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

The effects of storms, floods, and other climatic events could disrupt our operations and cause us to incur significant costs in preparing for or responding to these effects. These or other meteorological changes could lead to increased operating costs, capital expenses, or power purchase costs. Such climatic events could also affect the availability of a secure and economical fuel and water supplysupplies in some locations, both of which isare essential for the continued operation of our generation facilities.

Market competition may adversely affect our ability to operate profitably and generate positive cash flow. We sell our capacity, electricity, and ancillary services into competitive wholesale markets through a combination of capacity auctions, day-ahead and real-time spot markets, and bilateralfutures agreements.contracts. Our business model depends on us successfully operating in a competitive environment and, unlike regulated utilities, we are not assured of any rate of return on capital investments through a regulated rate structure. Competitors in wholesale power markets include other non-utility generators, regulated utilities and their competitive subsidiaries, industrial companies, financial institutions, and other energy marketers. See also “Item 1. Business—Our Operations—Competition.” Some of our competitors may have advantages over us through access to greater resources, newer generation facilities, lower costs, or more experience. Our ability to compete is affected primarily by electricity prices, fuel prices, the relative cost of electric generation, and the reliability and availability of generation assets. These factors can be impacted by generation additions or retirements from the market, changes in natural gas distribution networks that affect the price and availability of fuel utilized for electric generation, changes in storage assets and transmission capacity, and technological advances in power generation and efficiency. Competition may also be impacted by the actions of environmental and other governmental authorities, including but not limited to the establishment of legislation or subsidies favoring one form of generation over another (such as investment tax credits, production tax credits, and other factors); for example, the Inflation Reduction Act contains a number of tax credits and incentives relating to renewable energy projects and clean energy technologies. Any negative impact on our ability to compete could adversely impact our business. See also “—Regulatory, Environmental, and Legal Risks—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.”

Our business is subject to extensive energy, reliability, market, nuclear, environmental, and safety laws, regulations, and requirements, among others. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters.” Some of the key rules and regulations impacting our business include, among others, those set forth by: (i) the FERC, relating to the generation, sale, and transmission of electricity, and its designated Electric Reliability Organization (currently NERC), relating to reliability standards for the bulk power system; (ii) PJM and ISO-NE,PJM, relating to the reliability and performance of generation facilities and operation of the energy and capacity markets; (iii) the NRC, relating to the licensing, operation, and ownership of nuclear facilities; (iv) the EPA, relating to environmental protection and permitting; and (v) various state and local jurisdictions, relating to similar and other matters. We may also from time-to-time become subject to new or revised laws, regulations, or requirements. The costs of compliance with these requirements may be substantial, and any non-compliance or inability to comply could result in the suspension or curtailment of our electricity sales and power delivery; the cessation, suspension, delay, or limitation of our operations; premature unit retirements; and (or) monetary penalties, increased compliance obligations, or other types of sanctions. See also “—Regulatory, Environmental, and Legal Risks.”

Our business could be adversely affected by events outside of our control, including armed conflicts, war, terrorist attacks or threats, government shutdowns, pandemics, natural disasters, cyber-based attacks, or other significant events.

Instability and unrest, as well as war, other armed conflicts, economic sanctions, acts of terrorism, or threats thereof may lead to economic disruption that could adversely affect our business through high volatility in fuel and other commodity prices, difficulty obtaining products such as nuclear fuel, disruptions in supply chains, disruptions or volatility in financial markets, or other factors. Additionally, during periods of federal government shutdowns, many government agencies cease to operate at full capacity or at all, which could result in the suspension of ongoing application processes, significant delays in regulatory approvals or other project timing, and difficulty in conducting any other business requiring government participation or approval. In addition, we could be adversely affected by an epidemic, an infectious disease outbreak, or other public health events, which could impact our workforce and the availability of other resources, resulting in decreased service levels and increased costs. Furthermore, as a significant portion of our power generation facilities are geographically concentrated in the mid-Atlantic area of the United States, we face increased risk that a natural or man-made disaster in that area could adversely affect a large part of our operations.

We are exposed to price variability associated with future sales and (or) purchases of power products, fuel, environmental products, and other commodities in competitive wholesale markets, which contribute to uncertainty in the future performance and cash flows of our business. See also “—Industry and Market Risks—We may be adversely impacted by changes in the market prices, availability, and transmission of electricity, fuel, and other commodities.” We actively manage the market risk inherent in our business through our commercial risk management activities, which utilize a variety of physical and financial instruments to protect cash flow and preserve forward margin. See also “Item 1. Business—Our Strategies—OptimizeContinue to focus on our core generation fleet that provides stable earnings and cash flows through operational excellence, high reliability, capital discipline, and prudent risk management program and hedging.management.” Nonetheless, such activities may not effectively manage or fully eliminate risks as expected due to differing conditions than those assumed or forecasted, including those related to demand, pricing, volatility, market correlations, generation facility availability, unforeseen market disruptions, and weather events. Given the inherent uncertainty in developing future market expectations, actual market conditions could be materially different than our expectations. The financial markets in which we hedge may have insufficient liquidity or excessive counterparty risk, impairing our ability to enter into new transactions. Furthermore, when a commercial contract expires or is terminated, we may not secure replacement on acceptable terms or at all, and it is possible that subsequent commercial contracts may not be available at prices that permit the operation of our generation fleet on a profitable basis. If our commercial risk management activities are unable to predict or manage the market risk inherent in our operations, economic losses or other costs to our business could result.

Facility outages could also subject us to market or contractual penalties. Under PJM’s Capacity Performance model, we may be (and have in the past been) subject to substantial monetary penalties for failing to meet the Capacity Performance requirements set forth by PJM in certain emergency events. For example, during Winter Storm Elliott in 2022, certain of our generation facilities failedincurred Capacity Performance penalties for failing to meet PJM’s Capacity Performance requirements and,during asWinter aStorm result,Elliott wein incurred final aggregate net Capacity Performance penalties of $29 million.2022. See also “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets—Capacity Performance Event” and “—Regulatory, Environmental, and Legal Risks.” Additionally, under the AWS PPA, Susquehannawe hashave committed to certain delivery quantities over time andwith agreed reliability standards and AWS may be entitled to contractual or other remedies in the event of Susquehanna’sour non-performance.

Since 2016, we have retired three economically nonviableuneconomic coal-fired units, while our remaining coal-fired generation assets continue to be impacted by changing environmental regulations and power market economics. Although we recently reached a settlement agreement for the continued RMR operation of our Brandon Shores (a coal asset) and H.A. Wagner (formerly a coal asset, now operating primarily on fuel oil) facilities through May 2029, we do not currently anticipate that those assets willmay not continue to run beyond that date unless PJM continues to require their operation to maintain grid reliability. In addition, although our Brunner Island facility has been converted and can now run on either coal or natural gas, it remains a legacy coal facility with associated remediation obligations. We likewise have remaining liabilities associated with historical coal-fired generation at other legacy sites. We also own minority interests in three additional coal-fired facilities, including the Colstrip facility in Montana, of which we are the operator. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Forecasted Uses of Cash—Projected ARO and Accrued Environmental Liability Cash Flows” and Note 129 to the Annual Financial Statements for additional information on environmental remediation obligations. In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of capital, internal resources, and time to complete the required closure and reclamation.

Our ability to attract and retain key employees is important to both our operational and financial performance. In addition, effective succession planning is also important to our long-term success. We cannot guarantee that any member of our leadership or workforce will continue to serve in any capacity for any particular period of time.time Weand we could have difficulty retaining certain key members of management beyond Maytheir 2026,currently whenagreed aemployment significantand portioncompensation arrangements, many of ourwhich outstandingexpire long-termin equity-basedearly incentive2027. compensation is scheduledFailure to vest.timely and effectively ensure the transfer of knowledge and smooth transitions involving senior management and other key personnel could hinder our strategic planning and execution. Furthermore, an aging workforce with significant retirement eligibility, mismatch of skill set, expectation of future needs, uncertainty around the future of our aging assets, or unavailability of short-term contract employees or contractors may lead to difficulty retaining our workforce, operating challenges, and increased costs. Additional challenges we could face include a lack of human resources, losses to our operational knowledge base, and the required time and other resources needed to develop new workers’ skills. In particular, our operations at Susquehanna largely depend on highly specialized personnel whose absence may adversely impact our ability to operate. We are also subject to the risk of organized actions by unionized employees which,which asrepresent ofa Decembersignificant 31, 2024, represented approximately 43%proportion of our workforce. If we are unable to negotiate future collective bargaining agreements on favorable terms, or if our union employees were to engage in strikes, work stoppages, slowdowns, or other forms of labor disruption, we would be responsible for obtaining replacement labor and could experience increased costs, reduced power generation, outages, other operational disruptions, or reputational harm.

We could also engage in mergers, business combinations, or similar corporate transactions. In addition to the types of risks discussed above, mergers and similar transactions may subject us to risks associated with: required stockholder approvals and other stockholder legal actions; changes or fluctuations in merger consideration that could affect the value our stockholders receive; changes in management or control of our business; challenges integrating or operating the combined company; or failure to realize the anticipated business opportunities, synergies, growth prospects, or other benefits. Any acquisition, divestiture, merger, or other corporate transaction could occupy a significant amount of our time and may strain our resources, increase our costs, and distract management. Furthermore, the extensive regulation of our business could delay, prevent, limit the scope of, or increase the costs associated with any such transaction. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters” and “—Regulatory, Environmental, and Legal Risks.” Any failure to meet contractual terms, whether for regulatory or other reasons, could result in transaction cancellation, costly disputes or litigation, breakage or other fees, or other costs and liabilities. No assurance can be provided that any such transaction will result in the anticipated benefits to our business or stockholders. See also “—Risks Related to the Cornerstone Acquisition.”

We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to the FERC; the Department of Energy; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters—Energy Regulation” and “—Our ownership and operation of a nuclear power facility subjects us to regulations, costs, and liabilities uniquely associated with these types of facilities.”

Certain of our subsidiaries sell electricity into the wholesale markets and are subject to rate, financial, and organizational regulation by the FERC. The FERC has authorized us to sell energy, capacity, and ancillary services at wholesale at market-based rates and has granted us various related customary waivers and blanket approvals, including a blanket authorization to issue securities and to assume liabilities. The FERC retains the authority to modify or withdraw our market-based rate authority and impose cost-based rates if it determines that the market is not competitive, we possess market power in one or more markets, we are not charging just and reasonable and not unduly discriminatory rates, or we have violated the FERC’s market behavior rules or engaged in market manipulation. Any reduction by the FERC in the rates that we may receive, revocation of the FERC’s waivers and blanket authorizations, or unfavorable changes to the regulation of our business by federal or state regulators could materially adversely affect our business. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.” See "Item 3. Legal Proceedings” for additional information on the Susquehanna ISA Amendment. In addition, if we were found to have violated the FERC’s market behavior rules or other FERCrequirements requirements,of the FERC, the FERC could impose civil penalties or order us to disgorge associated profits. Our generation assets are also subject to the reliability standards promulgated by the FERC-designated Electric Reliability Organization (currently NERC) and approved by the FERC. If we fail to comply with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties and increased compliance obligations.

We do not own or control the transmission facilities required to deliver the wholesale power from our generation facilities to load. The FERC has issued regulations that require wholesale electricity transmission services, even when offered by parties other than RTOs and ISOs, to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale markets, there can be no assurance that transmission capacity will be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives, the adequacy of transmission facilities, or whether RTOs, ISOs, or other transmission providers will efficiently operate transmission networks and provide related services. Furthermore, regulatory approvals and orders that we have obtained may be subject to challenge and protest from time to time.

The wholesale energy markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, and compliance or failure of any of these markets could adversely impact our business. The PJM market is undergoing significant restructuring due to projected increases in demand, projected retirements of supply, and recent weather events that have exposed systemic flaws. Ongoing market reforms have caused delays in the PJM Base Residual Auctions, which determine capacity prices in upcoming years, leading to unpredictability around capacity revenues due to lack of reliable pricing and on-schedule BRAs. While PJM has established dates for certain upcoming PJM BRAs based upon FERCthe FERC’s orders establishing rules for such capacity markets, we cannot guarantee those auctions will take place on those dates or at all. In addition, under PJM’s Capacity Performance model, we may be (and have in the past been) subject to substantial monetary penalties for failing to meet the Capacity Performance requirements set forth by PJM in certain emergency events. Continued efforts to address perceived capacity market design issues are ongoing, and we cannot predict the outcome of these market reforms or their impact on future capacity revenues. See Note 129 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, BRA delays, and related legal actions.

These efforts are resulting in increased regulation of fossil fuel combustion, GHG emissions, and other related activities. Any resulting changes to the legal and regulatory framework governing electric generation could materially impact our business. For example, new air, waste, and water rules finalized by the EPA in 2024 could require us to incur significant costs if they withstand legal challenges and potential rescission or revision by the Trump administration. These costs include ARO revisions, potential asset modifications, including investments in environmental control equipment, premature retirement or reduced operations, and increased public reporting requirements. See “Item 1. Business—Legal, Regulatory, and Environmental Matters—Environmental Regulation” and Note 129 to the Annual Financial Statements for additional information. Furthermore, any new legislation or regulatory programs could also increase the cost of electricity production or make certain units unavailable or restricted, overall reducing the amount of reliable and affordable power available to meet our nation’s growing electricity demand.

In addition, the EPA recently finalized standards under the EPA GHG Rule in 2024 for new and certain existing power plants. These regulations primarily affect baseload units in the national power fleet, including our coal-fired generation facilities that have not set near-term retirement dates (e.g., Colstrip). More stringent limits on carbon dioxide and other GHG emissions and carbon taxes could be implemented or expanded at the state or regional levels. Recently, certain state legislatures have considered bills that could materially affect our ability to operate our coal-fueled generation facilities. Furthermore, other recent EPA rules (e.g., the EPA MATS, CCR,CCR and ELG Rules) could have a significant impact on our business as discussed herein. Each of these rules are currently subject to ongoing legal challenges. In addition, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Under the Trump Administration, the EPA is currently reconsidering many of the regulations that impact fossil fuel-fired power plants. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

While Susquehanna maintains property and liability insurance and is subject to NRC insurance requirements and the Price-Anderson Act scheme, there may be limitations on the amounts and types of insurance commercially available to us or we may have insufficient coverage with respect to any losses. See Note 129 to the Annual Financial Statements for additional information on nuclear insurance. Uninsured losses and other liabilities and expenses resulting from an incident at Susquehanna, to the extent not recovered from insurers or the nuclear industry, could be borne by us. See also “—IndustryCommercial and MarketOperational Risks—Operation of power generation facilities involves significant risks and hazards customary to the power industry, which we cannot assure our insurance will be adequate to cover.” Additionally, an accident or other significant event at a nuclear facility within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. If an incident did occur at Susquehanna, any resulting operational loss, damages, and injuries would likely have a material adverse effect on our business.

Changes in tax law (including any elimination of the Nuclear PTC),law, the implementation regulations of certain tax provisions, adverse decisions by tax authorities, or thechanges impositionto of(and uncertainty surrounding) U.S. and international tariffs and trade may adversely affect our business.

The laws and rules pertaining to U.S. federal, state, and local income taxation are routinely being reviewed and modified by governmental bodies, officials, and regulatory agencies, including the Internal Revenue Service (“IRS”) and the U.S. Treasury Department. It cannot be predicted whether, when, in what form, or with what effective dates tax laws, regulations, and rulings may be enacted, promulgated, or issued, which could result in changes in the estimated values of recorded deferred tax assets and liabilities and future income tax assets and liabilities and an increase in our effective tax rate and tax liability. For example, the Inflation Reduction Act was signed into law in August 2022. Among the Inflation Reduction Act’s provisions are changes to the U.S. corporate income tax system, including a one percent excise tax on certain repurchases of stock (and economically similar transactions) after December 31, 2022. The Inflation Reduction Act also includes amendments to the Internal Revenue Code of 1986, as amended (the “Code”), toto, among other things, create a nuclear production tax credit program. While electricity produced and sold by Susquehanna through December 31, 2032 may qualify for the Nuclear PTC, which is subject to potential adjustments, these provisions are subject to implementation regulations, the terms of which are not yet fully known. Accordingly, we cannot fully predict the impacts that any such tax credits may have on our liquidity or results of operations. Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value recognized, and any elimination of the Nuclear PTC mayprogram adverselywhich, affectif eliminated, could negatively impact our business and financial condition. See Note 2 to the Annual Financial Statements for our accounting policy related to Nuclear PTC and Note 6 to the Annual Financial Statements for Nuclear PTC revenue recognized. Additionally, the imposition of new tariffs by government authorities or the increase of existing tariffs could materially increase the prices we pay for fuel, materials, supplies, equipment, parts, and (or) other critical products that are integral to our operations.business.

Our ability to utilize our tax attributes, including net operating loss and interest carryforwards, remaining following Emergence, if any, may be limited.

Furthermore, the agreements governing TES’s indebtedness restrict the ability of TES and the Subsidiary Guarantors to pay dividends or distributions or otherwise transfer assets to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or distributions: (1) in an amount not to exceed the greater of $420 million and 40% of TES’s consolidated adjusted EBITDA, (2) in an unlimited amount so long as TES’s pro forma consolidated total net leverage ratio is less than or equal to 2.5 to 1.0, and (3) in an amount not to exceed the sum of: (a) the greater of $525 million and 50% of TES’s consolidated adjusted EBITDA, (b) TES’s consolidated adjusted EBITDA minus 140% of TES’s consolidated interest expense, in each case, for the period beginningfrom June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components. See also “—The amount and terms of our indebtedness could adversely affect our financial condition and impair our ability to operate our business.”

Sales of a substantial number of shares of our common stock in the public market could occur at any time. If at any time there are more shares of our common stock offered for sale than buyers are willing to purchase, then the market price of our common stock may decline, which could both affect our stockholders and also impair our ability to obtain capital (especially equity capital). Substantial sales of our common stock in the public market, or merely the market perception that large stockholders intend to sell shares (particularly with respect to our affiliates, directors, executive officers, or other insiders), could depress the market price or trading volume of our common stock. We currently expect a significant number of shares of our common stock to be issued and (or) become unrestricted in May 2025 and May 2026 upon the vesting and (or) release from lock-up of shares pursuant to certain existing awards under equity compensation plans, and those shares will become unrestricted in May 2026.plans. We may also issue additional shares under future grants of equity compensation awards, to raise capital, or in connection with future potential corporate alliances or acquisitions. For example, we expect to issue, and will be required to register, a substantial amount of common stock in connection with the proposed Cornerstone Acquisition. See “Item 1. Business—Recent Developments—Cornerstone Acquisition” for additional information.

The threefour largest TEC stockholders collectively own approximately 30%33% of our outstanding shares of common stock. Large holders such as these may be able to significantly affect matters requiring approval by our stockholders, including but not limited to the election of directors and the approval of mergers or other business combination transactions. Furthermore, we are a Delaware corporation and the anti-takeover provisions of the Delaware General Corporation Law may discourage, delay, or prevent a change in control by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder, even if a change in control would be beneficial to our existing stockholders.

As aan newlyindependent, publicpublicly traded company, we are or will be required to comply with additional laws, regulations, and requirements, including but not limited to applicable SEC rules and regulations, certain provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), including maintaining internal control over financial reporting and reporting any material weaknesses in our control, and Nasdaq rules and requirements. These requirements cover a wide variety of topics including many aspects of disclosure, financial reporting, internal controls, and corporate governance, among others. Complying with these laws, regulations, and requirements will occupy a significant amount of our time and may strain our resources, increase our costs, and distract management, all of which may inhibit our ability to comply with these requirements in a timely or cost-effective manner.

InWe particular,have, and will continue to, design, implement and test the internal controlscontrol and procedures required for public companyover financial reporting under Section 404 of the Sarbanes-Oxley Act are significantly more stringent than those required forto acomply privatewith company.this Fullyobligation implementingbut oursuch internalprocess controlis frameworkcomplex, time-consuming, and testing will require significant resources,costly, and management may not be able to timely and effectively implement the necessary controls and procedures. At any time, we may conclude that our internal controls, once tested, are not operating as designed or do not address all relevant financial reporting risks. InFurthermore, addition,projections onceof requiredany evaluation of effectiveness to attestfuture periods are subject to controlthe effectiveness,risk ourthat independent registered public accounting firmcontrols may issuebecome ainadequate reportbecause concludingof changes in conditions, or that ourthe internaldegree controlsof overcompliance financialwith reportingthe arepolicies notor effective.procedures may deteriorate. If we identify material weaknesses in the future or otherwise fail to implement or maintain effective internal controls over financial reporting, we may not be able to accurately or timely comply with our financial reporting obligations, which may subject us to adverse regulatory consequences, negatively affect our business, harm investor confidence, and (or) reduce the market price of our common stock.

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the Annual Financial Statements and the accompanying notes.notes Theincluded discussion contains forward-looking statements as well as estimates regarding market and industry data, which involve risks, uncertainties, and assumptions. See “Cautionary Note Regarding Forward-Looking Information” and “Market and Industry Data” for additional information. Dollars areelsewhere in millions,this unless otherwise noted.Report.

CommonCornerstone Stock TransactionsAcquisition

See Note 1817 to the Annual Financial Statements for additional information on the SRP,Cornerstone other share repurchases,Acquisition and other“Item common1A. stockRisk transactions.Factors—Risks Related to the Cornerstone Acquisition” of this Report for a discussion of the associated risks.

See NoteNotes 1310 and 17 to the Annual Financial Statements for additional information on long-termthe debt,financing other credit facilities,transactions and recentissuance financingof activities.the Unsecured Notes, and the Freedom and Guernsey Acquisitions, respectively.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, 2024 (Successor), December 31, 2023 (Successor), and December 31, 2022 (Predecessor) were:

(ba)Represents forward prices for 20242025 as of December 31, 20232024 (Successor). See weighted average settled prices table above for 20242025 realized prices.

Our generation capacityfacilities isare located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, RTO/ISOpower demand forecasts, reserve margin targets,targets andand, (in PJM)PJM, adjustments to the PJM Marketmarket Sellerseller Offeroffer Capcap as determined by the PJM Independentindependent Marketmarket Monitor.monitor. Additionally, capacity prices may be affected by regulatory proceedings and (or) interventions by government stakeholders.

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM Base Residual AuctionBRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year. However, PJM has delayed its recent BRAs, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The BRA for the 2025/2026 Capacity Year, which was the most recent auction, was held in July 2024. The BRA for the 2026/2027 Capacity Year is currently delayed until July 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 12 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, BRA delays, and related legal actions.

For the 20252027/20262028 PJM Capacity Year, wethe Company cleared a total of 6,8208,745 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas.$333.44/MWd.

The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC programprogram, established by the Inflation Reduction Act, provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $43.75$44.60/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $25$26/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. Susquehanna earned Nuclear PTC revenue during the year ended December 31, 2024 (Successor). However, as prevailing market prices exceeded the PTC recognition threshold during the year ended December 31, 2025 (Successor), no such tax credits were earned for the period. See Notes 63 and 74 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the Inflationtax Reduction Act.impact.

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. We servemaintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. See also “Item 1A. Risk Factors—Industry and Market Risks—Our business is subject to physical, market, economic, and regulatory risks relating to weather conditions and extreme weather events.”

In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. “Energy and other revenues” relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedging activity,hedges, Bitcoin revenue, and Nuclear PTC revenue. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.

In addition, unrealizedUnrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy ExpensesExpenses.” in the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.

CreditUpsizes Facilityand Transactions.Extensions. In AprilJune 2026, TESin also undertook the following financing transactions that are expected to become effective concurrentlyconnection with the closing of the Cornerstone Acquisition:Acquisition, TES (i) received commitments to increaseupsized its existing RCF (including its revolving LC capacity) from $900 million to $1.35 billion; and (ii) received commitments to upsizeupsized its existing $1.1 billion LCF to $1.5 billion and extendextended theits maturity from December 2027 to December 2029. In May 2026, TES extended the maturity of the TLB-1 from May 2030 to November 2032.

See NotesNote 10 and 17 to the Interim Financial Statements for additional information on the financing transactions and the Cornerstone Acquisition.transactions.

During the three months ended MarchJune 31,30, 2026, we repurchased and retired 300,000550,000 shares of TEC’s outstanding common stock under the SRP. The aggregate purchase price, including transaction fees and excise tax,fees, was $101$198 million at a weighted average price of $336.42$359.54 per share. As of MarchJune 31,30, 2026, the remaining capacity under the SRP is $1.9$1.7 billion through 2028. See Note 15 to the Interim Financial Statements for additional information on the SRP.

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,Factors” of our 2025 Annual Report, as updated by our Q1 2026 Quarterly Report, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.

During the firstsecond quarter 2026, PJM experiencedmarket conditions were influenced by weather-related volatilityvolatility, as extremeperiods of above-average temperatures overincreased certainelectricity daysdemand and contributed to increased load demand, resulting in higher settled on-peak power prices. Additionally, TETCO M-3M‑3 natural gas prices settled higher inbelow the periodfive-year dueaverage, toreflecting theample effectsupply of increased electric demand resulting from the extreme temperature days in PJM driving natural gas prices to historic highs on those days.conditions. Natural gas storage levelsinventories duringremained above the quarterfive-year wereaverage nearthroughout the 5-year average.quarter.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the yearsthree months ended MarchJune 31,30, were:

The weighted average forward market prices for the periods from AprilJuly 1 through December 31 as of MarchJune 31,30, were:

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year.

ForThe PJM BRA for the 20272028/20282029 PJM Capacity Year,Year was held in July 2026 and the Company cleared 8,74510,180 MW at a price of $333.44$325.00/MWd.

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We maintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.

The results of operations presented below are prepared in accordance with GAAP and should be reviewed in conjunction with the Interim Financial Statements and the related Notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the three and six months ended MarchJune 31,30, 2026, compared to the three and six months ended MarchJune 31,30, 2025.

Results for the Three Months Ended MarchJune 31,30, 2026 and 2025

Three Months Ended MarchJune 31,30, 2026 compared to Three Months Ended MarchJune 31,30, 2025

Net Income (Loss) increasedAttributable to Stockholders decreased by $198$(164) million, primarily driven by the factors discussed below.

•Operating Revenues, net of Energy Expenses. $345$(9) million favorableunfavorable increase,decrease, primarily due to the following:

◦Energy and Otherother Revenues,revenues, net of Fuel and Energyenergy Purchases.purchases. $157$149 million favorable increase. This is primarily related to thean combinedincrease effectsin ofgeneration volumes: (i) $432as milliona increaseresult of the Freedom and Guernsey acquisitions that were completed in marginNovember associated with electric generation2025; and ancillary revenue, primarily due to higher realized prices received(ii) at Susquehanna and our PJMother dispatchable fossil fleet; and (ii) higher generation volumes at Freedom and Guernsey. Such amounts are partially offset by $(271) million decrease in realized hedge results.facilities.

◦Capacity Revenues.revenues. $158$149 million favorable increase. This is primarily driven by higher cleared capacity prices,prices partially offset by lower volumes clearedreceived through the 2025/2026 PJM BRA compared to the 2024/2025 PJM BRA.BRA, and higher capacity results due to the Freedom and Guernsey acquisitions that were completed in November 2025.

•IncomeDepreciation, Taxamortization Benefitand (Expense).accretion. $(7033) million unfavorable increase. This is primarily relateddue to an increase in pre-taxdepreciation incomeassociated forwith the threeFreedom monthsand endedGuernsey Marchacquisitions 31,that 2026.were completed in November 2025.