Constellation Energy Corp 10-K

Item 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS (Dollars in millions, unless otherwise noted) Executive Overview We are a producer of carbon-free energy and a 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, 49 Table of Contents 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, 2024 compared to the year ended December 31, 2023. For discussion of the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2023 Form 10-K, which was filed with the SEC on February 27, 2024. Significant Transactions and Developments Proposed Acquisition of Calpine Corporation On January 10, 2025, we entered an agreement and plan of merger (Merger Agreement) with Calpine Corporation (Calpine) under which we will acquire all the outstanding equity interests of Calpine in a cash and stock transaction. Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with over 27 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 2.5 million customers with 60 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. We will couple the largest producer of clean, carbon-free energy with the reliable, dispatchable natural gas assets of Calpine, and also create the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that will enable us to meet growing demand with a broader array of energy and sustainability products. The addition of Calpine will strengthen our essential role in providing clean, reliable, and affordable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand. Completion of the transaction is conditioned upon review of the transaction by the DOJ, and approval by the FERC, NYPSC, and PUCT, in addition to other regulatory bodies, and is also subject to other customary closing conditions. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. Crane Clean Energy Center During the third quarter of 2024, we executed a 20-year PPA with Microsoft that will support the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center, which was retired in 2019 for economic reasons. Under the agreement, Microsoft will purchase the output generated from the renewed plant as part of its goal to help power its data centers in PJM with clean energy. We expect Crane will also be eligible for the technology-neutral clean electricity PTC (45Y) provided for by the IRA for its first 10 years of operations. We estimate the project will require approximately $1.6 billion of cash from operations for capital expenditures necessary to restart the plant, with an estimated in-service date of 2028. The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies. Additionally, through a separate request, we will pursue obtaining a renewed license that will extend operations at the plant to at least 2054. Nuclear PTC Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032. The nuclear PTC (45U) provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have evaluated and expect to meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. For the year ended December 31, 2024, our Consolidated Statements of Operations and Comprehensive Income include a nuclear PTC benefit of approximately $2,080 million in Operating revenues. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information. 50 Table of Contents Share Repurchase Program As part of our capital allocation plan, our Board of Directors has authorized up to $3 billion of share repurchases of our outstanding common stock to-date, of which $991 million has yet to be exercised. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. Other Key Business Drivers 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 carbon-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. Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements. Nuclear Decommissioning Asset Retirement Obligations The AROs associated with decommissioning our nuclear un its were $12.2 billion at December 31, 2024. 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 51 Table of Contents required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions: 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. The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation. Increases in the 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 the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers. If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.2 billion to approximately $11.2 billion. 52 Table of Contents The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO: Change in the CARFR applied to the annual ARO update Increase (Decrease) to ARO as of December 31, 2024 2023 CARFR rather than the 2024 CARFR $ (300) 2024 CARFR increased by 50 basis points (790) 2024 CARFR decreased by 50 basis points 990 ARO Sensitivities. Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation. The impact of a change in any one of these assumptions to the 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 ARO as of December 31, 2024 Cost escalation studies Uniform increase in escalation rates of 50 basis points $ 2,290 Probabilistic cash flow models Increase the estimated costs to decommission the nuclear plants by 10 percent 770 Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a) 130 Shorten each unit's probability-weighted operating life assumption by 10 percent (b) 430 Extend the estimated date for DOE acceptance of SNF to 2045 (40) __________ (a) Excludes any sites in which management has committed to a specific decommissioning approach. (b) Excludes Crane and Zion. 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. Purchase Accounting In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition. Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items. Changes to these estimates and assumptions could result in material changes to the fair value of assets and liabilities as of the acquisition date. The judgments made in the determination of the estimated fair value assigned to the assets acquired and liabilities assumed, as well as the estimated useful life of each asset and the duration of each liability, could significantly impact the financial statements in periods after acquisition, such as through depreciation and amortization expense. Authoritative guidance provides that the allocation of the purchase price may be modified up to one year after the acquisition date as more information is obtained about the fair value of assets acquired and liabilities assumed. See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information. The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value, or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value. Goodwill is assigned to reporting units that are expected to benefit from the acquisition. Goodwill is not amortized, instead it is subject to an impairment assessment at least annually to consider whether the reporting unit fair value is more likely than not less than the carrying amount. See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information. 53 Table of Contents Goodwill We perform an assessment for impairment of goodwill 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 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 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. We first perform a qualitative assessment to determine whether a quantitative assessment is necessary. As part of the qualitative assessment, we evaluate, among other things, management’s best estimate of projected operating and capital cash flows for the reporting units and changes in certain market conditions, including the discount rate. Significant assumptions used in these fair value analyses include discount and growth rates, energy prices, and projected operating and capital cash flows. While the 2024 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes. Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of our goodwill, which could be material. 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 Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts and fuel contracts that we have acquired. The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract. The unamortized energy contract assets and liabilities are amortized over the life of the contract in relation to 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. The review of long-lived assets or asset groups for impairment utilizes significant assumptions about operating strategies and estimates of future cash flows, which require assessments of current and projected market conditions. Forecasting future cash flows requires assumptions regarding forecasted commodity prices for the sale of power and purchases of fuel and the expected operations of assets. A variation in the assumptions used could lead to a different conclusion regarding the recoverability of an asset or asset group and, thus, could potentially result in material future impairments. An impairment evaluation is based on an undiscounted cash flow analysis at the lowest level at which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. The lowest level of independent cash flows is determined by the evaluation of several factors, including the geographic dispatch of the generating units and the hedging strategies related to those units. The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group), given the interdependency of cash flows generated from the customer supply and risk management activities within each region. In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewable generation). 54 Table of Contents 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 asset or asset groups. This includes significant assumptions of the estimated future cash flows generated by the asset 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, 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, supported by formal depreciation studies of historical asset retirement experience. Depreciation studies are generally conducted periodically if an event, regulatory action, or change in retirement patterns indicate an update is necessary. Along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated useful lives of our generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant. When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on future results of operations. Changes in estimated useful lives of electric generating assets could have a significant impact on future results of operations. See Note 1 — Basis of Presentation and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated useful lives of the property, plant and equipment. 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 authoritative guidance, could result in previously excluded contracts becoming in scope of new 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 entered for economic hedging and for proprietary trading purposes are recorded at fair value through earnings. NPNS transactions are not required to be recorded at fair value, but rather on an accrual basis of accounting. Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements. 55 Table of Contents 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 reassess our economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP. As a part of the authoritative guidance, we make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions. Under the authoritative guidance for fair value measurements, we categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. 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 The majority of our employees participate in defined benefit pension and OPEB plans 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, 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. 56 Table of Contents Discount Rate. Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality non-callable (or callable with make-whole provisions) 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, 2023 and 2024, 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: Actual Assumption Pension OPEB Assumption Increase / (Decrease) Actuarial Assumption Pension OPEB Total Change in 2025 cost: Discount rate (a) 5.66 % 5.63 % 0.5 % $ (13) $ (1) $ (14) 5.66 % 5.63 % (0.5) % 17 1 18 EROA 6.50 % 6.00 % 0.5 % (38) (3) (41) 6.50 % 6.00 % (0.5) % 38 3 41 Change in benefit obligation as of December 31, 2024: Discount rate (a) 5.66 % 5.63 % 0.5 % (319) (59) (378) 5.66 % 5.63 % (0.5) % 346 64 410 __________ (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 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. 57 Table of Contents 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 consolidated financial statements. 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 consolidated financial statements. 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 the consolidated financial statements. 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 services 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. 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 58 Table of Contents guidance expected to be issued from the U.S. Treasury and IRS that may materially impact the total amount of benefits we receive. Absence of prescriptive guidance requires the application of judgement 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 regarding nuclear PTC. Derivative Revenues. We record revenues and expenses using the fair value method of accounting, also referred to as mark-to-market method of accounting for transactions that are accounted for as derivatives. These derivative transactions primarily relate to commodity price risk management activities. Mark-to-market 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, 2024 compared to the same period in 2023. For additional information regarding the financial results for the years ended December 31, 2024 and 2023, see the discussions of Results of Operations below. For the Years Ended December 31, $ Change 2024 2023 GAAP Net Income (Loss) Attributable to Common Shareholders $ 3,749 $ 1,623 $ 2,126 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. 59 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. For all adjustments except the NDT fund investment returns, which are included in decommissioning-related activities, the marginal statutory income tax rate was 25.5% and 25.1% for the years ended December 31, 2024 and 2023, respectively. Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds. The effective tax rates for the unrealized and realized gains and losses related to NDT funds were 54.8% and 52.4% for the years ended December 31, 2024 and 2023, 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, 2024 compared to the same period in 2023. For the Years Ended December 31, 2024 2023 Earnings Per Share (a) Earnings Per Share (a) GAAP Net Income (Loss) Attributable to Common Shareholders $ 3,749 $ 11.89 $ 1,623 $ 5.01 Unrealized (Gain) Loss on Fair Value Adjustments (net of taxes $346 and $169, respectively) (b) (1,026) (3.25) 506 1.56 Plant Retirements and Divestitures (net of taxes $9 and $2, respectively) 28 0.09 (7) (0.02) Decommissioning-Related Activities (net of taxes $244 and $339, respectively) (c) (50) (0.16) (183) (0.56) Pension & OPEB Non-Service (Credits) Costs (net of taxes $2 and $14, respectively) 5 0.02 (41) (0.13) Separation Costs (net of taxes $3 and $21, respectively) (d) 9 0.03 62 0.19 ERP System Implementation Costs (net of taxes $3 and $6, respectively) 8 0.02 19 0.06 Change in Environmental Liabilities (net of taxes $22 and $11, respectively) 65 0.21 33 0.10 Income Tax-Related Adjustments (e) (52) (0.17) (9) (0.03) Acquisition-Related Costs (net of taxes $2 and $3, respectively) 6 0.02 9 0.03 Asset Impairments (net of taxes $— and $9, respectively) — — 62 0.19 Noncontrolling Interests (f) (7) (0.02) (40) (0.12) Adjusted (non-GAAP) Operating Earnings $ 2,735 $ 8.67 $ 2,034 $ 6.28 __________ (a) Amounts may not sum due to rounding. Earnings per share amount is based on average diluted common shares outstanding of 315 million and 324 million for the years ended December 31, 2024 and 2023, respectively. (b) Includes mark-to-market 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. (d) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA. See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information. (e) In 2024, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment. (f) Represents elimination of the noncontrolling interest portion of certain adjustments included above. 60 Table of Contents Results of Operations 2024 2023 $ Change Operating revenues $ 23,568 $ 24,918 $ (1,350) Operating expenses Purchased power and fuel 11,419 16,001 (4,582) Operating and maintenance 6,159 5,685 474 Depreciation and amortization 1,123 1,096 27 Taxes other than income taxes 586 553 33 Total operating expenses 19,287 23,335 (4,048) Gain (loss) on sales of assets and businesses 71 27 44 Operating income (loss) 4,352 1,610 2,742 Other income and (deductions) Interest expense, net (506) (431) (75) Other, net 670 1,268 (598) Total other income and (deductions) 164 837 (673) Income (loss) before income taxes 4,516 2,447 2,069 Income tax (benefit) expense 774 859 (85) Equity in income (losses) of unconsolidated affiliates (4) (11) 7 Net income (loss) 3,738 1,577 2,161 Net income (loss) attributable to noncontrolling interests (11) (46) 35 Net income (loss) attributable to common shareholders $ 3,749 $ 1,623 $ 2,126 Year Ended December 31, 2024 Compared to Year Ended December 31, 2023. The variance in Net income (loss) attributable to common shareholders was favorable by $2,126 million primarily due to: • Favorable net mark-to-market activity and other fair value adjustments; • Favorable nuclear PTC activity related to the IRA beginning in 2024; and • Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization. The favorable items were partially offset by: • Higher labor (inclusive of incentives), contracting, and materials; • Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023; • Unfavorable net realized and unrealized NDT activity; and • Lower revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years. 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. 61 Table of Contents For the year ended December 31, 2024 compared to 2023, Operating revenues were as follows: 2024 vs. 2023 2024 2023 $ Change % Change (a) Mid-Atlantic $ 5,522 $ 5,138 $ 384 7.5 % Midwest 4,805 4,658 147 3.2 % New York 2,050 2,021 29 1.4 % ERCOT 1,550 1,346 204 15.2 % Other Power Regions 5,506 5,851 (345) (5.9) % Total reportable segment electric revenues 19,433 19,014 419 2.2 % Other 3,819 4,505 (686) (15.2) % Mark-to-market gains 316 1,399 (1,083) Total Operating revenues $ 23,568 $ 24,918 $ (1,350) (5.4) % __________ (a) % Change in mark-to-market is not a meaningful measure. Sales and Supply Sources. Our sales and supply sources by region are summarized below: 2024 vs. 2023 (GWhs) 2024 2023 Change % Change Nuclear Generation (a) Mid-Atlantic 52,898 53,012 (114) (0.2) % Midwest 95,321 93,768 1,553 1.7 % New York 25,134 25,546 (412) (1.6) % ERCOT 8,358 1,721 6,637 385.6 % Total Nuclear Generation 181,711 174,047 7,664 4.4 % Natural Gas, Oil and Renewables (a) Mid-Atlantic 2,137 2,014 123 6.1 % Midwest 1,116 1,024 92 9.0 % ERCOT 14,778 16,877 (2,099) (12.4) % Other Power Regions 8,692 8,512 180 2.1 % Total Natural Gas, Oil and Renewables 26,723 28,427 (1,704) (6.0) % Purchased Power Mid-Atlantic 15,729 16,509 (780) (4.7) % Midwest 928 984 (56) (5.7) % ERCOT 3,249 5,530 (2,281) (41.2) % Other Power Regions 41,077 44,192 (3,115) (7.0) % Total Purchased Power 60,983 67,215 (6,232) (9.3) % Total Supply/Sales by Region Mid-Atlantic 70,764 71,535 (771) (1.1) % Midwest 97,365 95,776 1,589 1.7 % New York 25,134 25,546 (412) (1.6) % ERCOT 26,385 24,128 2,257 9.4 % Other Power Regions 49,769 52,704 (2,935) (5.6) % Total Supply/Sales by Region 269,417 269,689 (272) (0.1) % __________ (a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants. 62 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. 2024 2023 Nuclear fleet capacity factor 94.6 % 94.4 % Refueling outage days 230 256 Non-refueling outage days 36 51 Nuclear PTC. Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032. The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh. We have evaluated and expect to meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier. Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year. The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party. Many of the state-sponsored programs (i.e., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC. ZEC Prices. We are compensated through state programs for the carbon-free attributes of our nuclear generation. The following table includes the average ZEC reference prices ($/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, 2024 and 2023 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above. 2024 vs. 2023 State (Region) (a) 2024 2023 $ Change % Change New Jersey (Mid-Atlantic) (b) $ 9.98 $ 9.92 $ 0.06 0.6 % Illinois (Midwest) (c) 5.60 5.18 0.42 8.1 % New York (New York) 18.27 19.05 (0.78) (4.1) % __________ (a) See ITEM 1. BUSINESS, Environmental Matters for additional information on the plants receiving payments through state programs. (b) The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known. Following the latest annual update in August 2024, the ZEC price for the delivery period beginning June 2023 through May 2024 was calculated to be $9.95. (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 and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received by each qualifying plant and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 2022 through May 2023, $32.50 per MWh for the period June 2023 through May 2024 and $33.43 per MWh for the period June 2024 through May 2025). 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 63 Table of Contents CMC prices per MWh were $8.05 and $4.13 for the years ended December 31, 2024 and 2023, respectively. The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above. Capacity Prices. We participate in capacity auctions in each of our major regions, except ERCOT which does not have a capacity market. We also incur capacity costs associated with load served, which are factored into customer sales prices. Capacity prices have a material impact on our operating revenues and purchased power and fuel expense. We report capacity on a net monthly basis within each region in either Operating revenues or Purchased power and fuel expense, depending on our net monthly position. The following table presents the average capacity prices ($/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, 2024 and 2023. 2024 vs. 2023 Location (Region) 2024 2023 $ Change % Change Eastern Mid-Atlantic Area Council (Mid-Atlantic) $ 51.89 $ 69.64 $ (17.75) (25.5) % ComEd (Midwest) 31.09 48.64 (17.55) (36.1) % Rest of State (New York) 106.44 137.88 (31.44) (22.8) % Southeast New England (Other) 581.69 91.67 490.02 534.5 % 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. 2024 vs. 2023 Location (Region) 2024 2023 $ Change % Change PJM West (Mid-Atlantic) $ 33.74 $ 33.06 $ 0.68 2.1 % ComEd (Midwest) 25.50 26.64 (1.14) (4.3) % Central (New York) 34.12 26.97 7.15 26.5 % North (ERCOT) 26.97 55.15 (28.18) (51.1) % Southeast Massachusetts (Other) (a) 41.70 37.35 4.35 11.6 % __________ (a) Reflects New England, which comprises the majority of the activity in the Other region. For the year ended December 31, 2024 compared to 2023, changes in Operating revenues by region were approximately as follows: 2024 vs. 2023 $ Change % Change (a) Description Mid-Atlantic $ 384 7.5 % • favorable estimated nuclear PTC revenue of $515 • favorable retail load revenue of $135 primarily due to higher contracted energy prices; partially offset by • unfavorable wholesale load revenue of ($100) primarily due to lower volumes • unfavorable net ZEC program revenue of ($80) due to estimated refund associated with Nuclear PTC • unfavorable settled economic hedges of ($60) due to settled prices relative to hedged prices 64 Table of Contents 2024 vs. 2023 $ Change % Change (a) Description Midwest 147 3.2 % • favorable estimated nuclear PTC revenue of $1,300; partially offset by • unfavorable net ZEC and CMC program revenue of ($750) due to decrease in ZEC revenue realized and estimated pass through associated with nuclear PTC • unfavorable settled economic hedges of ($205) due to settled prices relative to hedged prices • unfavorable net generation and wholesale load revenue of ($85) primarily due to lower load volumes • unfavorable PJM performance bonuses of ($70) due to absence of favorable adjustment in 2023 associated with the December 2022 weather event New York 29 1.4 % • favorable retail load revenue of $155 primarily due to higher load volumes and contracted energy prices • favorable estimated nuclear PTC revenue of $150; partially offset by • unfavorable net ZEC program revenue of ($180) due to estimated refund associated with nuclear PTC and decrease in ZEC price in current planning year • unfavorable settled economic hedges of ($120) due to settled prices relative to hedged prices ERCOT 204 15.2 % • favorable settled economic hedges of $150 due to settled prices relative to hedged prices • favorable estimated nuclear PTC revenue of $110; partially offset by • unfavorable retail load revenue of ($100) primarily due to lower contracted energy prices Other Power Regions (345) (5.9) % • unfavorable wholesale load revenue of ($515) primarily due to lower contracted prices and load volumes; partially offset by • favorable retail load revenue of $200 primarily due to higher contracted energy prices Other (686) (15.2) % • unfavorable gas revenue, inclusive of settled economic hedges, of ($555) primarily due to lower gas prices • no other individually significant items to note Mark-to-market (b) (1,083) • gains on economic hedging activities of $316 in 2024 compared to gains of $1,399 in 2023 Total $ (1,350) (5.4) % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. 65 Table of Contents 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, 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, 2024 compared to 2023, Purchased power and fuel expense were as follows: 2024 vs. 2023 2024 2023 $ Change % Change (a) Mid-Atlantic $ 2,442 $ 2,214 $ 228 10.3 % Midwest 1,603 1,403 200 14.3 % New York 597 770 (173) (22.5) % ERCOT 503 764 (261) (34.2) % Other Power Regions 4,238 4,611 (373) (8.1) % Total electric purchased power and fuel 9,383 9,762 (379) (3.9) % Other 2,997 3,868 (871) (22.5) % Mark-to-market losses (gains) (961) 2,371 (3,332) Total purchased power and fuel $ 11,419 $ 16,001 $ (4,582) (28.6) % __________ (a) % Change in mark-to-market is not a meaningful measure. For the year ended December 31, 2024 compared to 2023, changes in Purchased power and fuel expense by region were approximately as follows: 2024 vs. 2023 $ Change % Change (a) Description Mid-Atlantic $ 228 10.3 % • unfavorable cost of ($100) associated with purchased power to supply load relative to generation volumes primarily driven by higher prices during peak load periods and higher net transmission costs • unfavorable settlement of economic hedges of ($75) due to settled prices relative to hedged prices Midwest 200 14.3 % • unfavorable cost of ($170) associated with purchased power to supply load relative to generation volumes primarily driven by higher net transmission costs • unfavorable nuclear fuel cost of ($55) primarily due to higher amortization rates related to the reversal of the previous decision in 2020 to retire certain sites New York (173) (22.5) % • favorable settlement of economic hedges of $230 due to settled prices relative to hedged prices ERCOT (261) (34.2) % • favorable cost of $245 associated with purchased power to supply load relative to generation volumes primarily due to higher generation volumes • favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices Other Power Regions (373) (8.1) % • favorable purchased power and fuel of $390 primarily due to lower energy prices and load served, partially offset by the expiration of the Mystic COS 66 Table of Contents 2024 vs. 2023 $ Change % Change (a) Description Other (871) (22.5) % • favorable net gas purchases, inclusive of settled economic hedges, of $730 primarily due to lower gas prices • favorable purchases in the United Kingdom, inclusive of settled economic hedges, of $95 primarily due to lower energy prices Mark-to-market (b) (3,332) • gains on economic hedging activities of $961 in 2024 compared to losses of ($2,371) in 2023 Total $ (4,582) (28.6) % __________ (a) % Change in mark-to-market is not a meaningful measure. (b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses. The changes in Operating and maintenance expense consisted of the following: 2024 vs. 2023 Increase (Decrease) Labor, other benefits, contracting, and materials (a) $ 495 Plant retirements and divestitures 47 Change in environmental liabilities 43 Decommissioning-related activities 37 Nuclear refueling outage costs (b) 6 Asset impairments (71) Separation costs (90) Other 7 Total increase $ 474 __________ (a) Primarily reflects increased employee incentive program costs, driven by stock compensation expense and Company performance exceeding relative metrics, increased headcount, and the acquisition of STP in November 2023. (b) Includes the co-owned Salem and STP generating units. Other, net was unfavorable for the year ended December 31, 2024 compared to the same period in 2023, due to activity described in the table below: Income (Deductions) For the Years Ended December 31, 2024 2023 Decommissioning-related activities (a) $ 567 $ 803 Non-service net periodic benefit credit (cost) (8) 54 Net realized and unrealized gains (losses) from equity investments 11 307 Other 100 104 Other, net $ 670 $ 1,268 __________ (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. 67 Table of Contents Effective income tax rates were 17.1% and 35.1% for the years ended December 31, 2024 and 2023, respectively. The change in effective tax rate in 2024 compared 2023 is primarily attributable to the inclusion of nuclear PTCs which are non-taxable. See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information. Liquidity and Capital Resources For discussion of the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2023 Form 10-K which was filed with the SEC on February 27, 2024. 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, the sale of certain receivables, 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. 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., 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 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 Flows from Operating Activities Our cash flows from operating activities include the sale of energy, energy-related products, and sustainable solutions, as well as sales of nuclear PTCs. Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers. The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2024 and 2023: For the Years Ended December 31, Cash flows from operating activities 2024 2023 $ Change Net income (loss) $ 3,738 $ 1,577 $ 2,161 Adjustments to reconcile net income (loss) to cash: Collateral received (posted), net 1,803 (1,491) 3,294 Option premiums received (paid), net 216 26 190 Pension and non-pension postretirement benefit contributions (184) (54) (130) Changes in working capital and other noncurrent assets and liabilities (a) (9,168) (8,355) (813) Total non-cash operating activities (b) 1,131 2,996 (1,865) Net cash flows provided by (used in) operating activities $ (2,464) $ (5,301) $ 2,837 68 Table of Contents __________ (a) Includes changes in Accounts receivable, Inventories, Accounts payable and accrued expenses, Income taxes, and Other assets and liabilities. (b) See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Asset impairments, Gain on sale of assets and businesses, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments. See Note 22 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line. Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below. Significant operating cash flow impacts for 2024 and 2023 were as follows: • In 2024, $1,570 million of cash was received related to the sale of nuclear PTCs. See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information. • Depending upon whether we are in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from our counterparties, respectively. In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets. See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral. • Option premiums received (paid), net relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices. Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts. • Increase in cash outflows for pension and non-pension postretirement benefit contributions is primarily due to our annual qualified pension contribution of $161 million and $21 million made in February 2024 and July 2023, respectively. See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans. • A net increase in cash outflows for changes in working capital and other noncurrent assets and liabilities primarily driven by an increase in cash collections applied to the Deferred Purchase Price (DPP) partially offset by an increase in liabilities associated with state-sponsored programs requiring refund or pass through of the nuclear PTC, as well as price changes related to natural gas purchases in 2024. See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable. Cash Flows from Investing Activities The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2024 and 2023: For the Years Ended December 31, Cash flows from investing activities 2024 2023 $ Change Collection of DPP, net $ 10,217 $ 7,340 $ 2,877 Acquisitions of assets and businesses (32) (1,690) 1,658 Investment in NDT funds, net (277) (228) (49) Capital expenditures (2,565) (2,422) (143) Other investing activities 85 31 54 Net cash flows provided by (used in) investing activities $ 7,428 $ 3,031 $ 4,397 69 Table of Contents Significant investing cash flow impacts for 2024 and 2023 were as follows: • Collection of DPP, net increased primarily due to the increased cash collections applied to DPP as a result of a decrease in the drawn Facility balance in 2024 compared to 2023. In addition, more cash collections were reinvested in the Facility in 2024. See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information. • See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the STP acquisition in November 2023. • Variances in capital expenditures are primarily due to the timing of cash payments for capital projects. See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending. Cash Flows from Financing Activities The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2024 and 2023: For the Years Ended December 31, Cash flows from financing activities 2024 2023 $ Change Long-term debt, net $ 799 $ 3,027 $ (2,228) Changes in short-term borrowings, net (1,644) 485 (2,129) Dividends paid on common stock (444) (366) (78) Repurchases of common stock (999) (992) (7) Other financing activities (1) 42 (43) Net cash flows provided by (used in) financing activities $ (2,289) $ 2,196 $ (4,485) Significant financing cash flow impacts for 2024 and 2023 were as follows: • Long-term debt, net varies due to debt issuances and redemptions each year. Refer to the Debt Issuances and Redemptions tables below for additional information. • Changes in short-term borrowings, net is driven by repayments on and issuances of notes due in less than 365 days. Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information. • Refer to ITEM 5. — MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES for additional information on dividends. See below for quarterly dividends declared. • Repurchases of common stock is related to our share repurchase program that commenced in March 2023. See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information. 70 Table of Contents 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 2024 and 2023 was as follows: 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) The Green Senior Notes were 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) Energy Efficiency Project Financing 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%. During 2023, the following long-term debt was issued (redeemed): Type Interest Rate Maturity Amount 2053 Senior Notes 6.50 % October 2053 $ 900 2028 Senior Notes 5.60 % March 2028 750 2033 Senior Notes 5.80 % March 2033 600 2034 Senior Notes 6.13 % January 2034 500 Tax-Exempt Notes Reoffering 4.10% - 4.45% 2025 - 2053 (a) 435 Energy Efficiency Project Financing (b) 2.20% - 4.96% March 2024 - June 2024 11 Energy Efficiency Project Financing 2.44% - 6.96% May 2023 - March 2024 (44) CR Nonrecourse Debt 3-month SOFR + 2.76% (c) December 2027 (39) West Medway II Nonrecourse Debt 1-month SOFR + 2.975% - 3.225% (d)(e) March 2026 (26) Continental Wind Nonrecourse Debt 6.00 % February 2033 (25) Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (25) RPG Nonrecourse Debt 4.11 % March 2035 (9) Total long-term debt issued (redeemed) $ 3,028 __________ (a) The Tax-exempt notes have a maturity date of March 2025 - April 2053, and a mandatory purchase date that ranges from March 2025 - June 2029. (b) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt. 71 Table of Contents (c) The interest rate for long-term debt redemptions prior to June 2023 were based on LIBOR + 2.50%. Beginning in June 2023, these redemptions are based on SOFR + 2.76%. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the CR nonrecourse debt. (d) The interest rate for long-term debt redemptions prior to May 2023 were based on LIBOR + 2.875%. Beginning in May 2023, these redemptions are based on SOFR + the variable interest rate of 2.975% - 3.225%. See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the West Medway II nonrecourse debt. (e) The nonrecourse debt has an average blended interest rate. Dividends Quarterly dividends declared by our Board of Directors during 2024 and for the first quarter of 2025 were as follows: Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share First Quarter of 2024 February 26, 2024 March 8, 2024 March 19, 2024 $ 0.3525 Second Quarter of 2024 May 1, 2024 May 29, 2024 June 10, 2024 $ 0.3525 Third Quarter of 2024 July 30, 2024 August 12, 2024 September 6, 2024 $ 0.3525 Fourth Quarter of 2024 November 1, 2024 November 15, 2024 December 6, 2024 $ 0.3525 First Quarter of 2025 February 18, 2025 March 7, 2025 March 18, 2025 $ 0.3878 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, 2024, we have access to facilities with aggregate bank commitments of $9 billion. We had access to the commercial paper markets and had availability under our revolving credit facilities during 2024 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 necessary to close on our proposed 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 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 December 31, 2024 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively. As of December 31, 2024, we had $6.7 billion of available capacity under our credit facilities and $3 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 following the announcement of our proposed acquisition of Calpine. If we had lost our investment grade credit ratings as of December 31, 2024, we would have been required to provide incremental collateral estimated to be approximately $1.9 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. 72 Table of Contents 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 is approximately $3 billion and $3.5 billion for 2025 and 2026, respectively. Approximately 35% of projected capital expenditures are 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 includes $1.7 billion of growth capital expenditures, including our planned restart of Crane, nuclear uprates, behind-the-meter 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 and 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. 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 levelized 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. Expected contributions in 2025 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. 73 Table of Contents Cash Requirements for Other Financial Commitments The following table summarizes our projected cash payments as of December 31, 2024 under existing financial commitments with fixed or minimum payments required: 2025 Beyond 2025 Total Time Period Long-term debt $ 1,028 $ 7,446 $ 8,474 2025 - 2054 Interest payments on long-term debt (a) 438 5,805 6,243 2025 - 2054 Operating leases (b) 58 409 467 2025 - 2056 Purchase power obligations (c) 891 1,056 1,947 2025 - 2036 Fuel purchase agreements (d) 1,381 8,630 10,011 2025 - 2040 Other purchase obligations (e) 1,400 1,992 3,392 2025 - 2057 SNF obligation — 1,366 1,366 2025 - 2040 Pension contributions (f) 163 701 864 2025 - 2030 Total cash requirements $ 5,359 $ 27,405 $ 32,764 __________ (a) Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2024 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, 2024. (b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $47 million and $230 million for 2025 and beyond 2025, respectively and $277 million in total. (c) Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability. Expected payments exclude payments on renewable generation contracts that are contingent in nature. (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, 2024 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. See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of 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 Sales of Customer Accounts Receivable We had an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables. The facility was amended effective December 31, 2024 resulting in an increased funding limit secured by certain receivables. See Note 7 — Accounts Receivable and 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 74 Table of Contents 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. 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, 2024, our capital structure consisted of the following: Percentage of Capital Structure Long-term debt 38 % 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 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, 2024, 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, 2024, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion 75 Table of Contents 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.