Talen Energy (TLN) 424B3Prospectus supplement

TALEN ENERGY CORPORATION

36,825,683 Shares of Common Stock

This prospectus relates to the registration of up to 36,825,683 shares of our common stock, par value $0.001 per share (our “common stock”), which may be offered for resale from time to time by the stockholders named under the heading “Principal and Selling Stockholders” (the “Selling Stockholders”). The shares of our common stock offered under this prospectus may be resold by the Selling Stockholders at fixed prices, prevailing market prices at the times of sale, prices related to such prevailing market prices, varying prices determined at the times of sale or negotiated prices, and, accordingly, we cannot determine the price or prices at which shares of our common stock may be resold. The shares of our common stock offered by this prospectus and any prospectus supplement may be resold by the Selling Stockholders directly to investors or to or through underwriters, dealers or other agents, as described in more detail in this prospectus. We do not know if, when or in what amounts a Selling Stockholder may offer shares of our common stock for resale. The Selling Stockholders may resell all, some or none of the shares of our common stock covered by this prospectus in one or multiple transactions. For more information, see the section titled “Plan of Distribution.”

We will not receive any proceeds from the resale of shares of common stock by the Selling Stockholders, but we have agreed to pay certain registration expenses.

Our common stock is quoted on the OTCQX U.S. Market under the symbol “TLNE.” On July 8, 2024, the closing price of our common stock as reported on the OTCQX U.S. Market was $118.99 per share. We have been approved to list our common stock on the Nasdaq Global Select Market (“Nasdaq”) under the symbol “TLN.” Our common stock will begin trading on Nasdaq on or about July 10, 2024.

This prospectus is a part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission (the “SEC”), using a “shelf” registration or continuous offering process. Under this shelf process, the Selling Stockholders may, from time to time, sell the common stock covered by this prospectus in the manner described in the section titled “Plan of Distribution.” Additionally, we may provide a prospectus supplement to add information to, or update or change information contained in, this prospectus (except that any such additions, updates, or other changes to the section titled “Plan of Distribution” shall only be made pursuant to a post-effective amendment to the extent they are material). You may obtain this information without charge by following the instructions under the section titled “Where You Can Find Additional Information” appearing elsewhere in this prospectus. You should read carefully this prospectus and any prospectus supplement before deciding to invest in our common stock.

The Selling Stockholders may only offer to resell, and seek offers to buy, shares of our common stock in jurisdictions where offers and sales are permitted. You should rely only on the information contained in this prospectus and any accompanying prospectus supplement. Neither we, nor the Selling Stockholders, have authorized anyone to provide you with information other than that contained in this prospectus or any accompanying prospectus supplement, and if other information is provided to you, then you should not rely on it. Neither we, nor the Selling Stockholders, take any responsibility for, and can provide no assurance as to the accuracy or completeness of, any information that others may give you. Neither we, nor the Selling Stockholders, have authorized any other person to provide you with different or additional information. The information contained in this prospectus speaks only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our common stock hereunder. Our business, financial condition, cash flows, results of operations and prospects may have changed since the date on the front cover of this prospectus.

Neither we nor the Selling Stockholders are making an offer to sell the shares in any jurisdiction where the offer or sale is not permitted.

Talen Energy Corporation (“TEC” or “Successor”) is a holding company whose only material businesses and properties are held through its direct and wholly owned subsidiary, Talen Energy Supply, LLC, (“TES” or the “Predecessor”). As used in this prospectus, and as further described below, for periods after May 17, 2023, the terms “Talen,” “Successor,” the “Company,” “we,” “us” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. For periods on or before May 17, 2023, the terms “Talen,” “Predecessor,” the “Company,” “we,” “us” and “our” refer TES and its consolidated subsidiaries (which does not include TEC), unless the context clearly indicates otherwise.

On May 9, 2022, TES and 71 of its subsidiaries each filed a voluntary petition for relief (the “Restructuring”) under Chapter 11 of the Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (Houston Division) (the “Bankruptcy Court”). While TEC’s management continued to operate TES and the other initial Debtors as debtors-in-possession during the pendency of the Restructuring, the activities that most significantly impacted TES’s and the other initial Debtors’ economic performance during this time required approval of the Bankruptcy Court. Accordingly, TEC deconsolidated TES for financial reporting purposes because TEC no longer controlled the activities of TES.

On December 12, 2022, TEC filed a petition to become a debtor in the Restructuring in order to facilitate the implementation of certain restructuring transactions contemplated under the Plan of Reorganization in the Restructuring (the “Plan of Reorganization”) and the Bankruptcy Court approved the joint administration of TEC’s voluntary petition for relief under Chapter 11 of the Bankruptcy Code with TES and the other initial Debtors. On December 20, 2022, the Bankruptcy Court confirmed the Plan of Reorganization.

On May 17, 2023, the Plan of Reorganization became effective and we emerged from the Restructuring (“Emergence”). Upon Emergence, TEC regained control of TES through a business combination that resulted in TEC again consolidating TES. The business combination was accounted for as a reverse acquisition based on the

Accordingly, the financial statements included elsewhere in this prospectus are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer. As a result, the consolidated financial statements of TEC after Emergence are not comparable to its consolidated financial statements prior to that date and have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.

We completed the sale of our ERCOT fleet to CPS Energy in May 2024 (the “ERCOT Sale”). As a result, we have updated certain operational data presented in this prospectus to give effect to the ERCOT Sale. Our financial statements, segment information and related financial data as of and for the periods ending on or prior to March 31, 2024 include the results of operations from the ERCOT fleet. We intend to reevaluate our segment information for the first financial period after the ERCOT Sale, which is the quarter ending June 30, 2024.

All capitalized terms not defined herein have the meaning provided in the Glossary, unless otherwise expressly set forth herein.

This prospectus includes estimates regarding market and industry data. Unless otherwise indicated, information concerning our industry and the markets in which we operate, including our general expectations, market position, market opportunity and market size, are based on our management’s knowledge and experience in the markets in which we operate, together with currently available information obtained from various sources, including publicly available information, industry reports and publications, surveys, our customers, trade and business organizations and other contacts in the markets in which we operate. Certain information is based on management estimates, which have been derived from third-party sources, as well as data from our internal research.

In presenting this information, we have made certain assumptions that we believe to be reasonable based on such data and other similar sources and on our knowledge of, and our experience to date in, the markets in which we operate. While we believe the estimated market and industry data included in this prospectus is generally reliable, such information is inherently uncertain and imprecise. Market and industry data is subject to change and may be limited by the availability of raw data, the voluntary nature of the data gathering process and other limitations inherent in any statistical survey of such data. In addition, projections, assumptions and estimates of the future performance of the markets in which we operate are necessarily subject to uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” These and other factors could cause results to differ materially from those expressed in the estimates made by third parties and by us. Accordingly, you are cautioned not to place undue reliance on such market and industry data or any other such estimates.

Market prices for electricity, capacity, ancillary services, natural gas, uranium, coal and oil are unpredictable and fluctuate substantially over relatively short periods. Market prices for electricity are particularly volatile due to electricity’s inability to be stored in large quantities, so it must be used as it is produced. This results in electricity prices being subject to significant fluctuations based on supply and demand imbalances in the day-ahead and real-time markets. As a result of the use of natural gas in facilities that often serve as the marginal, price-setting generating units, there is also a strong positive correlation between the price of natural gas and the wholesale market price of electricity, in each case in the competitive electric markets in which we operate. In recent years, the market price of natural gas has experienced significant volatility, while prices for other fuels have also varied. Our energy margins are significantly influenced by the relationship between the price of electricity, the price of natural gas and, to a lesser extent, the price of other fuels like coal and uranium. A decline in the price of natural gas, including any negative impact on energy prices resulting therefrom, could materially adversely impact our energy margins, liquidity and results of operations.

Our operations are significantly impacted by weather conditions, which directly influence the demand for electricity and affect the price of energy. As of March 31, 2024 after giving effect to the ERCOT Sale, approximately 97% of our capacity was located in PJM. A warmer winter in the Mid-Atlantic may suppress regional natural gas prices and reduce our energy margins, particularly in PJM. Alternatively, warmer summer temperatures tend to increase cooling electricity demand, energy prices and margins, and cooler winter temperatures tend to increase winter heating electricity demand, energy prices and margins. Furthermore, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation expenses during the winter in the Mid-Atlantic and, prior to the ERCOT Sale, during the summer in Texas. Moderate temperatures reduce the usage of electricity and adversely affect resulting energy margins to the extent that weather is cooler in the summer or warmer in the winter than forecasted. Moreover, extreme weather events, such as Winter Storm Uri and Winter Storm Elliot, can also materially impact power prices or otherwise exacerbate conditions or circumstances that result in volatility of power prices. Weather conditions, which cannot be accurately predicted, may have an adverse effect on our business, results of operations and financial condition, including by requiring us to sell excess electricity on the spot market at a time when market prices are weak.

In addition, the potential physical effects of climate change, such as increased frequency and severity 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. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of our generation facilities.

Adverse economic conditions may reduce the demand for electricity in the key wholesale power markets we serve. In addition, improvements in energy efficiency, conservation efforts and other shifts in energy consumption have slowed, and may continue to slow, electricity consumption growth, particularly in PJM, and may eventually reduce consumption of electricity, which would likely affect our business over the long term. The combination of lower demand for electric power, an increasing supply of natural gas and penetration of renewables in the markets in which we operate has, and may continue to, put downward price pressure on wholesale power market prices in general, further impacting our results of operations. Economic and commodity market conditions will continue to impact our margins on unhedged future energy production, liquidity, earnings growth and overall financial condition.

Our industry is subject to significant advances in technology, including the introduction of new products, technologies and methods of electric power generation. Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us. Technological advances have improved, and are likely to continue to improve, existing and alternative methods to produce, dispatch and store power, which could have the further effect of increasing the overall electricity supply. In addition, technological advances in demand-side management and increased conservation efforts have decreased, and are expected to continue decreasing, electricity demand. As a result of these technological advances and changes in consumption patterns, the dispatch, Capacity Factors and value of our generation facilities could decline, which could have a material adverse effect on our financial condition, operating cash flows and results of operations.

We sell our available electricity and ancillary services and products into competitive wholesale markets through the day-ahead and real-time spot market, and under contracts of varying duration. Our competitors include regulated utilities, industrial companies, other non-utility generators, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. Additionally, we may face competitors that have access to greater resources, newer generation facilities, lower costs or more experience, which could adversely affect our ability to compete in our markets.

Competition in the wholesale power markets occurs principally on the basis of the price of products and, to a lesser extent, reliability and availability. Competition is affected by electricity and fuel prices, relative cost of production of electricity products, new market entrants and barriers thereto, construction by others of generation or storage assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities, establishment of legislation which favors one form of generation over another, such as investment tax credits or production tax credits and other factors. For example, substantial quantities of new generation capacity, including new combined cycle gas and renewable power generation, have been proposed and are under construction in PJM. Commencement of commercial operation of such facilities will increase the supply of electricity, and thus competition, in the wholesale power markets in these regions.

Our wholesale business is also dependent on our ability to operate successfully 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. These competitive factors may negatively affect our ability to sell electricity and related products and services, as well as the prices that we receive for these products and services.

Furthermore, federal and certain state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempting to incentivize, including through certain tax benefits, the construction and development of additional renewable or carbon-free resources, as well as increases in energy efficiency investments. For example, the Inflation Reduction Act contains a number of tax credits and incentives relating to new renewable projects and clean energy technologies. These

We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from governmental agencies. Obtaining and renewing permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Moreover, renewal of existing permits could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure, local community, political or other opposition or executive, legislative or regulatory action. The cost of, or the inability to obtain or comply with the conditions of permits or approvals, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions.

Our generation subsidiaries sell electricity into the wholesale markets. Our generation subsidiaries and our marketing subsidiary are subject to rate, financial and organizational regulation by FERC. FERC has authorized us to sell energy, capacity and ancillary services at market-based prices and has granted us various waivers and blanket approvals customarily granted to market-based rate sellers, including a blanket authorization to issue securities and to assume liabilities. FERC retains the authority to modify or withdraw our market-based rate authority and to impose cost-based rates if it determines that the market is not competitive, that we possess market power in one or more markets, that we are not charging just and reasonable rates or that we have violated FERC’s market behavior rules or engaged in market manipulation. Any reduction by FERC in the rates that we may receive, any revocation of the waivers and blanket authorizations we have received from FERC, or any new or unfavorable changes to the regulation of our business by federal or state regulators could materially adversely affect our results of operations. In addition, if we were found to have violated FERC’s market behavior rules or other FERC requirements, FERC could impose civil penalties or order us to disgorge profits associated with the violation. Pursuant to the Capacity Performance construct, we are subject to economic penalties for generation non-performance up to our capacity commitments during certain PJM emergency events, which penalties could be material. See “—Regulatory, Legislative and Legal Risks—Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and regulatory entities to investigate and determine the causes of such events and may result in changes in applicable laws and regulations, mandatory reliability requirements and market rules, including to reform PJM.”

Our generation assets are also subject to the reliability standards promulgated by the FERC-designated Electric Reliability Organization (currently NERC) and approved by 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.

Instability and unrest, as well as threats of war, other armed conflict and economic sanctions may lead to acts of war or terrorism or other economic disruption and high levels volatility in prices for oil and natural gas and the supply of nuclear fuel, which may significantly affect our business and results of operations.

In addition, we could be significantly affected by an epidemic, outbreak of an infectious disease or other public health events that are outside of our control. Depending on the severity of such an event and the resulting impacts to workforce and other resource availability, the ability to operate our generation facilities could be affected, resulting in decreased service levels and increased costs. Additionally, as our power generation facilities are geographically concentrated in certain areas of the United States, we face increased risk that a natural or man-made disaster in one of our geographical areas could adversely affect a significant percentage of our operations.

The operation of our business is also subject to cyber-based security and integrity risk, which could result in an adverse impact to our reputation or our results of operations. The operation of our generation facilities and of our

Power generation involves hazardous activities, including transporting, storing and handling fuel, operating large pieces of electrical and other equipment and connecting to high voltage transmission and distribution systems. As a result, our employees, contractors, customers and the general public may be exposed to risks inherent in the nature of our operations, including hazards such as nuclear accidents, accidents involving high voltage electrical equipment, environmental hazards, fires or explosions, structural failures, machinery failures and other dangerous incidents. These and other hazards can cause significant personal injury or loss of life, severe property damage or destruction and any such event may expose us to liability for substantial damages, fine or penalties. Although we currently maintain customary insurance coverage for certain of these risks, we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject, or that insurance coverage will continue to be available at economic rates. See “Business—Insurance.” Any losses not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Operation of our generation facilities and other assets subjects us to a variety of risks, including from accidents, equipment failures, electrical delivery or transportation problems, fuel supply disruptions, environmental incidents, security and information technology breaches, labor disputes, obsolescence and below-expected performance. Any unexpected failure, including failure associated with breakdowns or forced outages, as well as any unanticipated capital expenditures, could result in reduced profitability. Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fully in the event losses occur. Our facilities require periodic maintenance and repair, and frequent or prolonged planned or unplanned outages could further affect our results of operations, including by requiring us to purchase power at then-current market prices to satisfy our commitments. Furthermore, we cannot be certain of the level of capital expenditures that will be required due to needed facility maintenance and repairs, competitive developments, changing environmental and safety laws and unexpected events, and any such expenditures could be significant.

Our operations depend on transmission and distribution facilities owned and operated by RTOs, ISOs and other unaffiliated parties to deliver the electricity that we produce to our counterparties. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Electric power blackouts are possible and have occurred, which could disrupt electrical service for extended periods of time. If a blackout were to occur, the impact could result in interruptions to our operations, increased costs to replace existing contractual obligations, the possibility of regulatory investigations and potential operational risks to our facilities. Transmission constraints and outages, including line maintenance outages, can cause transmission congestion that negatively impacts energy

Susquehanna accounted for a majority of our generation and associated earnings in 2023, and we expect that it will continue to contribute a majority of our generation and associated earnings in the future. Accordingly, an adverse development in Susquehanna’s operations, such as an unplanned outage or catastrophic event, could have a significant impact on our results of operations and liquidity. The risks and uncertainties of our nuclear generation include, among other things:

The frequency and duration of outages affect Susquehanna’s availability. Although we have met or exceeded our availability targets and have timely completed our planned refueling outages for several years, if future refueling outages last longer than anticipated or Susquehanna experiences unplanned outages for any reason, our results of operations and liquidity could be adversely affected. In addition, if Susquehanna were to experience a significant disruption to its operations, it is possible that our ability to meet our capacity commitments and obligations under long-term power supply contracts, including under the Cumulus Data Campus PPA, could be negatively impacted.

In addition, the costs associated with the nuclear fuel cycle are substantial and the suppliers for certain components and other materials required to produce nuclear fuel are limited. Any disruption to the availability of these components and other materials, whether temporary or long-term, could cause unplanned outages and have a significant impact on the cost of nuclear fuel or otherwise impact our ability to profitably operate Susquehanna.

There remains substantial uncertainty regarding the nuclear industry’s permanent disposal of SNF, which could result in substantial additional costs to us that cannot be predicted. Federal law requires the U.S. Government to provide for the permanent disposal of commercial SNF. Prior to May 2014, nuclear operators were required to contribute to a fund to pay for the transportation and disposal of SNF. In May 2014, this fee was reduced to zero. We cannot predict if or when the U.S. Government will increase this fee in the future, which could result in significant additional costs to us. Susquehanna is currently party to an agreement with the U.S. Government that requires the U.S. Government to reimburse certain costs to temporarily store SNF at the Susquehanna facility through the end of 2025. However, we cannot be certain that this arrangement will be extended beyond 2025.

Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe,

Certain of our operations pose risks of environmental liability due to leakage, migration, emission, releases or spills of hazardous substances to the air, surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. We could be held responsible for all liabilities associated with the environmental condition of our generation facilities, including remediation or removal of any soil or groundwater contamination that may be present, regardless of whether we were responsible for the creation of the environmental condition or it arose from the activities of predecessors or third parties and even if our operations met previous standards in the industry at the time they were conducted.

We actively manage the market risk inherent in our generation and energy marketing activities, as well as monitor compliance with our risk management processes. Nonetheless, such programs may not manage or eliminate all risks or work as expected in all potential market outcomes. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management calculations. Unforeseen market disruptions could decrease market depth and liquidity, negatively impacting our ability to enter into new transactions. We enter into financial contracts to hedge commodity “basis risk” and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position. Any failure of our risk management activities to adequately manage the market risk inherent in our operations could adversely affect our business, financial condition and results of operations.

In addition, we are also exposed to market risks associated with selling and marketing products in the wholesale power markets, including, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel and other electricity-related commodities, converting fuel into power and satisfying our contractual electricity sales obligations. We may from time to time undertake these activities to hedge those risks through hedging agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, LCs, a first lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency.

Significant movements in market prices can cause us to be required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral, we may not be able to manage price volatility effectively or to implement our hedging strategy. An increase in the amount of LCs or cash collateral required to be provided to our counterparties may have a material adverse effect on us. As we are required to collateralize hedges that settle in future delivery periods, but do not receive settlements for electric generation until delivery, such collateral requirements could result in lower available cash and liquidity, which could adversely affect our business, financial condition and results of operations.

We believe that we will have sufficient liquidity to fulfill our collateral obligations under these agreements. However, our obligation to post collateral could exceed the amount of our available liquidity, particularly if power prices increase significantly, and our ability to obtain additional liquidity could be limited by our debt or other agreements, willingness of lenders to lend us additional capital, financial markets or other factors.

Despite reduced exchange trading, we may still have significant obligations that require cash collateral or the posting of LCs, which are at risk of being drawn down in the event we default on our obligations. In the normal course of business, we enter into agreements that provide financial performance assurance to third parties on behalf

We employ a variety of commercial, physical and financial instruments to hedge commodity price volatility, provide stable cash flow generation and preserve forward margin. Certain of these transactions are recognized on the balance sheet at fair value with changes in their fair values resulting from fluctuations in the underlying commodity prices recognized in earnings. However, not all commercial risk management transactions meet the accounting standard for such accounting treatment and, accordingly, there may be timing differences between when these instruments are recognized in earnings. Additionally, even where the changes in fair values of these instruments are immediately recognized in earnings, those changes may not entirely offset the changes in fair values of the instruments that are subject to the hedges. Further, when commercial contract expires or is terminated, we may not secure replacement on acceptable terms or timing, if at all. 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. As a result, during periods of extreme price volatility or significant changes in market prices, our quarterly and annual results are subject to significant fluctuations due to changes in fair values of commodity derivative instruments caused by changes in market prices.

We are subject to the risk of loss resulting from nonpayment by our contractual counterparties in the ordinary course of our business, including ISOs, other customers and other market counterparties and other parties to whom we supply certain products or services. As part of our risk management procedures, we have established credit procedures to evaluate counterparty credit risk, but these procedures and policies may not be adequate to fully identify or effectively manage customer and counterparty credit risk. Further, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our purchasers’ and hedging counterparties’ creditworthiness. Unanticipated deterioration in the creditworthiness of existing or future customers and hedging counterparties, and any resulting increase in nonpayment or nonperformance by them could cause us to reserve for or write-off uncollectible accounts.

Additionally, we are exposed to concentrations of credit risk from suppliers and customers among electric utilities, financial institutions, marketing and trading companies and the U.S. Government. These concentrations may impact our overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. See Note 3 in Notes to the Interim Financial Statements and Note 5 in Notes to the Annual Financial Statements for more information.

We purchase fuel and other consumables during the production of electricity (such as coal, natural gas, uranium, oil, water, lime, limestone and other chemicals and sorbents) from a number of suppliers. Delivery of these fuels and other consumables to our facilities is dependent upon the continuing financial viability of our contractual counterparties, as well as the transportation infrastructure available to serve each generation facility. If our suppliers or other contractual counterparties fail to perform, we may be forced to not operate, curtail the production of electricity or enter into alternative arrangements. If we have agreements in place to deliver firm electricity and capacity and fail to do so, we could be required to procure electricity from third parties to meet our contractual or capacity obligations or to otherwise pay market-based damages. Depending on price volatility in the wholesale power markets, such damages could be significant.

We sell forward a portion of our forecasted power generation in order to lock in future power prices that we deem to be favorable at the time we enter into the forward power sales contracts. In order to hedge our cost of production relating to those obligations, we may enter into forward contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in our fuel supplies may require us to find alternative fuel sources at higher costs, find other sources of power to deliver to counterparties at a higher cost or pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on our results of operations, liquidity or financial condition. Where we have assumed a forward capacity obligation in the PJM capacity market, we may also be exposed to substantial penalties if we fail to generate electricity as ordered during certain emergency periods. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions and other factors could affect our ability to meet our obligations or cause significant increases in the market price of replacement capacity and electricity.

We also buy some of our fuel and other consumables on a short-term or spot market basis. Prices for all of our fuels and other products fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of electricity may not rise at the same rate, or may not rise at all, to match a rise in fuel and other products or their delivery costs. This may have a material adverse effect on our financial performance.

Since 2016, we have retired three economically nonviable coal-fired units, and we have committed to cease burning coal at Montour, Brandon Shores and Wagner by the end of 2025 and Brunner Island by the end of 2028. (However, for additional information on potential Reliability-Must-Run arrangements affecting Brandon Shores and Wagner, see Note 8 in Notes to the Interim Financial Statements.) In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required closure and reclamation, which could result in significant costs and have a material adverse effect on our financial and operating performance.

Property, plant and equipment used in operations is assessed for impairment whenever changes in facts and circumstances indicate the carrying amount of the asset group may not be recoverable. If we were to experience events, among others, such as a prolonged economic downturn, significant changes to generation facility useful lives, a decrease in the market price of an asset, increased costs, certain negative financial trends or significant changes to the market conditions or the regulatory environment, we could experience future generation facility impairments, which may result in a material adverse effect on our financial conditions, results of operations and cash flows.

We have limited control over the ownership, and in some cases, the operation of our joint-owned facilities, including the Conemaugh and Keystone generation facilities. We also own 30% of Colstrip Unit 3. We are subject to costs and output-sharing arrangements in respect of Colstrip Units 3 and 4 which are operated by Talen Montana. We seek to exert a degree of influence with respect to the management and operation of these generation facilities by either operating these facilities (i.e., Colstrip) or negotiating to obtain positions on management committees or to receive certain limited governance rights, but we may not always succeed in such negotiations.

In many instances we depend on these co-owners for elements of these arrangements that are important to the success of the joint operation, such as funding their proportional share of capital and operating costs. These co-owners may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. Moreover, some of these co-owners are rate regulated utilities that

Retaining key employees and attracting new employees are important to both our operational and financial performance. We cannot guarantee that any member of our leadership team or our key employees will continue to serve in any capacity for any particular period of time. An aging workforce, 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 operating challenges and increased costs. The challenges that we might face as a result of such risks include a lack of human resources, losses to our operational knowledge base and the time and other resources required to develop new workers’ skills. In particular, our operations at Susquehanna are dependent on highly specialized personnel, and any prolonged absence by these persons may adversely impact our ability to operate. If we are unable to successfully retain and attract an appropriately qualified workforce, our financial position or results of operations could be negatively affected.

Further, we are also subject to the risk of strikes or work stoppages by unionized employees. As of March 31, 2024 after giving effect to the ERCOT Sale, we had 1,892 full-time employees, approximately 44% of which were represented by labor unions. In the event that our union employees participate in a strike, work stoppage or slowdown or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our business, financial condition and results of operations.

We expect to continue to face increased cost pressures in our operations because of increased costs of labor from heightened inflation, the need for higher-cost expertise in the workforce and other factors. Rising or persistently high inflation rates could have a material adverse effect on our business, financial condition, results of operations and liquidity. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. We provide similar benefits to our non-union employees. Due to general inflation with respect to such costs, the aging demographics of our workforce, health care cost trends and other factors, we expect our health care costs, including prescription drug coverage, to continue to increase, despite measures that we have taken to reduce such costs.

As of December 31, 2023, our qualified defined benefit pension plans for our retirees and certain employees were underfunded by an estimated $333 million with a total benefit liability of an estimated $1.31 billion. We expect to continue to incur significant costs with respect to the defined benefit pension plans for our retirees and certain of our employees. The measurement of our expected future pension obligations and costs is highly dependent on a variety of assumptions, most of which relate to factors beyond our control, including investment returns, interest rates, inflation rates, salary increases, future government regulation, required or voluntary contributions made to the plans and the demographics of plan participants. If our assumptions prove to be inaccurate, our costs and cash contribution requirements to fund these benefits could increase significantly. Further, without sustained growth in the pension investments over time, and depending upon the assumptions impacting costs listed above, we could be required to fund our plans with significant amounts of cash in advance of the time we would otherwise fund such payments. Future changes in funding requirements associated with our pension plans, including as a result of poor performance or inaccurate assumptions, or an adverse decision in the litigation related to the TERP (see “Business—

We do not own or control the transmission facilities required to deliver the wholesale power from our generation facilities to load. In most cases, RTOs and ISOs operate transmission facilities and provide related services, administer organized power markets and maintain system reliability. Many of these RTOs and ISOs operate the real-time and day-ahead markets in which we sell electricity. The RTOs and ISOs that oversee most of the wholesale power markets impose, and may continue to impose, offer caps, price limitations and other mechanisms to guard against the potential exercise of market power in these markets. These and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell electricity and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generation facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. As a result, our financial condition, results of operations, liquidity and cash flows may be materially adversely affected.

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 market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs, RTOs or other transmission providers in applicable markets 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. See “Business—Regulatory Matters” for additional information about ongoing regulatory matters.

There is also unpredictability around capacity revenues due to lack of reliable pricing and PJM Base Residual Auctions. The PJM market is undergoing significant restructuring due to recent weather events that have exposed systemic flaws, resulting in decline or delay in a substantial portion of capacity revenues. We cannot predict what these market reforms will look like or their impact on capacity revenues in the future. Please see Note 10 in Notes to the Interim Financial Statements and Note 12 in Notes to the Annual Financial Statements for more information on the capacity market and systemic risks in PJM.

Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions. The competitive wholesale marketplace may be undermined by changes in market structure and the actions of federal or state entities, including out-of-market payments to nuclear facilities, renewable mandates or subsidies and out-of-market payments to new generators.

In July 2021, PJM filed proposed tariff language to significantly reduce the application of the existing PJM MOPR by applying it only when the state requires an entity to act in a certain manner in the capacity market in exchange for receiving a subsidy. FERC did not act on PJM’s July 2021 filing, and the PJM MOPR tariff language

In June 2023 and February 2024, FERC accepted requests by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delays currently schedule the PJM Base Residual Auctions for 2025/2026 in July 2024, 2026/2027 in December 2024, 2027/2028 in June 2025 and 2028/2029 in December 2025. Although PJM has established dates for the next four auctions, there is no guarantee that the auctions will take place on those dates or at all. Depending on the ultimate outcome of matters related to PJM’s capacity auctions, capacity revenues in PJM could be affected, which could have a material adverse effect on our business, financial condition and results of operations.

Many political and regulatory authorities, along with certain financing sources and environmental groups, are devoting substantial resources and efforts to minimize or eliminate the use of fossil fuels as a source of electricity generation, domestically and internationally, thereby reducing the demand and pricing for electricity generated at fossil fuel-fired generation facilities and potentially materially and adversely impacting our future financial results, liquidity, ability to raise capital and growth prospects.

Concerns about the environmental impacts of fossil fuel combustion, including impacts on global climate issues, are resulting in increased regulation of coal combustion and greenhouse gas (“GHG”) emissions, unfavorable lending policies toward the financing of fossil fuel-fired power generation facilities and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Climate issues continue to attract public, scientific and governmental attention to global climate issues and to emissions of GHGs. Changes to the legal and regulatory framework governing electricity generation resulting from such concerns could have a material adverse effect on our operations, cash flow and financial condition. For example, the new water, waste, air and climate rules recently finalized by the EPA could require us to incur costs to comply if they withstand legal challenges. These costs include asset modifications and potential emission control equipment investments, as well as reporting requirements. See “Business—Environmental Matters” for additional information on these new rules. Furthermore, any new legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the power we produce.

Enactment of laws or passage of regulations regarding emissions from the combustion of coal, natural gas or oil by the United States, some of its states or other countries, or other actions to limit such emissions, could also result in electricity generators further switching from coal or natural gas to other fuel sources or additional fossil fuel-fired power generation facility closures. We operate an aging fossil fleet and many of our facilities require periodic maintenance and repair. If we significantly modify a unit such that regulated pollutants are increased beyond thresholds set by the EPA pursuant to New Source Review guidelines promulgated under the Clean Air Act, we may be required to install the best available control technology or to achieve the lowest achievable emission rates, which would likely result in substantial additional capital expenditures.

In accordance with the relevant legal and regulatory requirements, we perform certain activities to manage large quantities of CCR material resulting from decades of coal-fired electric generation. In particular, Talen Montana has significant decommissioning and environmental remediation liabilities primarily consisting of its proportionate share of remediation, closure and decommissioning costs for coal ash impoundments at the Colstrip Units. Where applicable, we carry the expected cost of these obligations within our ARO liabilities. Actual cash expenditures associated with these AROs are expected to materially increase over the next five years due to the expected timing and scope of anticipated remediation activities and will continue at a reduced spending level for several decades.

Under the Atomic Energy Act of 1954, as amended, our operation and 90% ownership of Susquehanna are subject to regulation by the NRC, including requirements pertaining to: licensing, inspection and enforcement; testing, evaluation and modification of all aspects of nuclear reactor power generation facility design and operation; environmental and safety performance; technical and financial qualifications; decommissioning funding assurance; and transfer and foreign ownership restrictions. The current facility operating licenses for our two units at Susquehanna expire in 2042 and 2044.

The NRC could permanently or temporarily shut down Susquehanna, require it to modify its operations or refuse to permit restart of the unit after unplanned or planned outages. As a result of any shutdown or forced outage, we may face additional costs to the extent we are obligated to provide power from more expensive alternative sources to cover our then-existing forward sale obligations, as well as substantial costs related to the storage and disposal of radioactive materials and SNF. In addition, Susquehanna will be obligated to continue storing SNF if the U.S. DOE continues to fail to meet its contractual obligations under the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of Susquehanna’s SNF. NRC regulations also require us to demonstrate reasonable assurance that certain funds will be available to decommission each nuclear generation facility at the end of its life. There are uncertainties with respect to certain technological and financial aspects of decommissioning these facilities, and related costs may exceed the amounts available from the Susquehanna NDT funds.

New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep Susquehanna operating efficiently. Any unexpected failure, including failure associated with breakdowns or any unanticipated capital expenditures, could result in reduced profitability. Costs associated with these risks could be substantial and could have a material adverse effect on our business, financial condition or results of operations. See “—Commercial and Operational Risks—Our ownership and operation of Susquehanna, which contributes a majority of our earnings associated with electric generation, subjects us to substantial risks associated with nuclear generation.”

While Susquehanna maintains property and liability insurance for losses related to nuclear operations at Susquehanna 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, or we may have insufficient coverage with respect to any such losses. 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. 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 results of operations, cash flows, financial condition and liquidity.

Our business and facilities are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection and human health and safety, which have become more stringent over time. These laws and regulations impose numerous requirements, including requiring permits to conduct regulated activities, incurring costs to limit or prevent pollution or releases of regulated materials to the environment, imposing specific standards addressing worker protection and process safety, and imposing substantial liabilities and remedial obligations for pollution or contamination. If there is any delay in obtaining any environmental regulatory approvals necessary for our operations or capital projects, or failure to obtain, maintain or comply with any such approvals, operations at our affected facilities could be halted, reduced or subjected to additional costs. New or more stringent enforcement of existing laws or regulations could adversely affect our business, financial condition and results of operations.

As a result of various factors, including existing and recently revised rules and regulations, such as those pertaining to water, waste, air (including GHG regulations) and climate, we have spent, and expect to continue to spend, substantial amounts on measures regarding environmental control, compliance and remediation. See “Business—Environmental Matters” for additional information on new water, waste, air and climate rules recently finalized by the EPA. We anticipate that certain of these new EPA rules will be legally challenged; the outcome of our spend will depend on the success and timing of such challenges, which we cannot currently predict.

The EPA regulates GHG emissions from the power sector and certain states regulate carbon dioxide emissions from power generation facilities. The EPA recently finalized GHG standards for new and certain existing power plants. These regulations primarily affect higher-emitting 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. Failure to comply with applicable laws, regulations and permits may result in liability for administrative, civil or criminal fines or penalties or in unforeseen costs or obligations, including requirements to install additional equipment or make substantial changes to our operations. In addition, private parties may also have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance, with environmental laws, regulations and permits.

The conduct of our business is subject to various laws and regulations administered by federal, state and local governmental agencies. In addition, changes in state laws and regulations may be less predictable or could occur more rapidly, or have a more drastic effect, than changes at the federal level. Changes in laws and regulations occur frequently and sometimes dramatically, as a result of political, economic or social events or in response to significant events. For example, economic downturns, periods of high energy supply costs and other factors can lead to changes in, or the development of, legislative and regulatory policy designed to promote reductions in energy consumption, increased energy efficiency, renewable energy and self-generation by customers. Such a focus may result in a decline in electricity demand, which could in turn adversely affect our business. Any change in the legal and regulatory landscape (including the processes for obtaining or renewing permits, costs associated with providing healthcare benefits to employees, health and safety standards, accounting standards, taxation regulations and requirements and competition laws) may have a material adverse effect on our results of operations, competitive position or financial condition. See “Business—Environmental Matters” for additional information on new water, waste, air and climate rules recently finalized by the EPA.

Separately, 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 have a material adverse effect on our business, results of operations, cash flows and financial condition. See “Business—Regulatory Matters” for additional information about ongoing market reforms.

During Winter Storm Elliott, certain of our generation facilities failed to meet the Capacity Performance requirements set forth by PJM, while our remaining generation facilities met or exceeded their capacity obligations. As a result, we incurred certain Capacity Performance penalties charged by PJM for our under-performing facilities and earned bonus revenues from PJM for our over-performing generation facilities. Accordingly, Talen Energy Marketing recognized in 2022 and 2023 a net penalty charge, of approximately $51 million, net of expected bonus revenues. Talen Energy Marketing and its affiliates, along with other suppliers, subsequently filed complaints against PJM at FERC disputing a significant portion of the penalties assessed by PJM. In December 2023, FERC approved a market-wide settlement that resolved the disputes. As a result, Talen’s estimated aggregate penalties, net of expected bonus revenues, were reduced from $51 million to $28 million, but no assurance can be provided that these amounts will not vary based on the final market settlements or any other legal and (or) regulatory actions.

In the future, we are highly likely to face additional severe weather events, which are inherently unpredictable in nature, location, scope and timing, and which may give rise to investigations or other efforts to determine the causes or consequences of such events. Any such efforts may result in further changes to applicable laws and regulations, mandatory reliability requirements and market rules, which could affect our liquidity and results of operations, all of which are unpredictable at this time.

We are required to maintain, through either allocations or purchases, sufficient emission allowances for sulfur dioxide, nitrogen oxide and carbon dioxide to support our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. Given the historical correlation between rising natural gas prices and increasing prices for wholesale electricity, we may idle our units less as natural gas prices increase, resulting in an increase in emissions. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances or install costly new emission controls. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.

The laws and rules dealing with 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”), to 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, whose terms are not yet fully known. As such, we cannot fully predict the impacts that any such tax credits may have on our liquidity or results of operations. We are continuing to evaluate the Inflation Reduction Act and its requirements, as well as its application to us. Any elimination of the Nuclear PTC may adversely affect our business and financial condition.

In addition, our tax reporting is subject to audit by tax authorities. We may enter into transactions and arrangements in the ordinary course of business in which the tax treatment is not entirely certain. We must therefore make estimates and judgments in determining our consolidated tax provisions and accruals. The final outcome of any audits by tax authorities may differ from estimates and assumptions used in determining our consolidated tax provisions and accruals, and the resolution of tax assessments or audits by tax authorities could impact operations. This could result in a material and adverse effect on our consolidated income tax provision, financial position and the net income/loss for the period for which such determinations are made.

As of December 31, 2023, we had approximately $1.3 billion of U.S. federal net operating loss (“NOL”) carryforwards and approximately $1.4 billion of disallowed business interest expense carryforwards under Section 163(j) of the Code and certain other tax attributes (including significant tax basis in assets). However, we expect that, absent an election under Section 108(b)(5), we will be required to substantially reduce or eliminate certain of our tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the Restructuring. We are still considering whether we will make a Section 108(b)(5) election to reduce fixed asset tax basis prior to any reduction in NOL carryforwards.

Because the consummation of the Plan of Reorganization resulted in an ownership change for purposes of Sections 382 and 383 of the Code, our ability to utilize any remaining tax attributes after reduction and disallowed business interest expense carryforwards is subject to limitation under Sections 382 and 383 of the Code. As a result, certain of our tax attributes have been substantially reduced, eliminated or otherwise restricted.

Our generation and wholesale power sales business relies on a competitive marketplace. The competitive marketplace may be impacted by out-of-market subsidies provided by states or state entities, including bailouts of uneconomic nuclear facilities, imports of power from Canada, renewable mandates or subsidies, mandates to sell power below its cost of acquisition and associated costs, as well as out-of-market payments to new or existing generators. These out-of-market subsidies to existing or new generation undermine the competitive marketplace, which can lead to premature retirement of existing facilities, including those owned by us. If these measures continue, capacity and energy prices may be suppressed, and we may not be successful in our efforts to insulate our platform from this interference in the competitive market.

We are, and in the future may be, subject to litigation arising out of our operations. Damages claimed under such litigation may be material, and the outcome of such litigation may materially adversely impact our financial condition, cash flows, results of operations and liquidity. While we will assess the merits of any lawsuits and defend such lawsuits accordingly, we may be required to incur significant expense or devote significant financial resources to such defenses. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our operations. Our insurance may not adequately cover losses for damages claimed against us, and we do not have insurance coverage for all litigation risks. Please see Note 10 in Notes to the Interim Financial Statements, Note 12 in Notes to the Annual Financial Statements, and “Business—Legal Matters” for more information regarding our litigation matters.

In recent years, shifting worldwide social and political views toward the environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and concern about investors’ expectations regarding environmental matters, have necessitated changes in fossil fuel-related industries. Many institutional investors have recently

Our primary liquidity requirements, in addition to our ordinary course operating expenses, are for servicing our debt and capital expenditures and, in certain cases, providing collateral for our hedging program. If our sources of liquidity are not sufficient to fund our current or future liquidity needs, we may be required to take other actions, including refinancing, restructuring or reorganizing all or a portion of our debt or capital structure, reducing or delaying capital investments or obtaining alternative financing. Our ability to obtain financing is subject to numerous factors that we may not be able to control, including conditions in the capital markets, our current operations, credit ratings and other events which we are not able to predict. Furthermore, any financing may be at a higher cost than we expect or have other security, collateral or other conditions or requirements. Additionally, applicable regulations may impose costly additional requirements on our business and the businesses of others with whom we contract or may increase costs to conduct our business or access sources of capital and liquidity. There can be no assurance that we will be able to obtain financing on commercially reasonable terms, or at all, or in a manner that would be permitted under the terms of our debt instruments or in a manner that does not negatively impact our business. Additionally, there can be no assurance that the above actions, if taken, would allow us to meet our debt obligations and operating requirements.

Our capital structure was significantly altered under the Plan of Reorganization. Upon Emergence, we adopted fresh-start accounting, which required us to adjust our assets and liabilities to fair value and restate our accumulated deficit to zero. In addition, we adopted accounting policy changes and such policies could result in material changes to our financial reporting and results. Accordingly, our financial condition and results of operations following the Restructuring are not comparable to the financial condition and results of operations reflected in our Annual Financial Statements.

Our indebtedness, including the Indenture and the Credit Facilities, could have important consequences to our future financial condition, operating results and business, including the following:

Although the Credit Facilities, the Indenture and other existing indebtedness contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and any additional indebtedness incurred in compliance with these restrictions could be substantial. See “—Risks Related to Ownership of Our Common Stock—TEC is a holding company; its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the agreements governing our indebtedness contain certain restrictions on distributions of cash to TEC.” and

Our borrowings under the Credit Facilities are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our ability to make payments of principal and interest on the Secured Notes (as well as on loans with respect to the Credit Facilities) may be adversely impacted.

Our debt agreements, including the Indenture and the agreements governing the Credit Facilities, contain covenants that, among other things, limit the ability of TES and certain of its subsidiaries to, among other things:

These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers, acquisitions and other corporate opportunities. Various risks, uncertainties and events beyond our control could affect our ability to comply with these covenants. Failure to comply with the covenants in our existing or future financing agreements could result in a default under those agreements and other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity for the debt under these agreements and to foreclose upon any collateral securing the debt. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. In addition, the limitations imposed by financing agreements on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing, which could adversely affect our financial condition and results of operations and could cause us to become bankrupt or insolvent.

Our project development activities related to the Cumulus projects may consume a significant portion of our management’s focus, and if not completed or successful, reduce our profitability. TES currently provides corporate, administrative and operational services to the Cumulus Affiliates. As a result, the operations and activities of the Cumulus Affiliates may divert the attention and impact the availability of TES personnel. The Cumulus projects may also require us to spend significant sums for engineering, construction, permitting, legal, financial advisory and other expenses before we determine whether a development project is feasible, economically attractive or capable of being financed. In addition, the economic assumptions underlying one or more of the Cumulus projects may prove to be incorrect or materially different than projected, which may cause us to reevaluate pursuing or further investing in a particular project.

Our Cumulus projects may be complex, which increases the chances that we may not be able to complete them. There can be no assurance that we will be able to negotiate the required agreements, overcome any local opposition or obtain the necessary approvals, licenses, permits and financing. Failure to achieve any of these elements may prevent the development and construction of a project. If that were to occur, we could lose all of our investment in development expenditures and may be required to write-off project development assets. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise.

Through certain Cumulus Affiliates, we are party to joint venture agreements with various third parties, including Pattern Energy and BQ Energy Development, LLC for potential solar and wind projects. Additionally, Cumulus Coin holds a 75% equity interest in Nautilus, with TeraWulf as our joint venture partner. Conflicts may arise with our joint venture or joint owner counterparties due to differing strategic or commercial objectives or disagreement on governance matters or whether a project merits continued investment. A deadlock in management decisions could cause us to sell our interest in the project or buy our joint venture partner’s interest. We may also be subject to the risk that our counterparties do not fund their obligations and to preserve the value of our investment, we may be required to expend additional internal resources that could otherwise be directed to other projects. Conversely, if we no longer desire to invest in a project, our counterparties may determine to cover our investment which may dilute our interests and lead to a loss of voting or other rights in the project. If we are unable to successfully execute and manage our existing and proposed joint venture and jointly owned projects, the anticipated benefits associated with such arrangements may not be achieved or could be delayed, which could adversely impact our financial and operating results. See “Certain Relationship and Related Party Transactions.”

The capital expenditures and time required to develop new renewable and digital infrastructure projects are considerable and can increase due to a wide variety of factors, many of which are beyond our control. These include, but are not limited to, weather conditions, ground conditions, availability of construction material, availability and performance of contractors and suppliers, changes in cost or construction schedules, inflation, delivery and installation of equipment, design changes, accuracy of estimates, availability of accommodations for the workforce, change in laws or regulations and the ability to obtain necessary government approvals. In addition, the Cumulus Data Campus’s and Nautilus’s operations are and will be powered exclusively by electricity generated at Susquehanna. Any disruption or outage at Susquehanna affecting its ability to generate sufficient electricity for Cumulus Data operations (including submetered electricity to Nautilus) could have a material adverse effect on their respective businesses, financial condition and results of operations.

While we expect to maintain our existing Bitcoin operations through our interest in Cumulus Coin, we do not currently plan to expand such operations or expect any material capital expenditures within the next twelve months. Nonetheless, our existing Bitcoin operations do expose us to certain risks. Almost all of Cumulus Coin’s expected revenue is from the sale of Bitcoin mined by Nautilus. Investing in Bitcoin is speculative, as it has historically experienced significant intraday and long-term price volatility. For example, during 2023, the per-coin price of Bitcoin reached a low of approximately $16,500 and a high of approximately $44,700. If the price of Bitcoin declines, Cumulus Coin’s profitability will decline, which would adversely affect the business, prospects, financial condition, and results of operation of Nautilus and Cumulus Coin.

Additionally, digital assets, including Bitcoin, are under increasing regulatory scrutiny, and the extent and content of any forthcoming laws and regulations are uncertain. New laws and increased regulation could result in new compliance-related costs for Cumulus Coin’s operations, result in regulation of Bitcoin under the securities

Furthermore, cryptocurrency assets are generally controllable only by the possessor of the unique private key relating to the digital wallet in which such assets are held. To the extent that any of the private keys relating to wallets containing Bitcoin held by Nautilus are lost, destroyed, stolen or otherwise compromised or unavailable, Nautilus would be unable to access the Bitcoin held in the related wallet.

From time to time, we may seek to acquire additional assets or businesses. The acquisition of new assets or businesses is subject to substantial risks, including delays in completion or an inability to complete them at all, the failure to identify material problems during due diligence, the risk of over-paying, the ability to retain customers or employees of such acquired businesses and the inability to arrange required or desired financing for an acquisition. We may acquire assets or businesses in geographic regions or markets in which we do not currently operate or lines of business outside of our core focus, which may expose us to increased market or regulatory risks. There can be no assurances that any future acquired businesses will perform as expected or that the returns from such acquisitions will support any related financing incurred or the cash flows needed to operate them profitably.

In addition, we may from time to time choose to sell certain assets or businesses. The risks of such dispositions may relate to employment matters, counterparties, regulators and other stakeholders in the disposed business, separating the disposed assets from our other businesses, the management of our ongoing business, as well as risks unknown to us at the time and other financial, legal and operational risks related to such disposition. In connection with such dispositions, we may also indemnify or guarantee counterparties against certain liabilities, which may result in future costs or liabilities payable by us. Any such risk may result in one or more costly disputes or litigation. In addition, any disposition would decrease our Adjusted EBITDA, which could impact our ability to pay dividends or effect share repurchases under our debt agreements. The failure to realize the anticipated returns or benefits from an acquisition or disposition could adversely affect our business, financial condition and results of operations.

There was no public market for our common stock prior to commencing trading on the OTC Pink Market on June 23, 2023 and subsequent commencement of trading on the OTCQX U.S. Market on July 24, 2023. We have been approved to list our common stock for trading on Nasdaq under the symbol “TLN.” However, listing on Nasdaq does not ensure that an active trading market for our common stock will develop or be sustained. Accordingly, no assurance can be given as to the likelihood that an active trading market for our common stock will develop or be sustained, the liquidity of any such market or the ability of our stockholders to sell their common stock at the price desired.

The stock markets, including Nasdaq, have from time to time experienced significant price and volume fluctuations. As a result, the market price of our common stock may be similarly volatile, and investors in shares of our common stock may from time to time experience a decrease in the market price of their shares, including decreases unrelated to our financial performance or prospects. The market price of shares of our common stock

Sales of a substantial number of shares of our common stock in the public market or the perception in the market that the holders of a large number of shares intend to sell shares (particularly with respect to our affiliates, directors, executive officers or other insiders) could depress the market price of our common stock and could impair our future ability to obtain capital, especially through an offering of equity securities. If there are more shares of common stock offered for sale than buyers are willing to purchase, then the market price of our common stock may decline. In the future, we may issue additional shares to our employees, directors or consultants under our equity compensation plans, in connection with corporate alliances or acquisitions, or to raise capital. Due to these factors, sales of a substantial number of shares of our common stock in the public market could occur at any time.

In the future, we may attempt to obtain financing or to further increase our capital resources by issuing additional shares of our common stock or by offering debt or other equity securities. Any future debt financing could involve restrictive covenants relating to our capital-raising activities and other financial and operational matters, which might make it more difficult for us to obtain additional capital and to pursue business opportunities. Moreover, if we issue debt securities, the debt holders would have rights to make claims on our assets senior to the rights of our stockholders. The issuance of equity securities or securities convertible into equity may dilute our existing stockholders. Debt securities convertible into equity could be subject to adjustments in the conversion ratio pursuant to which certain events may increase the number of equity securities issuable upon conversion.

TEC is a holding company that does not (and does not intend to) conduct any business operations or incur material obligations of its own. While we do not expect TEC to incur obligations that it is unable meet due to contractual restrictions on distributions from subsidiaries, certain subsidiaries are subject to such limitations. However, TEC’s cash flows are largely dependent on the operating cash flows of TES and TEC’s other subsidiaries and the payment of such operating cash flows to TEC in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from TEC and have no obligation (other than any existing contractual obligations) to provide TEC with funds to satisfy its obligations. Any decision by a subsidiary to provide TEC with funds to satisfy its obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary’s results of operations, financial condition, cash flows, cash requirements, contractual and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to TEC. Furthermore, the agreements governing the indebtedness of TES contain provisions restricting the ability of those entities to pay dividends or otherwise transfer assets to TEC.

The Indenture and Credit Facilities restrict the ability of TES to pay dividends or distributions to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or distributions: (1) in an amount not to exceed $160 million, (2) in an unlimited amount so long as TES’s pro forma consolidated total net leverage ratio is less than or equal to 1.5 to 1.0 (or, on and after the date the second quarter 2024 financials are due under the Credit Agreement, 2.0 to 1.0), and (3) in an amount not to exceed the sum of: (a) TES’s adjusted EBITDA minus 140% of TES’s consolidated interest expense, in each case, for the period beginning June 1, 2023 (subject to (i) in the case of the Credit Facilities, compliance with a pro forma consolidated total net leverage ratio of less than or equal to 2.75 to 1.0 (or, after the date the second quarter 2024 financials are due under the Credit Agreement, 3.25 to

Any determination to pay dividends to holders of our common stock in the future will be at the sole discretion of the Board of Directors and will depend upon many factors, including our historical and anticipated financial condition, cash flows, liquidity and results of operations, capital requirements, market conditions, our growth strategy and the availability of growth opportunities, contractual restrictions (including restrictions on the payment of dividends imposed by the Credit Facilities and the Indenture), our level of indebtedness and other restrictions with respect to the payment of dividends, applicable law and other factors that the Board of Directors deems relevant.

The three largest TEC stockholders collectively own approximately 38.2% of our outstanding common stock (the “Principal Stockholders”). Large holders such as the Principal Stockholders may be able to affect matters requiring approval by our stockholders, including the election of directors and the approval of mergers or other business combination transactions. See “Principal and Selling Stockholders.”

We expect that the trading market for our common stock will be affected by research or reports that industry or financial analysts publish about us or our business. There are many large, well-established companies active in our industry and portions of the markets in which we compete, which may mean that we receive unfavorable or less widespread analyst coverage than our competitors. If one or more of the analysts who covers us downgrades their evaluations of us or our common stock or TES or its indebtedness, the price of our common stock could decline. If one or more of these analysts cease coverage of us, our common stock may lose visibility in the market, which in turn could cause the price of our common stock to decline.

We are a Delaware corporation and the anti-takeover provisions of the Delaware General Corporation Law (the “DGCL”) 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.

Additionally, the Third Amended and Restated Certificate of Incorporation of TEC (the “Charter”) and the Second Amended and Restated Bylaws of TEC (the “Bylaws”) contain provisions that could depress the market price of our common stock by acting to discourage, delay or prevent a change in control of TEC or changes in our management that stockholders may deem advantageous. These provisions in our Charter and Bylaws, among other things:

These provisions could make it more difficult for a third-party to acquire us, even if the third party’s offer may be considered beneficial by many of our stockholders. As a result, our stockholders may be limited in their ability to obtain a premium for their shares of common stock. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.

As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), related regulations of the SEC and the requirements of Nasdaq, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and may strain our resources, increase our costs and distract management, which may inhibit our ability to comply with these requirements in a timely or cost-effective manner.

The standards required for a public company under Section 404(a) of the Sarbanes-Oxley Act are significantly more stringent than those required as a private company. While we generally must comply with Section 404 of the Sarbanes-Oxley Act, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our first annual report following the first entire fiscal year in which we are subject to reporting requirements of the Exchange Act. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to control effectiveness, our independent registered public accounting firm may issue a report that concludes it does not believe our internal controls over financial reporting are effective. Moreover, management may not be able to effectively and timely implement controls and procedures that adequately respond to the increased regulatory compliance and reporting requirements that will become applicable after the consummation of this offering. 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 report our financial condition or results of operations, which may subject us to adverse regulatory consequences, adversely affect our business and harm investor confidence and the market price of our common stock.

This prospectus contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would” or similar expressions. Although we believe that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that these expectations will prove to be correct. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially from the results discussed in forward-looking statements.

Such risks and uncertainties include, but are not limited to:

We caution you that the foregoing list may not contain all forward-looking statements made in this prospectus.

You should not rely on forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this prospectus primarily on our current expectations and projections about future events and trends that we believe may affect our business, financial condition and results of operations. The outcome

In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based on information available to us as of the date of this prospectus. While we believe such information provides a reasonable basis for these statements, such information may be limited or incomplete. Our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely on these statements.

The forward-looking statements made in this prospectus relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this prospectus to reflect events or circumstances after the date of this prospectus or to reflect new information, actual results, revised expectations or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments.

This prospectus relates to shares of our common stock that may be offered for resale by the Selling Stockholders, who may, or may not, elect to sell shares of our common stock covered by this prospectus. To the extent any Selling Stockholder chooses to sell shares of our common stock covered by this prospectus, we will not receive any proceeds from any such resales of our common stock, but we have agreed to pay certain registration expenses. The net proceeds from any resale of such shares will be received by the applicable Selling Stockholders. See the section titled “Principal and Selling Stockholders.”

Our common stock was quoted on the OTC Pink Market under the symbol “TLNE” from June 23, 2023 to July 23, 2023 and is currently quoted on the OTCQX U.S. Market under the symbol “TLNE,” where it has been traded since July 24, 2023. No established trading market existed for our common stock prior to June 23, 2023. The following table sets forth the per share high and low closing prices for our common stock as reported on the OTCQX U.S. Market for the periods presented.

On July 8, 2024, the closing price of our common stock as reported on the OTCQX U.S. Market was $118.99 per share. As of July 8, 2024, there were three stockholders of record of our common stock, not including beneficial owners of shares registered in nominee or street name.

We have been approved to list our common stock for trading on Nasdaq, under the symbol “TLN.”

The holders of shares of common stock are entitled to receive such dividends and other distributions (payable in cash, property or capital stock of the Company) when, as and if declared thereon by the Board of Directors from time to time out of any assets or funds of the Company legally available for the payment of dividends and shall share equally on a per share basis in such dividends and distributions.

Any future determination regarding the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors our Board of Directors may deem relevant. In addition, our ability to pay dividends may be restricted by agreements governing TES’s indebtedness and other agreements we may enter into in the future.

The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2024. You should read the information set forth below together with our consolidated financial statements and the related notes contained elsewhere in this prospectus.

The following unaudited pro forma financial information (the “Unaudited Pro Forma Financial Information”) consists of the Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2023. The Unaudited Pro Forma Financial Information was prepared as if the Plan of Reorganization had become effective and fresh start accounting occurred on January 1, 2023. An unaudited pro forma condensed consolidated balance sheet has not been presented, as the Plan of Reorganization and fresh start accounting adjustments have already been fully reflected in the Consolidated Balance Sheet as of December 31, 2023. The unaudited pro forma condensed consolidated statements of operations give effect to (i) various transactions effected pursuant to the Plan of Reorganization and (ii) the application of fresh start accounting.

The Unaudited Pro Forma Financial Information was derived from and should be read in conjunction with the Talen Energy Corporation and Subsidiaries Consolidated Statements of Operations for the Period from January 1, 2023 through May 17, 2023 (Predecessor) and for the Period from May 18, 2023 through December 31, 2023 (Successor).

The Unaudited Pro Forma Financial Information has been prepared in accordance with Article 11 of Regulation S-X, as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses.” The Unaudited Pro Forma Financial Information is presented for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan of Reorganization and the application of fresh start accounting had been consummated or applied, as applicable, on the dates indicated, nor is it necessarily indicative of our results of operations in the future.

The Plan of Reorganization implemented, among other things, the transactions contemplated by the RSA and the related settlements. Pursuant to the Plan of Reorganization, among other things:

Upon emergence from the Restructuring, TES adopted fresh start accounting, which resulted in TEC becoming a new entity for financial reporting purposes. As a result of fresh start accounting, TEC’s reorganization value was allocated to its individual assets and liabilities based on its fair values (except for deferred income taxes) in conformity with applicable guidance for business combinations. Deferred income tax amounts were determined in accordance with accounting guidance for income taxes. The estimated fresh start accounting adjustments give effect to the application of fresh start accounting to the unaudited condensed consolidated statement of operations assuming Emergence occurred on January 1, 2023.

Unaudited Pro Forma Condensed Consolidated Statement of Operations

for the Year Ended December 31, 2023

The unaudited Pro Forma Condensed Consolidated Statement of Operations sets forth the combined results of operations of: (i) Talen Energy Supply, LLC (“TES” or the “Predecessor”) for the period from January 1 through May 17, 2023 (Predecessor), (ii) Talen Energy Corporation (“TEC” or the “Successor”) for the period, from May 18 through December 31, 2023 (Successor), and (iii) pro forma impacts to the Successor after giving effect to Plan of Reorganization and the application of fresh start accounting as if the Plan of Reorganization and application of fresh start accounting had occurred on January 1, 2023.

The Unaudited Pro Forma Financial Information has been prepared in accordance with Article 11 of Regulation S-X and is provided to give effect to: (i) various transactions effected pursuant to the Plan of Reorganization, including the incurrence by TES of indebtedness and the issuance of new TEC equity at Emergence; and (ii) the application of fresh start accounting. The Unaudited Pro Forma Financial Information is presented for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan of Reorganization and the application of fresh start accounting had been consummated or applied, as applicable, on the dates indicated, nor is it necessarily indicative of our results of operations in the future.

Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity, and ancillary services into wholesale power markets in the United States primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic and Montana. The majority of our generation is produced at zero-carbon nuclear and lower-carbon gas-fired facilities. Consistent with our risk management initiatives, we may execute physical and financial commodity transactions involving power, natural gas, nuclear fuel, oil and coal to economically hedge and optimize our generation fleet.

See “Business—Our Properties” for additional information on our generation portfolio. See “—Recent Developments—ERCOT Sale” below for information on the recent sale of our generation assets in Texas.

Share Repurchase Program

In October 2023, the Board of Directors approved a share repurchase program initially authorizing the Company to repurchase up to $300 million of the Company’s outstanding common stock through December 31, 2025. In May 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion through the end of 2025. Repurchases may be made from time to time, at the Company’s discretion, in open market transactions at prevailing market prices, negotiated transactions, or other means in accordance with federal securities laws, and may be repurchased pursuant to a Rule 10b5-1 trading plan. The Company intends to fund repurchases from cash on hand. Repurchases by the Company will be subject to a number of factors, including the market price of the Company’s common stock, alternative uses of capital, general market and economic conditions, and applicable legal requirements, and the repurchase program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. The Company has no obligation to repurchase any amount of its common stock under the repurchase program. As of March 31, 2024, 493,000 shares of the Company’s common stock have been purchased under the share repurchase program for $39 million, inclusive of transaction costs. See Note 16 in Notes to the Annual Financial Statements for additional information. On July 1, 2024, the Company purchased an additional 5,027 shares under the share repurchase program for approximately $550,000.

In May 2024, the Company commenced the Tender Offer to purchase shares of the Company’s common stock for cash. The Tender Offer resulted in the purchase for cash of 5,275,862 shares of its common stock, representing 9.0% of the Company’s outstanding common stock, at a clearing price per share of $116.00, or an aggregate of $612 million.

On July 1, 2024, we entered into a purchase agreement with Rubric pursuant to which Rubric agreed to sell, and we agreed to repurchase from Rubric, 2,413,793 Shares at $116.00 per share of the Company’s common stock for an aggregate purchase price of $280 million pursuant to the Rubric Share Repurchase.

Remarketing of PEDFA Bonds

In June 2024, the Company completed a remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $80.6 million in aggregate principal amount of its PEDFA 2009C Bonds.

The PEDFA 2009B and PEDFA 2009C Bonds will now bear interest at 5.25% until the end of the new term rate period on June 1, 2027. In connection with the remarketing, the approximately $133 million of letters of credit that had previously backstopped the PEDFA 2009B and PEDFA 2009C Bonds will be terminated, providing the Company with increased capacity on its TLC.

Mandatory Share Exchange

In May 2024, each outstanding restricted share of the Company’s common stock issued with or under CUSIP No. 87422Q208 was exchanged for an unrestricted share of the Company’s common stock issued with or under CUSIP No. 87422Q109. The exchange was intended to provide stockholders with increased liquidity, permitting the previously restricted shares to now trade without restriction, subject to each holder’s compliance with (i) securities laws and (ii) rules promulgated by the OTCQX U.S. Market or Nasdaq, as applicable.

Term Loan Repricing

In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale, and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement. See Note 11 in Notes to the Interim Financial Statements for additional information on Talen’s indebtedness.

ERCOT Sale

In May 2024, the Company closed the previously announced sale of its approximately 1.7 GW generation portfolio located in the South Zone of the ERCOT market to CPS Energy for $785 million of gross proceeds (approximately $723 million in net proceeds after customary working capital adjustments and estimated taxes, transaction fees and other costs). These assets included the 897 MW Barney Davis and 635 MW Nueces Bay natural gas-fired generation facilities, both located in Corpus Christi, Texas, as well as the 178 MW natural gas-fired generation facility in Laredo, Texas. See Note 17 in Notes to the Interim Financial Statements for additional information.

Cumulus Digital Buyouts

In March 2024, TES acquired all of the equity units of Cumulus Digital Holdings held by affiliates of Orion and two former members of Talen senior management in exchange for $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital Holdings. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts” for additional information.

Cumulus Data Campus Sale

In March 2024, AWS purchased substantially all the assets of Cumulus Data for gross proceeds of $650 million, with $350 million delivered to the Company at closing and the remaining $300 million of consideration held in escrow. The first $200 million of escrowed proceeds will be released upon a zoning amendment approval or ordinance allowing construction and operation of data center facilities on the property sufficient to consume an aggregate of at least 540 MW of energy, with the remaining $100 million released upon similar zoning amendment approval sufficient to allow aggregate consumption of at least 960 MW. If the 540 MW zoning amendment approval is not granted prior to March 1, 2025 (subject to certain limited extensions), then AWS has the option either to (i) retain the property and release all escrowed funds to the Company or (ii) revert all escrowed funds to AWS and allow the Company a one-time right to repurchase the property for $355 million. If the 540 MW zoning condition is met but the 960 MW zoning amendment approval is not granted prior to March 1, 2028, the remaining $100 million of escrowed funds will revert to AWS. The zoning amendment was approved by the applicable township on May 28, 2024 for the 960 MW. After a required 30 day public comment period, it is expected the zoning amendment will be approved and that the remaining $300 million of consideration will be released to the Company.

In connection with the Cumulus Data Campus Sale, the Company executed the Cumulus Data Campus PPA with AWS, pursuant to which the Company agreed to supply long-term, carbon-free power from Susquehanna to the Cumulus Data Campus through fixed-price power commitments. Under the Cumulus Data Campus PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-applicable PJM energy and capacity prices. The initial term of the Cumulus Data Campus PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, Talen will receive additional revenue from AWS related to the sales of CFE to the grid. For additional information about the Cumulus Data Campus PPA, see “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale” and Note 17 in Notes to the Interim Financial Statements.

PJM, PPL, and Susquehanna have entered into the Amended ISA allowing Susquehanna to increase the amount of “behind-the-meter” power that it can provide to directly connected load under the current ISA. In June 2024, certain intervenors filed with FERC a protest to the Amended ISA. Talen does not currently expect this proceeding to have material impacts on the AWS transaction. For additional information, see “Business—Regulatory Matters—Susquehanna ISA Amendment.”

Cumulus Digital TLF Repayment

In connection with the Cumulus Data Campus Sale, the Company terminated the Cumulus Digital TLF and the outstanding obligations thereunder were satisfied and discharged in full. The security interests granted under the Cumulus Digital TLF were terminated, discharged and released. See Note 11 in Notes to the Interim Financial Statements and Note 13 in Notes to the Annual Financial Statements for additional information.

PPL/Talen Montana Litigation Settlement

In December 2023, Talen reached a litigation settlement with PPL. Under the terms of the settlement agreement, PPL paid TEC’s indirect subsidiary, Talen Montana, $115 million in cash in exchange for a full release of Talen Montana’s claims against PPL. Separately, Talen Montana remitted $11 million of the PPL settlement proceeds to the general unsecured creditors trust that was established pursuant to the Plan of Reorganization. See “Business—Legal Matters—Resolved Legal Matters—PPL/Talen Montana Litigation” and Note 12 in Notes to the Annual Financial Statements for additional information.

Riverstone Repurchase

In September 2023, TEC paid Riverstone $40 million in exchange for the cancellation of all of its TEC common stock warrants and a tax indemnity agreement, as well as waiving its future rights to the Retail PPA Incentive Equity. Also, in September 2023, TES and Orion purchased all of the equity units of Cumulus Digital Holdings held by Riverstone for an aggregate purchase price of $20 million, of which TES paid $19 million. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts,” “Certain Relationships and Related Party Transactions—Riverstone Warrant Cancellation” and Note 16 in Notes to the Annual Financial Statements for additional information.

Emergence from Restructuring

In May 2022, Talen commenced a reorganization under Chapter 11 of the Bankruptcy Code to allow the Debtors to, among other things, strengthen their financial position and provide additional liquidity to fund their operations and protect their investments in certain energy transition projects.

The Plan of Reorganization became effective in May 2023. At Emergence, TES adopted “fresh start” accounting, which required our assets and liabilities to be remeasured at fair value. Such measurement affected the carrying value of our assets and liabilities, and by extension, the comparability of our financial statements between periods.

Through consummation of the Exit Financings and the Plan of Reorganization, we achieved a significant reduction in debt and interest, provided for full repayment of TES’s Prepetition Secured Indebtedness and completed the consensual equitization of all of TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds.

Upon Emergence, the Successor experienced an ownership change under Section 382 of the Internal Revenue Code. The Internal Revenue Code Sections 382 and 383 impose limitations on the ability of a company to utilize tax attributes after experiencing an ownership change. As a result, we have estimated our annual base limitation is approximately $72 million against the utilization of our loss carryforwards and other tax attributes. The Company can increase its annual Section 382 base limitation for the amount of recognized built-in gain (“RBIG”) pursuant to the application of Notice 2003-65. The additional deemed RBIG is approximately $859 million over a 5-year recognition period. States generally have similar tax attribute limitation rules following an ownership change.

See Notes 2, 3 and 4 in Notes to the Annual Financial Statements for additional information regarding the Restructuring. See “—Liquidity and Capital Resources” for additional information on the Exit Financings and Note 13 in Notes to the Annual Financial Statements for additional information on Talen’s indebtedness.

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Statements,” “Risk Factors,” Notes 3 and 10 in Notes to the Interim Financial Statements, and Notes 5 and 12 in Notes to the Annual Financial Statements for additional information on our risks.

We completed the ERCOT Sale in May 2024. As a result, we have updated certain operational data presented in this prospectus to give effect to the ERCOT Sale. Our financial statements, segment information and related financial data as of and for the periods ending on or prior to March 31, 2024 include the results of operations from the ERCOT fleet. We intend to reevaluate our segment information for the first financial period after the ERCOT Sale, which is the quarter ending June 30, 2024.

Generation Facility Updates

In June 2023, PJM notified Brandon Shores that the units were needed for reliability. Talen subsequently notified PJM that it does not agree to continue to operate Brandon Shores under a Reliability-Must-Run arrangement. In April 2024, Brandon Shores filed a cost-of-service rate schedule at FERC for the continued Reliability Must Run operation and provision of service from these units. No assurance can be provided when, if at all, FERC will approve the filing. See Note 8 in Notes to the Interim Financial Statements and Notes 10 and 12 in Notes to the Annual Financial Statements for additional information.

Unusual Market Events

Commodity Markets

The following tables summarize average on-peak power prices and natural gas prices for each of the PJM, ERCOT, and WECC markets for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor). During the first quarter 2024, natural gas prices for Texas Eastern M-3 and Houston Ship Channel settled below each of their ten-year averages resulting from reduced demand for natural gas as the regions experienced milder quarterly average temperature conditions. In PJM, the combination of mild temperatures and natural gas prices contributed to the similar on-peak power price settlements experienced during the prior year. In ERCOT and WECC, increased demand resulting from colder-than-average temperatures during January 2024 contributed to higher average on-peak power prices in each region compared to the prior year.

The average January and February forward market prices as of March 31 were:

The average July and August forward market prices as of March 31 were:

The average third quarter forward market prices as of March 31 were:

The Mid-Columbia Day Ahead Peak 2024 quarter average settled prices increased approximately 5% compared to the prior year.

The Mid-Columbia 2024 and 2025 third quarter average on-peak forward prices decreased approximately 25% and 22%, respectively, compared to the prior year.

Capacity Markets

Approximately 85% of our generation capacity is located 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, ISO demand forecasts, reserve margin targets and adjustments to PJM MSOC as determined by the PJM IMM.

See “—Capacity Prices” below for additional information on capacity prices and see Note 10 in Notes to the Interim Financial Statements for additional information on the PJM RPM and other PJM matters.

Nuclear Production Tax Credit

The Inflation Reduction Act of 2022 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 program provides qualified nuclear power generation facilities with a $3 per MWh transferable credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna after December 31, 2023 through December 31, 2032 will qualify for the credit, which is subject to potential adjustments. Such adjustments include inflation escalators, a five-times increase in tax credit value (to $15 per MWh) if the qualifying generation facility meets prevailing wage requirements, and a pro-rata decrease in tax credit value once the annual gross receipts of a qualifying generation facility exceeds $25 per MWh. As the credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation), the Nuclear PTC program is expected to create a minimum price Susquehanna is expected to receive for its generation. Susquehanna generated approximately 18 million MWh in each of the calendar years 2023, 2022 and 2021.

The credit would be:

The Inflation Reduction Act’s provisions are subject to implementation regulations, whose terms are not yet known. No assurance can be provided as to the magnitude of the benefit to Susquehanna as the Inflation Reduction Act’s provisions, including the computations of the Nuclear PTC, are subject to implementation regulations. As such, Talen cannot fully predict the realization of any minimum price for Susquehanna’s generation and (or) impacts to Talen’s liquidity or results of operations. See Note 4 in Notes to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized.

Seasonality/Scheduled Maintenance

The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results in the future may fluctuate substantially on a seasonal basis. For example, a lack of sustained cold weather in the Mid-Atlantic region may suppress regional natural gas prices and reduce our future capacity and energy revenues. Alternatively, above-average temperatures in the summer tend to increase summer cooling electricity demand, energy prices and revenues, and below-average temperatures in the winter tend to increase winter heating electricity demand, energy prices and revenues. Inversely, the milder weather during spring and fall tend to decrease the need for both cooling electricity demand and heating electricity demand. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region and during the summer in Texas.

We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance requirements of our facilities and the terms of bilateral contracts to purchase or sell electricity. The largest and recurring maintenance project is the annual spring refueling outage at Susquehanna. The outages normally occur during late March and into April each year.

The results of operations presented below should be reviewed in conjunction with the Interim Financial Statements, the Annual Financial Statements, and their respective notes. Our financial results for the three-month period ending March 31, 2023, the period January 1 through May 17 , 2023, and for the years ended December 31, 2022 and 2021, are referred to as the “Predecessor” periods. Our financial results for the three-month period ending March 31, 2024 and the period from May 18 through December 31, 2023 are referred to as the “Successor” periods. The operating results of the three-month period ending March 31, 2024 and the period May 18 through December 31, 2023 cannot be adequately compared with any of the previous periods reported in the Interim Financial Statements or the Annual Financial Statements. Our results of operations as reported in the Interim Financial Statements and the Annual Financial Statements are prepared in accordance with GAAP.

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 revenues relate to sales to an ISO or RTO, sales under wholesale bilateral contracts or realized hedging activity, 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, unrealized gains (losses) on derivatives instruments resulting from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” in the Interim Financial Statements and the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities.

Results for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor)

Successor Period — Three months ended March 31, 2024

Net Income (Loss) Attributable to Members totaled $294 million for the three months ended March 31, 2024 (Successor). Results were driven by:

Predecessor Period — Three months ended March 31, 2023

Net Income (Loss) Attributable to Member totaled $48 million for the three months ended March 31, 2023 (Predecessor). Results were driven by:

Results for the period from May 18 through December 31, 2023 (Successor), the period from January 1 through May 17, 2023 (Predecessor), and the years ended December 31, 2022 and December 31, 2021 (Predecessor)

The following table and subsequent sections display the results of operations for the Successor and Predecessor periods: