capacity to power the equivalent of 27 million homes, providing about 10% of the nation’s clean energy and delivering the around-the-clock reliability needed to power America’s growing economy. We are also the largest nuclear energy company in the U.S. and a leading competitive retail supplier, serving approximately 2.5 million customer accounts nationwide, including 80% of the Fortune 100. We are committed to investing in innovation and new technologies to drive the transition to a reliable, sustainable and secure energy future. 50 Table of Contents Significant Transactions and Developments Acquisition of Calpine Corporation On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $21.8 billion. The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand. After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of predominantly natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually. This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification. The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand. In March 2026, we entered into an agreement with LS Power Equity Advisors, LLC to sell five natural gas-fired generating facilities with approximately 4.4 GWs of capacity from Calpine's portfolio of generation assets located in PJM to satisfy regulatory commitments related to our acquisition of Calpine. The transaction is valued at $5.0 billion before closing adjustments and remains subject to customary closing conditions, including receipt of applicable regulatory approvals. Completion of this transaction, together with the planned divestiture of an additional ERCOT facility, is expected to satisfy the remaining regulatory commitments related to the merger. See Note 2 — Mergers, Acquisitions, and Dispositions and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. New Data Center Facility at Freestone Energy Center In the first quarter of 2026, we signed a new 380 MW agreement with Dallas-based CyrusOne, a leading global data center developer and operator, to connect and serve a new data center adjacent to the Freestone Energy Center, in Freestone County, Texas. The agreement provides CyrusOne with access to power, grid connectivity and site infrastructure needed to support development of the new facility, while ensuring electricity continues to flow to the regional grid and ensuring reliability for all customers and communities. Calpine has also entered into an exclusive agreement to provide power, grid connectivity and site infrastructure for Phase 2, which will be an additional 380 MWs. These agreements are in addition to the 400 MW agreements announced in the second half of last year between Calpine and CyrusOne for the Thad Hill Energy Center in Bosque County, Texas. Pastoria Solar Project In April 2026, we celebrated the commissioning of the 105 MW Pastoria Solar Project, the largest renewable energy project contracted by the California Department of Water Resources to date in its mission to fully decarbonize its operations by 2035. The Pastoria Solar Project connects to the grid through the interconnection facilities at our highly efficient 750 MW natural gas-fired combined-cycle generating facility. Also, co-located with the Pastoria Solar Project is the Pastoria Power Bank, a 80 MW/320 MWh Battery Energy Storage System, which will be coming online during the spring/summer of 2026. The Pastoria Power Bank is contracted and supported by a 15-year power purchase agreement with Pacific Gas and Electric Company. Pin Oak Creek Energy Center In April 2026, our Pin Oak Creek Energy Center achieved commercial operation. Pin Oak Creek is a 460-megawatt, state-of-the-art natural gas facility designed to provide reliable, dispatchable power to the ERCOT grid. As a peaking facility, it is built to operate when demand is highest and reliability matters most, while also maintaining the flexibility to run longer if system conditions require it. The project is a direct response to Texas’ continued growth and increasing electricity demand across homes, businesses, and industry. Pin Oak Creek will play a critical role in strengthening grid reliability and supporting the state’s economic momentum. 51 Table of Contents Other Key Business Drivers PJM Market Reform In January 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to improve reliability and cost-effectiveness within its capacity auctions. During the first quarter of 2026, PJM began stakeholder discussions and preparatory work in response to this directive, including evaluation of a potential reliability backstop mechanism, enhancements to large load forecasting methodologies, and actions to accelerate generator interconnection studies. In February 2026, PJM filed tariff revisions proposing to extend the existing RPM capacity market price collar—consisting of a price cap of approximately $325/MW‑day and a price floor of approximately $175/MW‑day—for the 2028/2029 and 2029/2030 Base Residual Auctions. In an order issued by FERC in April 2026, FERC accepted PJM’s tariff revisions, allowing the continued application of the price collar for the specified delivery years. The Commission found the filing sufficiently justified to proceed, citing ongoing reliability concerns and extraordinary demand growth, including data center load expansion, and anticipated market reforms. FERC Issues Order in PJM Show Cause Proceeding In December 2025, FERC issued a draft order finding PJM's tariff unjust and unreasonable as it relates to colocated load, citing lack of sufficient clarity and consistency regarding rates, terms, and conditions of service for interconnection customers serving co-located load. The draft order also found that behind-the-meter generation rules in PJM's current tariff are no longer appropriate. PJM's current tariff requires that all co-located load be served through the PJM transmission system and that any planned modifications to generating facilities would require reliability studies and be subject to PJM's approval. FERC is now directing PJM to revise its tariff to: a) detail the terms and conditions for interconnection customers serving co-located load, b) require transmission customers serving co-located load to choose from four specific service options, and c) revise behind-the-meter generation rules, including the development of a transition period and grandfather clause for certain existing contracts. Through the date of this filing, PJM had not filed its final compliance tariff revisions, and the ultimate form and timing of these changes remain subject to further stakeholder processes and FERC review. Russia and Ukraine Conflict We are closely monitoring developments of the ongoing Russia and Ukraine conflict, including United States, United Kingdom, European Union, and Canadian sanctions, and legislation that may impact exports and imports of Russian nuclear fuel supply and enrichment activities, as well as the potential for Russia to limit fuel deliveries. The U.S. “Prohibiting Russian Uranium Imports Act” became effective in August 2024, banning the import of low-enriched uranium into the U.S. that is produced in Russia or by Russian entities, absent a waiver from the DOE. Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars to support expansion of the domestic nuclear fuel cycle within the United States to improve 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 and mitigate the risk of exposure to Russian nuclear fuel supply. Recognizing the potential for the continuing conflict to impact our longer-term security and cost of supply, we have entered into contracts to increase the size of our nuclear fuel inventory. Our fuel procurement activities comply with all U.S. and international trade laws and we continue to take advantage of all available avenues to maintain continuity in our nuclear fuel supply, including working with the U.S. Government and our diverse set of suppliers to secure the nuclear fuel needed to continue to operate our nuclear fleet long-term. 52 Table of Contents Environmental Regulation California Assembly Bill 32, as amended by Senate Bill 32 in 2016, directed the California Air Resources Board (CARB) to adopt regulations to achieve the maximum technologically feasible and cost-effective reductions in GHG emissions, targeting statewide GHG emissions at 1990 levels by 2020 and to at least 40% below 1990 levels by 2030. The California Climate Crisis Act was enacted in 2022 and further establishes the state's policy to achieve net zero GHG emissions as soon as possible, but no later than 2045, and to reduce statewide anthropogenic GHG emissions to 85% below 1990 levels by 2045. To achieve these targets, CARB has promulgated complementary regulatory measures, including the Cap-and-Trade Program and Mandatory Greenhouse Gas Emissions Reporting Regulation. Covered entities, such as our power plants, must surrender compliance instruments, which include both allowances and offset credits, in an amount equivalent to their GHG emissions. Assembly Bill 398, enacted in 2017, authorized the extension of the Cap-and-Trade Program through 2030 and required several changes to the program, including establishing a price ceiling and other price mitigative mechanisms and limiting the amount of offsets allowed to comply with the regulation. In September 2025, California Governor Gavin Newsom signed AB 1207 and SB 840 into law, extending the state’s Cap-and-Trade Program through January 1, 2046, and renaming it the “Cap and Invest" Program. In September 2021, Illinois Governor JB Pritzker signed into law the Climate and Equitable Jobs Act, which, among other things, establishes a schedule for eliminating CO2 emissions by EGUs. Under that schedule, privately owned natural gas units that exceed an established level of NOx or SO 2 emissions and are located within three miles of an environmental justice community, or an equity investment-eligible community must permanently eliminate CO2 and co-pollutant emissions by January 1, 2030, subject to certain reliability exceptions. Unless relief from the requirements is provided this could require our natural gas generation facility Zion Energy Center, acquired as part of Calpine, to shut down by January 2030. See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on environmental legislation and regulation we are subject to. Critical Accounting Policies and Estimates Management makes a number of significant estimates, assumptions, and judgments in the preparation of our financial statements. At March 31, 2026, our critical accounting policies and estimates had not changed significantly from December 31, 2025. See ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS — Critical Accounting Policies and Estimates of our 2025 Form 10-K for further information. Financial Results of Operations GAAP Results of Operations. The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the three months ended March 31, 2026 compared to the same period in 2025. For additional information regarding the financial results for the three months ended March 31, 2026 and 2025, see the discussions of Results of Operations below. Three Months Ended March 31, $ Change 2026 2025 GAAP Net Income (Loss) Attributable to Common Shareholders $ 1,590 $ 118 $ 1,472 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. 53 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 25.5% for the three months ended March 31, 2026 and 2025. The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the three months ended March 31, 2026 compared to the same period in 2025. Three Months Ended March 31, 2026 2025 (In millions, except per share data) Earnings Per Share (a) Earnings Per Share (a) GAAP Net Income (Loss) Attributable to Common Shareholders $ 1,590 $ 4.49 $ 118 $ 0.38 Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes of $247 and $169, respectively) (b) (721) (2.03) 505 1.61 Decommissioning-Related Activities (net of taxes of $79 and $31, respectively) (c) (174) (0.49) 19 0.06 Amortization of Acquired Commodity Contracts (net of taxes of $53 and $—, respectively) (d) 154 0.44 — — Calpine Merger and Integration Costs (net of taxes of $22 and $4, respectively) (e) 119 0.34 13 0.04 Plant Retirements and Divestitures (net of taxes of $— and $4, respectively) — — 11 0.03 Pension & OPEB Non-Service (Credits) Costs (net of taxes of $7 and $3, respectively) 20 0.06 9 0.03 Income Tax-Related Adjustments (13) (0.04) — — Noncontrolling Interests (f) (3) (0.01) (2) (0.01) Adjusted (non-GAAP) Operating Earnings $ 972 $ 2.74 $ 673 $ 2.14 __________ (a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 354 million and 314 million for the three months ended March 31, 2026 and 2025, respectively. (b) Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments. (c) Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units. The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting. Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts. (d) In 2026, reflects the non-cash impacts of the amortization of certain commodity contracts recorded at fair value associated with the Calpine acquisition. (e) Reflects costs associated with the completion of the Calpine merger and subsequent integration of its operations. Certain of these transaction-related expenses are not tax deductible. (f) Represents elimination of the noncontrolling interest portion of certain adjustments included above. 54 Table of Contents Results of Operations Three Months Ended March 31, $ Change 2026 2025 Operating revenues $ 11,122 $ 6,788 $ 4,334 Operating expenses Purchased power and fuel 6,352 4,384 1,968 Operating and maintenance 1,780 1,545 235 Depreciation and amortization 443 248 195 Taxes other than income taxes 229 160 69 Total operating expenses 8,804 6,337 2,467 Gain (loss) on sales of assets 14 — 14 Operating income (loss) 2,332 451 1,881 Other income and (deductions) Interest expense, net (253) (146) (107) Other, net 46 (154) 200 Total other income and (deductions) (207) (300) 93 Income (loss) before income taxes 2,125 151 1,974 Income tax (benefit) expense 530 22 508 Equity in income (losses) of unconsolidated affiliates 8 — 8 Net income (loss) 1,603 129 1,474 Net income (loss) attributable to noncontrolling interests 13 11 2 Net income (loss) attributable to common shareholders $ 1,590 $ 118 $ 1,472 Three Months Ended March 31, 2026 Compared to Three Months Ended March 31, 2025. The variance in Net income (loss) attributable to common shareholders was favorable by $1,472 million primarily due to: • Addition of Calpine operations acquired in January 2026, inclusive of the impacts of purchase accounting. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information; • Favorable net unrealized gains on economic hedges; • Favorable decommissioning-related activities primarily driven by the Q1 2026 nuclear ARO update. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information; • Lower net unrealized loss on equity investments; and • Favorable net market and portfolio conditions primarily driven by higher capacity revenues partially offset by higher costs related to a significant weather event in the first quarter of 2026 and lower CMC program revenue. The favorable items were partially offset by: • Unfavorable impacts from nuclear outages. 55 Table of Contents Operating revenues. Our six reportable segments are Mid-Atlantic, Midwest, New York, ERCOT, Other Power Regions, and Calpine. See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on these reportable segments. With the exception of Calpine's natural gas sales, which are included in the Calpine segment, wholesale and retail sales of natural gas, as well as sales of other energy-related products and sustainable solutions and other miscellaneous business activities that are not significant to overall results of operations are reported under Other and not allocated to a segment. For the three months ended March 31, 2026 compared to 2025, Operating revenues were as follows: Three Months Ended March 31, 2026 2025 $ Change % Change Mid-Atlantic $ 1,847 $ 1,665 $ 182 10.9 % Midwest 1,732 1,404 328 23.4 % New York 569 562 7 1.2 % ERCOT 370 398 (28) (7.0) % Other Power Regions 1,487 1,556 (69) (4.4) % Calpine 2,395 — 2,395 100.0 % Total reportable segment revenues 8,400 5,585 2,815 50.4 % Other 1,407 1,490 (83) (5.6) % Unrealized gains (losses) (a) 1,315 (287) 1,602 Total Operating revenues $ 11,122 $ 6,788 $ 4,334 63.8 % __________ (a) % Change in unrealized gains (losses) is not a meaningful measure. 56 Table of Contents Sales and Supply Sources. Our sales and supply volumes (GWhs) by segment are summarized below: Three Months Ended March 31, (GWhs) 2026 2025 Change % Change Nuclear Generation (a) Mid-Atlantic 13,326 13,177 149 1.1 % Midwest 22,974 23,596 (622) (2.6) % New York 6,014 6,280 (266) (4.2) % ERCOT 2,352 2,529 (177) (7.0) % Total Nuclear Generation 44,666 45,582 (916) (2.0) % Natural Gas, Oil, and Renewables (a) Mid-Atlantic 740 632 108 17.1 % Midwest 344 385 (41) (10.6) % ERCOT 2,738 3,084 (346) (11.2) % Other Power Regions 1,742 1,804 (62) (3.4) % Calpine 26,497 — 26,497 100.0 % Total Natural Gas, Oil, and Renewables 32,061 5,905 26,156 442.9 % Purchased Power Mid-Atlantic 4,094 4,794 (700) (14.6) % Midwest 417 488 (71) (14.5) % ERCOT 686 659 27 4.1 % Other Power Regions 9,317 10,994 (1,677) (15.3) % Calpine 2,089 — 2,089 100.0 % Total Purchased Power 16,603 16,935 (332) (2.0) % Total Supply/Sales by Segment Mid-Atlantic 18,160 18,603 (443) (2.4) % Midwest 23,735 24,469 (734) (3.0) % New York 6,014 6,280 (266) (4.2) % ERCOT 5,776 6,272 (496) (7.9) % Other Power Regions 11,059 12,798 (1,739) (13.6) % Calpine 28,586 — 28,586 100.0 % Total Supply/Sales by Segment 93,330 68,422 24,908 36.4 % __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. 57 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. Three Months Ended March 31, 2026 2025 Nuclear fleet capacity factor 92.3 % 94.1 % Refueling outage days 99 88 Non-refueling outage days — — Equivalent Forced Outage Factor (Natural Gas, Oil, and Pumped-storage Hydro). As a result of our expanded fleet following the acquisition of Calpine in January 2026, we now consider EFOF to be a key operational metric beginning in 2026. EFOF represents the percentage for which a generating unit is not available due to forced outages and forced deratings in a given period. We consider to be a useful measure in analyzing the reliability and performance of our natural gas, oil, and pumped-storage hydro fleet. The EFOF for the three months ended March 31, 2026 is 4.5%. This operational metric is being included as a complement to the financial information provided in accordance with GAAP. However, as an operational metric, it may not be calculated or presented in a manner comparable to similar metrics used by other companies. Electricity Prices. As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost. We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense based on our net hourly position. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the geographic region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors. The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for zones/hubs in each ISO/RTO where we have significant activity. This does not reflect prices we ultimately realized. Three Months Ended March 31, ISO/RTO 2026 2025 $ Change % Change PJM - PJM West $ 97.16 $ 53.69 $ 43.47 81.0 % PJM - ComEd 50.71 35.31 15.40 43.6 % NYISO - Central 112.23 75.31 36.92 49.0 % ERCOT - North 40.65 31.39 9.26 29.5 % ERCOT - Houston 38.55 31.73 6.82 21.5 % ISO-NE - Southeast Massachusetts 118.82 104.75 14.07 13.4 % CAISO - NP15 29.01 40.96 (11.95) (29.2) % 58 Table of Contents Capacity Prices. We participate in capacity auctions in each ISO/RTO where we have qualifying generating assets. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis in either Operating revenues or Purchased power and fuel expense. We assess the net position by ISO/RTO across segments and, where applicable, by segment within the ISO/RTO. The following table presents the average capacity prices ($/MW Day) for each ISO/RTO in which we have significant activity. Prices reflect the weighted average prices for the various auction periods within the three months ended March 31, 2026 and 2025. We also enter into bilateral capacity contracts at negotiated contract prices. These contracts primarily relate to resource adequacy in CAISO and have a material impact on our operating revenues. Negotiated contract prices from these bilateral contracts are not included in the table below. Three Months Ended March 31, ISO/RTO 2026 2025 $ Change % Change PJM - Eastern Mid-Atlantic Area Council $ 269.92 $ 53.60 $ 216.32 403.6 % PJM - ComEd 269.92 28.92 241.00 833.3 % NYISO - Rest of State 112.33 86.33 26.00 30.1 % ISO-NE - Rest of Pool (a) 84.37 82.57 1.80 2.2 % __________ (a) We did not have significant activity at this zone for the three months ended March 31, 2025. ZEC Prices. We are compensated through state programs for the emissions-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/MWh) for each state and associated segment in which state programs have been enacted. Gross prices reflect the weighted average price for the various delivery periods within the three months ended March 31, 2026 and 2025 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below. Three Months Ended March 31, State (Segment) (a) 2026 2025 $ Change % Change New Jersey (Mid-Atlantic) (b) $ — $ 10.00 $ (10.00) (100.0) % Illinois (Midwest ) 1.17 9.38 (8.21) (87.5) % New York (New York) 14.76 18.27 (3.51) (19.2) % __________ (a) See ITEM 1. BUSINESS, Environmental Matters and Regulation of our 2025 Form 10-K for additional information on the plants receiving payments through state programs. (b) The New Jersey ZEC program concluded in May 2025. Illinois CMC Price. The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $33.43 per MWh for the period June 2024 through May 2025 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 ($26.18) and ($2.04) for the three months ended March 31, 2026 and 2025, 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 $26.00 per MWh and $44.75 per MWh for 2025. We expect the inflation factor for 2026 to be published in the second or third quarter of 2026. Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year. 59 Table of Contents Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC. The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the three months ended March 31, 2026 compared to 2025: Three Months Ended March 31, 2026 2025 $ Change % Change Nuclear PTC revenue (a) $ 10 $ — $ 10 100.0 % State-sponsored programs net revenue (b) (285) 110 (395) (359.1) % __________ (a) Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units. Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information. (b) Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. For the three months ended March 31, 2026 compared to 2025, changes in Operating revenues by segment were approximately as follows: Three Months Ended March 31 $ Change % Change Description Mid-Atlantic $ 182 10.9 % • favorable retail load revenue of $315 primarily due to higher contracted energy prices • favorable wholesale load revenue of $100 primarily due to higher contracted energy prices, partially offset by lower load volumes; partially offset by • unfavorable realized economic hedges of $215 due to settled prices relative to hedged prices Midwest 328 23.4 % • favorable net generation and wholesale load revenue of $370 primarily due to higher energy prices and higher load volumes, partially offset by lower generation volumes • favorable retail load revenue of $210 primarily due to higher contracted energy prices • favorable net capacity revenue of $90 primarily due to higher prices; partially offset by • unfavorable CMC program revenue of $350 primarily due to higher energy and capacity prices New York 7 1.2 % • favorable net generation revenue of $100 associated with the sale of generation volumes relative to purchased power to supply load primarily due to higher energy prices; partially offset by • unfavorable realized economic hedges of $95 due to settled prices relative to hedged prices ERCOT (28) (7.0) % • no individually significant drivers Other Power Regions (69) (4.4) % • unfavorable wholesale load revenue of $125 primarily due to lower load volumes in New England Calpine 2,395 100.0 % • represents the operating revenues associated with our Calpine segment since the date of acquisition 60 Table of Contents Three Months Ended March 31 $ Change % Change Description Other (83) (5.6) % • current year includes unfavorable amortization associated with certain commodity contracts related to the Calpine acquisition of $215; partially offset by • favorable retail gas revenue of $165 primarily due to higher gas prices Unrealized gains or losses (a)(b) 1,602 • gains on economic hedging activities of $1,315 in 2026 compared to losses of $287 in 2025, inclusive of Calpine Total $ 4,334 63.8 % __________ (a) % Change in unrealized gains or losses is not a meaningful measure. (b) See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. Purchased power and fuel. See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by segment, nuclear fleet capacity factor, EFOF, capacity prices, and electricity prices. With the exception of Calpine's natural gas activity, which is included in the Calpine segment, wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a segment. For the three months ended March 31, 2026 compared to 2025, Purchased power and fuel expense were as follows: Three Months Ended March 31, 2026 2025 $ Change % Change Mid-Atlantic $ 1,035 $ 856 $ 179 20.9 % Midwest 878 554 324 58.5 % New York 160 161 (1) (0.6) % ERCOT 161 184 (23) (12.5) % Other Power Regions 1,220 1,362 (142) (10.4) % Calpine 1,269 — 1,269 100.0 % Total segment purchased power and fuel 4,723 3,117 1,606 51.5 % Other 1,375 1,233 142 11.5 % Unrealized losses (gains) (a) 254 34 220 Total purchased power and fuel $ 6,352 $ 4,384 $ 1,968 44.9 % __________ (a) % Change in unrealized losses (gains) is not a meaningful measure. 61 Table of Contents Natural Gas Prices. As an owner-operator of a large fleet of natural gas generation facilities, the cost of our natural gas supply has a significant impact on our Purchased power and fuel expense. The following table summarizes the average daily reference price ($/MMBtu) for the periods presented in each geographic region where we have significant activity. This does not reflect prices we ultimately realized. Three Months Ended March 31, Location 2026 2025 $ Change % Change Henry Hub $ 4.90 $ 4.28 $ 0.62 14.5 % Transco Zone 6 (a) 9.48 6.06 3.42 56.4 % Houston Ship Channel (b) 3.26 3.46 (0.20) (5.8) % PG&E Citygate (c) 2.07 3.71 (1.64) (44.2) % Algonquin Citygate (d) 14.08 11.83 2.25 19.0 % __________ (a) Transcontinental Gas pipeline located in Mid-Atlantic region. (b) Houston-area pipeline and industrial network located in ERCOT region. (c) Pacific Gas & Electric Company virtual trading point located in West region. (d) Algonquin Gas Transmission physical delivery point located in New England region. For the three months ended March 31, 2026 compared to 2025, changes in Purchased power and fuel expense by segment were approximately as follows: Three Months Ended March 31 $ Change % Change Description Mid-Atlantic $ 179 20.9 % • unfavorable $350 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, higher prices associated with net capacity costs, and higher costs related to a significant weather event in January 2026; partially offset by • favorable realized economic hedges of $190 due to settled prices relative to hedged prices Midwest 324 58.5 % • unfavorable $310 associated with purchased power to supply load, net of generation, primarily due to higher costs related to a significant weather event in January 2026 New York (1) (0.6) % • no individually significant drivers ERCOT (23) (12.5) % • no individually significant drivers Other Power Regions (142) (10.4) % • favorable $80 associated with purchased power to supply load primarily due to lower energy prices in the West Calpine 1,269 100.0 % • represents the purchased power and fuel associated with our Calpine segment since the date of acquisition Other 142 11.5 % • unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $175 primarily due to higher gas prices Unrealized gains or losses (a)(b) 220 • losses on economic hedging activities of $254 in 2026 compared to losses of $34 in 2025, inclusive of Calpine Total $ 1,968 44.9 % __________ (a) % Change in unrealized gains or losses is not a meaningful measure. (b) See Note 12 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses. 62 Table of Contents The changes in Operating and maintenance expense consisted of the following: Three Months Ended March 31 2026 vs. 2025 Increase (Decrease) Labor, contracting, and materials (a) $ 175 Calpine merger and integration costs 126 Nuclear refueling outage costs (b) 51 Decommissioning-related activities (272) Other 155 Total increase $ 235 __________ (a) Primarily reflects increased employee-related costs, including labor and other incentives, as well as higher contracting expense, driven in large part by the addition of Calpine's operations beginning in January 2026. (b) Includes the co-owned Salem and STP generating units Depreciation and amortization expense increased by $195 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to the additional depreciation and amortization associated with assets acquired from Calpine beginning in January 2026. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Interest expense, net increased by $107 million for the three months ended March 31, 2026 compared to the same period in 2025, primarily due to a net increase in outstanding debt as a result of the debt assumed and related financing transactions following the acquisition of Calpine in January 2026. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other, net was favorable for the three months ended March 31, 2026 compared to the same period in 2025, due to activity described in the table below: Income (Deductions) Three Months Ended March 31, 2026 2025 Decommissioning-related activities (a) $ 59 $ 94 Net unrealized gains (losses) from equity investments (b) (27) (268) Other 14 20 Other, net $ 46 $ (154) __________ (a) Includes net realized and net unrealized gains (losses) on NDT fund investments, the elimination of decommissioning-related activities, and the elimination of income taxes related to all NDT fund activity for the Regulatory Agreement Units. See Note 9 — Asset Retirement Obligations and Note 18 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information. (b) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company. We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock. Effective income tax rates were 24.9% and 14.6% for the three months ended March 31, 2026 and 2025, respectively. The change in effective tax rate for 2026 is primarily due to the decrease in share-based payment awards as well as lower qualified NDT fund income which is taxed at a higher rate. See Note 10 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. 63 Table of Contents Liquidity and Capital Resources All results included throughout the liquidity and capital resources section are presented on a GAAP basis. Our operating and capital expenditures requirements are provided by internally generated cash flows from operations as well as funds from external sources in the capital markets and through bank borrowings. Our business is capital intensive and requires considerable capital resources. We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane. A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., issuing equity, joint ventures, minority partners, etc.). Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions. If these conditions deteriorate to the extent that we no longer have access to the capital markets at reasonable terms, we have access to credit facilities with aggregate bank commitments of $15.1 billion. We utilize our credit facilities to support our commercial paper programs, provide for other short-term borrowings and to issue letters of credit. See the “Credit Matters and Cash Requirements” section below for additional information. We expect cash flows to be sufficient to meet operating expenses, financing costs, and capital expenditure requirements. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Cash Flow Activities The following table summarizes our cash flow activities for the three months ended March 31, 2026 and 2025, respectively: Three Months Ended March 31, 2026 2025 $ Change Cash, restricted cash, and cash equivalents at beginning of period $ 3,748 $ 3,129 $ 619 Net cash provided by (used in): Operating activities 425 107 318 Investing activities (3,732) (886) (2,846) Financing activities 730 (408) 1,138 Net increase (decrease) in cash, restricted cash, and cash equivalents (2,577) (1,187) (1,390) Cash, restricted cash, and cash equivalents at end of period $ 1,171 $ 1,942 $ (771) Net Cash Provided By (Used In) Operating Activities Cash provided by operating activities was $425 million and $107 million for the three months ended March 31, 2026 and 2025, respectively. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business. Additionally, the increase in cash provided by operating activities was due to cash inflows associated with a decrease in collateral posted. See Note 12 — 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 ($3,732) million and ($886) million for the three months ended March 31, 2026 and 2025, respectively. The change is primarily related to cash paid, net of cash acquired, for the Calpine acquisition. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. 64 Table of Contents Net Cash Provided By (Used In) Financing Activities Cash provided by financing activities was $730 million for the three months ended March 31, 2026, compared to cash used in financing activities of ($408) million for the three months ended March 31, 2025. The change primarily relates to long-term debt and changes in short-term borrowings. Debt issuances and redemptions or repayments vary each year. For the three months ended March 31, 2026, these activities reflect the impact of debt transactions associated with the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Quarterly dividends declared by our Board of Directors during 2026 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share First Quarter of 2026 February 20, 2026 March 9, 2026 March 20, 2026 $ 0.4265 Second Quarter of 2026 April 28, 2026 May 15, 2026 June 5, 2026 0.4265 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 March 31, 2026, we have access to facilities with aggregate bank commitments of $15.1 billion. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. We had access to the commercial paper markets and had availability under our revolving credit facilities during the first quarter of 2026 to fund our short-term liquidity needs, when necessary. We routinely review the sufficiency of our liquidity position, including appropriate sizing of credit facility commitments, by performing various stress test scenarios, such as commodity price movements, increases in margin-related transactions, changes in hedging levels, and the impacts of hypothetical credit downgrades. We closely monitor events in the financial markets and the financial institutions associated with the credit facilities, including monitoring credit ratings and outlooks, credit default swap levels, capital raising, and merger activity. See PART I, ITEM 1A. RISK FACTORS of our 2025 Form 10-K for additional information regarding the effects of uncertainty in the capital and credit markets. We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below. Security Ratings Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings. A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of March 31, 2026 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of March 31, 2026, we had $6.7 billion of available capacity under our credit facilities and $0.8 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 March 31, 2026, we would have been required to provide incremental collateral estimated to be approximately $3.0 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements. See Note 12 — Derivative Financial Instruments and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. 65 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 below reflect a funding strategy to make annual contributions to offset the growth of the liability. Based on this funding strategy and current market conditions, which are both subject to change, our annual qualified pension contribution was made in February 2026 for $161 million. Unlike the qualified pension plans, our non-qualified plans are not subject to statutory minimum contribution requirements. OPEB plans are also not subject to statutory minimum contribution requirements, though we have funded a portion of our plans. Annually, we evaluate whether additional funding for those plans is needed. For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid. The estimated benefit payments to the non-qualified pension plans in 2026 are approximately $25 million and the planned contributions to the OPEB plans, including estimated benefit payments to unfunded plans, are $64 million. Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on pension and other postretirement benefits. Cash Requirements for Other Financial Commitments In connection with the acquisition of Calpine in January 2026, we assumed approximately $3 billion of projected cash payments under existing financial commitments with fixed or minimum payments required. These commitments exclude future cash payments for debt service on assumed debt as much of the debt was refinanced or paid off following the acquisition. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Other than as described above and elsewhere in this Quarterly Report on Form 10-Q, there have been no material changes to the cash requirements from contractual and other obligations disclosed in our 2025 Annual Report on Form 10-K. Refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS - Liquidity and Capital Resources of our 2025 Form 10-K for additional information on our cash requirements for financial commitments. Accounts Receivable Facilities We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain accounts receivables. As a result of our acquisition of Calpine in January 2026, we assumed Calpine's accounts receivable sales program which allows for the sale of certain Calpine receivables at a nominal discount. See Note 7 — Accounts Receivable and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. Project Financing Project financing is based upon a financial structure in which project debt is paid back from the cash generated by a specific asset or portfolio of assets. Borrowings under these agreements are secured by the assets and equity of each respective project. If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates. In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral. The potential requirement to repay the debt or other borrowings earlier than otherwise anticipated could lead to impairments due to a higher likelihood of disposing of the respective project-specific assets significantly before the end of their useful lives. As a result of our acquisition of Calpine in January 2026, we assumed various project financing arrangements. See Note 16 — Debt and Credit Agreements of our 2025 Form 10-K and Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on project finance credit facilities and nonrecourse debt. 66 Table of Contents Credit Facilities We meet our short-term liquidity requirements primarily through the issuance of commercial paper. We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit. We assumed various credit facilities as part of the acquisition of Calpine. See Note 13 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities. NRC Minimum Funding Requirements NRC regulations require that licensees of nuclear generating facilities demonstrate reasonable assurance that sufficient funds will be available in certain minimum amounts for radiological decommissioning of the facility. These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit. If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available. See Note 9 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding the latest funding status report filed with the NRC. As of March 31, 2026, 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 March 31, 2026, we have adequate NDT funds for the remaining radiological decommissioning costs at Zion Station related to the Independent Spent Fuel Storage Installation. Decommissioning costs other than radiological may require funding from us. See Liquidity and Capital Resources — NRC Minimum Funding Requirements of our 2025 Form 10-K for information regarding the risk of additional financial assurance for shutdown units. Properties There have been no changes in the properties that were owned as of December 31, 2025 and disclosed within ITEM 2. PROPERTIES of our 2025 Form 10-K. The following table presents our interests in net electric generating capacity by station as of March 31, 2026, for those acquired from Calpine. Station Location No. of Units Percent Owned (a) Primary Fuel Type Primary Dispatch Type (b) Net Generation Capacity (MWs) (c) Calpine Deer Park Deer Park, TX 6 Gas Intermediate 1,217 Bethlehem (d) Bethlehem, PA 8 Gas Intermediate 1,130 Hay Road (d) Wilmington, DE 8 Gas Intermediate 1,130 Guadalupe New Braunfels, TX 6 Gas Intermediate 1,040 Greenfield Ontario, Canada 4 Gas Intermediate 1,088 Baytown Baytown, TX 4 Gas Intermediate 896 Delta Pittsburg, CA 4 Gas Intermediate 882 Channel Houston, TX 4 Gas Intermediate 845 York 2 (d) Delta, PA 3 Gas Intermediate 828 Morgan Decatur, AL 4 Gas Intermediate 807 Thad Hill Clifton, TX 5 Gas Intermediate 792 Pasadena Pasadena, TX 5 Gas Intermediate 781 Freestone Fairfield, TX 6 75 Gas Intermediate 776 Pastoria Arvin, CA 5 Gas Intermediate 759 Magic Valley Edinburg, TX 3 Gas Intermediate 712 67 Table of Contents Station Location No. of Units Percent Owned (a) Primary Fuel Type Primary Dispatch Type (b) Net Generation Capacity (MWs) (c) Granite Ridge Londonderry , NH 3 Gas Intermediate 695 Hermiston Hermiston, OR 3 Gas Intermediate 635 Metcalf Coyote, CA 3 Gas Intermediate 625 Russell City Hayward, CA 3 Gas Intermediate 619 Jack A. Fusco (d) Richmond, TX 3 Gas Intermediate 609 Otay Mesa San Diego, CA 3 Gas Intermediate 608 Sutter Yuba City, CA 3 Gas Intermediate 578 Los Medanos Pittsburg, CA 3 Gas Intermediate 572 York 1 (d) Delta, PA 4 Gas Intermediate 565 South Point Mohave Valley, AZ 3 Gas Intermediate 555 Westbrook Westbrook, ME 3 Gas Intermediate 552 Quail Run Odessa, TX 6 Gas Intermediate 550 Corpus Christi Corpus Christi, TX 3 Gas Intermediate 520 Texas City Texas City, TX 4 Gas Intermediate 453 Hidalgo Edinburg, TX 3 78.5 Gas Intermediate 395 Los Esteros San Jose, CA 5 Gas Intermediate 309 Pine Bluff Pine Bluff, AR 2 Gas Intermediate 215 Gilroy Cogeneration Gilroy, CA 2 Gas Intermediate 130 King City Cogeneration King City, CA 2 Gas Intermediate 120 Bethpage 3 Levittown, NY 2 Gas Intermediate 80 Bethpage Bethpage, NY 5 Gas Intermediate 56 Stony Brook Stony Brook, NY 1 Gas Intermediate 47 Agnews San Jose, CA 2 Gas Intermediate 28 Zion Zion, IL 3 Gas Peaking 503 Cumberland Milleville, NJ 2 Gas Peaking 191 Gilroy Gilroy, CA 3 Gas Peaking 141 Sherman Avenue Vineland, NJ 1 Gas Peaking 92 Wolfskill Fairfield, CA 1 Gas Peaking 48 Bethpage Peaker Bethpage, NY 1 Gas Peaking 48 Yuba City Yuba City, CA 1 Gas Peaking 47 Feather River Yuba City, CA 1 Gas Peaking 47 Creed Suisun City, CA 1 Gas Peaking 47 Lambie Suisun City, CA 1 Gas Peaking 47 Goose Haven Suisun City, CA 1 Gas Peaking 47 Riverview Antioch, CA 1 Gas Peaking 47 King City Peaking King City, CA 1 Gas Peaking 44 Delaware City New Castle, DE 1 Gas Peaking 23 West Wilmington, DE 3 Gas Peaking 20 Fore River Weymouth, MA 3 Oil/Gas Intermediate 731 Edge Moor (d) Wilmington, DE 3 Oil Peaking 725 Christiana Wilmington, DE 2 Oil Peaking 53 Tasley Accomac, VA 1 Oil Peaking 33 Bayview Cape Charles, VA 6 Oil Peaking 12 Crisfield Crisfield, MD 1 Oil Peaking 10 68 Table of Contents Station Location No. of Units Percent Owned (a) Primary Fuel Type Primary Dispatch Type (b) Net Generation Capacity (MWs) (c) Nova Project I-V Menifee, CA 5 Battery Storage Peaking 680 Santa Ana Santa Ana, CA 3 Battery Storage Peaking 80 West Ford Flat Sonoma County, CA 1 Battery Storage Peaking 25 Bear Canyon Sonoma County, CA 1 Battery Storage Peaking 13 McCabe 5 & 6 Sonoma County, CA 2 Geothermal Baseload 85 Ridge Line 7 & 8 Sonoma County, CA 2 Geothermal Baseload 77 Eagle Rock Sonoma County, CA 1 Geothermal Baseload 71 Calistoga Lake County, CA 2 Geothermal Baseload 69 Big Geysers Lake County, CA 1 Geothermal Baseload 61 Lake View Sonoma County, CA 1 Geothermal Baseload 56 Quicksilver Lake County, CA 1 Geothermal Baseload 53 Sonoma Sonoma County, CA 1 Geothermal Baseload 53 Cobb Creek Sonoma County, CA 1 Geothermal Baseload 51 Socrates Sonoma County, CA 1 Geothermal Baseload 50 Sulphur Springs Sonoma County, CA 1 Geothermal Baseload 47 Grant Sonoma County, CA 1 Geothermal Baseload 41 Aidlin Sonoma County, CA 2 Geothermal Baseload 18 Vineland Solar Vineland, NJ 1 Solar Intermittent 4 Total Calpine 27,689 __________ (a) 100%, unless otherwise indicated. (b) Baseload units are those that normally operate to take all or part of the minimum continuous load of a system and, consequently, produce electricity at an essentially constant rate. Intermittent units are those with output controlled by the natural variability of the energy resource rather than dispatched based on system requirements. Intermediate units are those that normally operate to take load of a system during the daytime higher load hours and, consequently, produce electricity by cycling on and off daily. Peaking units consist of lower-efficiency, quick response steam units, gas turbines and diesels normally used during the maximum load periods. (c) Net generation capacity is stated at proportionate ownership share. All facilities reflect a summer rating. (d) These stations are pending divestiture as part of the regulatory requirements for the acquisition of Calpine that closed in January 2026 and the associated balances are classified as Assets held for sale in the Consolidated Balance Sheets. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. The net generation capability available for operation at any time may be less due to regulatory restrictions, transmission congestion, fuel restrictions, efficiency of cooling facilities, level of water supplies, or generating units being temporarily out of service for inspection, maintenance, refueling, repairs, or modifications required by regulatory authorities. 69 Table of Contents The following table presents our estimated net generation capacity by station for projects under construction at March 31, 2026, each of which is wholly owned by us unless otherwise noted. Station Location No. of Units Primary Fuel Type Primary Dispatch Type Estimated Net Generation Capacity (MWs) (a) Crane Middletown, PA 1 Uranium Baseload 835 Pin Oak Creek (b) Freestone, TX 2 Gas Peaking 425 Pastoria Solar (c) Kern County, CA 1 Solar Intermittent 105 Pastoria/Bess Kern County, CA 1 Battery Storage Peaking 80 Total Projects Under Construction 1,445 __________ (a) The estimated net generation capacity for units under construction is approximate until commercial operation commences and applicable confirmatory testing is completed. (b) Commercial operation was in April 2026. Additionally, in May 2026, we sold a 25% ownership interest in the facility to an unrelated party. The sale did not have a material impact on our results of operations or financial condition. (c) Pastoria Solar was commissioned in April 2026.