Talen Energy Corp: Form 10-K for the period ended Dec 31, 2024

Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 10.7 gigawatts of power infrastructure in the United States, including 2.2 gigawatts of nuclear power and a significant dispatchable generation fleet. We produce and sell electricity, capacity, and ancillary services into wholesale U.S. power markets, with our generation fleet principally located in the Mid-Atlantic and Montana. Our team is committed to generating power safely and reliably, delivering the most value per megawatt produced and driving the energy transition. Talen is also powering the digital infrastructure revolution. We are well-positioned to capture this significant growth opportunity, as data centers serving artificial intelligence increasingly demand more reliable, clean power.

Our Operations

Our Fleet

The following discussion provides a brief overview of our fleet. See “Item 2. Properties” for additional information on each of our facilities.

Baseload, carbon-free nuclear facility. We operate, and own a 90% interest in, the 2.5 GW Susquehanna facility, the sixth largest nuclear-powered generation facility in the U.S. Susquehanna typically comprises approximately half of our total annual generation. In 2024, Talen produced over 18 GWh of reliable, zero-carbon power from Susquehanna at a low all-in cost of less than $24 per MWh, while also maintaining excellent safety and operational performance (when measured by standards adopted by the nuclear industry). Susquehanna’s efficient cost structure is supported in part by a portfolio of supply contracts for all stages of the nuclear fuel cycle. See “—Fuel Supply—Nuclear” for additional information. Susquehanna’s two units are currently licensed through 2042 and 2044, respectively (with up to 20-year extensions possible with regulatory approval).

Susquehanna has historically generated revenues primarily from energy sales into the PJM wholesale market, PJM capacity sales, and strategic hedging. As part of the AWS Data Campus Sale in 2024, Susquehanna and AWS have contracted under the AWS PPA for the long-term, fixed-price supply of power directly from Susquehanna to the adjacent AWS Data Campus. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale and “—Our Key Markets and Revenue Streams—Contracted Revenues—AWS PPA” for additional information on the AWS PPA. Susquehanna also benefits from the Nuclear PTC included under the Inflation Reduction Act, which runs through 2032 and provides a tax credit of up to $43.75 per MW (indexed to inflation) for power produced from a nuclear generation source. See “—Our Key Markets and Revenue Streams—Nuclear PTC” for additional information on the Nuclear PTC.

Dispatchable natural gas and oil intermediate and peaking units. Our 6.3 GW natural gas and oil fleet (of which 3.2 GW is from Brunner Island, Montour, and H.A Wagner Unit 3 after conversion, as discussed below) includes seven technologically diverse natural gas and oil generation facilities across the generation stack (including intermediate and peaking dispatch). Certain units are capable of utilizing multiple fuel sources, providing meaningful operational flexibility. These strategically located assets include significant generation in attractive wholesale markets (primarily PJM), allowing them to generate predictable revenues on cleared capacity while also benefiting from varying market dynamics. See “Item 2. Properties” for additional information on each of these facilities.

Reliability assets and carbon deleveraging. Our coal-fired generation assets continue to be impacted by changing environmental regulations and power market economics. We have already completed the conversion of approximately 3.2 GW of our legacy coal fleet to lower-carbon fuels, including our Brunner Island and Montour facilities, which together represent over 25% of our total generation capacity, and Unit 3 of our H.A Wagner facility. We previously requested deactivation of both H.A Wagner and our wholly-owned 1.3 GW Brandon Shores facility in mid-2025. However, PJM subsequently notified us that both H.A Wagner and Brandon Shores are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders to continue running both facilities through May 2029 under an RMR arrangement. See “—Our Key Markets and Revenue Streams—Contracted Revenues—Brandon Shores and H.A Wagner RMR Arrangements” and Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement. We also own minority interests, totaling approximately 800 MW, in three coal-fired generation facilities in PJM and WECC, and we are exploring ways to maximize the value of these assets in the context of changing market conditions. See “Item 2. Properties” for additional information on each of these facilities.

Our Key Markets and Revenue Streams

Our operating revenues have historically consisted primarily of capacity revenues, energy/ancillary services revenues, and unrealized gain (loss) on hedging instruments. As further discussed below, we sell capacity and energy through a combination of forward auctions, bilateral contracts, and spot market sales (as applicable). See “—Our Strategies—Optimize risk management program and hedging” for a discussion of our commercial optimization strategy. Beginning in mid-2025, we expect our Brandon Shores and H.A. Wagner facilities to begin operating as reliability resources under an RMR agreement that will provide fixed payments to Talen in addition to reimbursement for certain costs and expenses. In addition, our Susquehanna facility is party to the AWS PPA for the supply of power from Susquehanna to AWS through long-term, fixed-price power commitments that increase over time. See “—Contracted Revenues” for additional information on both the RMR arrangements and the AWS PPA. We continue to evaluate business opportunities resulting from industrial load growth. See “—Demand Growth from Multiple Sources” for additional information. We also benefit from the Nuclear PTC under the Inflation Reduction Act. See “—Nuclear PTC” for additional information.

Wholesale Markets

The substantial majority of our generation capacity is located in, and accordingly the majority of our revenues are derived from, PJM. Specifically, a majority of our generation capacity (over 10 GW) is located in the MAAC (Mid-Atlantic Area Council) and BGE (Baltimore Gas and Electric) regions of PJM. The remainder of our generation capacity is in ISO-NE and WECC. See “Item 2. Properties” for additional information on the market location of each of our facilities.

PJM. PJM is an RTO responsible for the operation of wholesale electric markets and for centrally dispatching electric systems in all or parts of 13 states and the District of Columbia. It coordinates the dispatch of approximately 180,000 MW of generating capacity to more than 65 million people and operates wholesale electricity markets with approximately 1,090 members. Generators in PJM may earn revenues from sales of capacity, energy, and (or) ancillary services.

The PJM Reliability Pricing Model is intended to ensure that resources are available when needed for grid reliability. Under this model, PJM conducts a series of forward capacity auctions, which establish a long-term market for capacity. We sell capacity through PJM Base Residual Auctions and, to the extent we are unable to sell capacity through the PJM BRAs, we may sell uncleared capacity through PJM Incremental Auctions or bilateral capacity transactions. PJM BRAs are typically conducted three years prior to the start of the applicable capacity year (which runs from June 1–May 31), but FERC has recently accepted requests by PJM to delay certain PJM BRAs in order to propose additional changes to the PJM Reliability Pricing Model. See “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.” and Note 12 to the Annual Financial Statements for additional information on ongoing market reforms in PJM and related auction delays. PJM also operates day-ahead and real-time markets into which generators can bid to provide energy and ancillary services. We sell energy/ancillary services into these markets. We also enter into bilateral transactions for the sale of energy directly to power purchasers.

ISO-NE. ISO-NE is an ISO that manages the flow of electricity from approximately 30,000 MW of generation capacity to approximately 15 million people in all or part of six states in New England. ISO-NE conducts forward capacity auctions and operates day-ahead and real-time energy/ancillary services markets. In ISO-NE, we both earn capacity revenues and sell energy/ancillary services into the spot markets from our Dartmouth generating facility.

WECC. WECC is a non-profit corporation that promotes a reliable and secure bulk electric system in the Western Interconnection, covering all or parts of Montana, 13 other U.S. States, Canada, and Mexico. WECC does not operate energy or capacity markets. The Colstrip facility in Montana operates within NorthWestern’s Balancing Authority within WECC. We enter into bilateral transactions for the direct sale of energy from our portion of the generation from Colstrip.

Contracted Revenues

Brandon Shores and H.A Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules (the “CORS”). If approved, the proposed RMR arrangements will extend the operating life of these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. Beginning June 1, 2025, the CORS will provide a monthly fixed-cost payment of $12,083,333 ($312/MW-day) for Brandon Shores and $2,916,667 ($137/MW-day) for H.A Wagner, which includes a performance “hold back” of $416,667 per month for Brandon Shores and $208,333 per month for H.A Wagner, each to be paid out based on unit performance. We will also receive separate reimbursement for variable costs and approved project investments. See Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement.

AWS PPA. In connection with the AWS Data Campus Sale in 2024, we and AWS entered into the AWS PPA, pursuant to which we agreed to supply long-term, carbon-free power from Susquehanna to the AWS Data Campus through fixed-price power commitments. Under the AWS 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 AWS PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, we will receive additional revenue from AWS related to the sales of carbon-free energy to the grid. We expect to begin receiving initial revenues from power sales in 2025. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale.

In November 2024, FERC issued an order denying the Susquehanna ISA Amendment between PJM, PPL Corporation, and Susquehanna that would permit Susquehanna to decrease the amount of power supply it would otherwise provide to the power grid. Such order does not have an impact on the existing ISA permitting 300 MW of co-located load at Susquehanna to supply power for the first phases of the AWS Data Campus. In December 2024, FERC issued an order stating that it would address our request for rehearing in a future order, which FERC has not yet issued. Due to FERC’s decision not to address the merits of our motion for rehearing, we have filed an appeal in the U.S. Court of Appeals for the Fifth Circuit. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.” We are evaluating our commercial and legal options to provide the most efficient path to full development of the AWS Data Campus. Such options include, but are not limited to, potential submission of a revised form of Susquehanna ISA Amendment or alternative contract structures with AWS. See “Item 3. Legal Proceedings” and “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—Our business is subject to extensive energy-related regulation and oversight.” for additional information on the Susquehanna ISA Amendment.

Demand Growth from Multiple Sources

Power demand forecasts continue to rise over time in PJM compared to previous expectations. In January 2025, PJM released updated long-term load forecasts which point to RTO-wide load in summer 2030 and 2035 that is approximately 10% and 17% higher, respectively, than 2024 expectations. Fundamental demand growth in PJM is expected to come from multiple sources, most notably high-performance computing and data center demand, continued re-shoring in the wake of the COVID-19 pandemic and associated supply chain disruptions, and continued electrification of the U.S. economy. This demand growth is not currently well matched with increases in supply, as the PJM queue for new-build generation is predominately intermittent rather than dispatchable in nature. In addition, continued PJM coal plant retirements are expected through the end of the decade. These drivers of demand have had, and could continue to have, direct impacts on the overall supply/demand balance and resulting energy and capacity prices in the markets in which we operate, the profitability, value, and growth prospects of our business, and the regulatory framework under which we operate.

Nuclear PTC

The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $43.75/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $25/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. This program serves as an important tool for mitigating power price exposure, effectively creating a minimum price that Susquehanna is expected to receive for its generation. We can monetize the credit by reducing our income taxes payable or selling the credits to a third-party. See Notes 6 and 7 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the Inflation Reduction Act.

Fuel Supply

Our power generation assets are advantaged by significant fuel diversity, including nuclear, natural gas, coal, oil, and various dual-fuel capabilities. Further, our natural gas generation assets are situated near the Marcellus shale region of Pennsylvania, which provides access to fuel from one of the largest producing natural gas regions in the U.S. See “Item 2. Properties” for additional information on the fuel capabilities of each of our facilities.

Nuclear. Susquehanna has a portfolio of supply contracts for raw uranium, conversion, enrichment, and fabrication. Our nuclear fuel cycle is fully contracted through the 2027 fuel load, almost entirely contracted through 2028, and over 70% contracted through 2029. We have no current fuel exposure to any Russian-affiliated counterparties. Susquehanna has an on-site dry-cask spent fuel storage facility that, together with its spent fuel pools, accommodates discharged SNF. We expect to continue expanding this storage facility in phases to accommodate additional SNF and, assuming receipt of appropriate approvals, we expect such expansion to accommodate all of the SNF discharged by Susquehanna through 2044, the current license life of unit 2. Federal law requires the U.S. government to provide for the permanent disposal of commercial SNF, but the government has not yet done so. Consequently, under a related settlement agreement, the government is required to reimburse Susquehanna for certain SNF storage costs through 2025. See Note 12 to the Annual Financial Statements for additional information on this arrangement.

Natural Gas and Oil. We manage our natural gas and oil supply utilizing a combination of contracted purchases, spot market purchases, and on-site storage for the commodities and pipeline capacity. The amount and duration of contracted purchases vary due to factors including fuel availability, economic considerations, and generation facility location on the pipeline grid. A significant portion of our natural gas need is satisfied through short-term transactions on a spot basis. Oil is generally supplied from on-site inventory and replenished through purchases on the spot market. The price risk associated with these transactions is managed via financial hedges.

Coal. We actively manage our coal requirements by purchasing coal from central and northern Appalachia for our PJM facilities and from a mine adjacent to Colstrip for that facility. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine production issues, and other supplier or transporter operating difficulties. We maintain coal inventory at levels estimated to be necessary to avoid operational disruptions at our coal-fired units. Short- and long-term supply contracts support adequate coal inventory levels and are augmented with spot market purchases as needed.

Seasonality/Scheduled Maintenance

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

Competition

Increased competition in U.S. energy markets exists in part due to federal and state competitive market initiatives. The power generation business is regionally varied in industry structure and fundamentals. PJM, the primary market in which we operate, is a competitive market and has from time-to-time considered new market rules, while some states have considered re-regulation measures that could result in more limited opportunities for competitive energy suppliers. See Note 12 to the Annual Financial Statements for additional information on ongoing market reforms in PJM. We face competition in wholesale markets from other suppliers of available energy, capacity, and ancillary services, which may include operators of various competing generation technologies, such as natural gas-fired, coal-fired, and nuclear generation, as well renewable and other alternative energy sources. Competition is affected by electricity and fuel prices, grid congestion, government subsidies for new and certain existing generation facilities (including some which might otherwise retire), new market entrants, construction of new generation assets, technological advances in power generation, environmental and regulatory matters, and various other factors. Competitors in wholesale power markets include other non-utility generators, regulated utilities and their competitive subsidiaries, industrial companies, financial institutions, and other energy marketers. See also “Item 1A. Risk Factors—Industry and Market Risks—We face intense competition in the competitive power generation market.” and “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.”

Insurance

Power generation involves hazardous activities, which could expose our assets, employees, contractors, customers, and the general public to various risks inherent in the nature of our operations. Various hazards, including but not limited to accidents or natural disasters, can cause damage or destruction of our assets or other property and equipment, personal injury or loss of life, pollution or environmental damage, and (or) suspension of operations. We maintain a portfolio of general liability, property, business interruption, pollution liability, workers’ compensation, nuclear, cybersecurity, financial lines, and other insurance policies (as applicable) with varying limits, deductibles, and self-insurance that we believe are reasonable and prudent under the circumstances to cover our operations and assets; however, we cannot provide any assurance that our insurance program 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 or at all. We will continue to periodically evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program. See also “Item 1A. Risk Factors—Industry and Market Risks—Operation of power generation facilities involves significant risks and hazards customary to the power industry, which we cannot assure our insurance will be adequate to cover.,” “Item 1C. Cybersecurity,” and Note 12 to the Annual Financial Statements.

Our Strategies

We believe we are well-positioned to achieve our business objectives through the following strategies:

Focus and maintain our core generation fleet that provides stable earnings and cash flows. Our core fleet, anchored by our Susquehanna nuclear facility, generates stable earnings from cleared capacity and cash flows backed by multiple sources. Our integrated generation, wholesale marketing, and commercial capabilities enable us to produce significant recurring cash flow, and our commercial and risk management strategies provide cash flow stability while balancing operational, price, and liquidity risk through physical and financial commodity transactions. In today’s robust but volatile energy markets, our team has been able to capture high realized pricing through both reliable generation and strategic risk management. Capacity revenue is a key indicator of the important role that nuclear, natural gas, and peaking generation all play in PJM grid reliability. In 2024, our PJM fleet generated significant capacity revenues. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” for additional information on our energy and capacity revenues. We are now also poised to benefit from long-term, stable cash flows from both contractual revenues under the Brandon Shores and H.A. Wagner RMR arrangements and fixed-price power sales under the AWS PPA. See “—Our Key Markets and Revenue Streams—Contracted Revenues” for additional information on both the RMR arrangements and the AWS PPA. We now also have substantive federal support for nuclear generation, which is accretive to our portfolio, in the form of the Nuclear PTC. See “—Our Key Markets and Revenue Streams—Nuclear PTC” for additional information on the Nuclear PTC.

Continue our operational excellence, with focus on continued efficiencies. The foundation of our platform is safe, disciplined operational and commercial performance. We drive operational excellence by maximizing the safety, reliability, and efficiency of our core assets. While we will continue to evaluate ways to find the highest and best use of our assets and capital, we are committed to maintaining best-in-class operations at our core generation facilities, including a disciplined cost structure across all categories. To sustain our robust performance, our leadership team focuses on, among other priorities, maximizing reliability through carefully planned and periodic maintenance and upgrades of our equipment, retaining experienced facility managers and employees and positioning them on-site to address emerging issues quickly, capitalizing on procurement efficiencies across our platform, and implementing redundancy in our generation facility design. While prioritizing operational safety and excellence, we intend to continue evaluating and executing on available opportunities for additional cost efficiencies.

Optimize risk management program and hedging. We are focused on maintaining appropriate risk management policies in the context of a right-sized balance sheet and the cash flow stability provided by the Nuclear PTC. We maintain both an internal risk management committee, comprised of members of senior management from across the organization, and a Board-level risk oversight committee, comprised of members of our Board of Directors with extensive trading and risk backgrounds. Our commercial optimization strategy is focused on hedging commodity price volatility within appropriate risk tolerances while providing stable cash flow generation and preserving forward margin. We employ a variety of physical and financial instruments to manage risk and optimize the value of our assets. In some cases, we use a portfolio approach to manage risks, such as those associated with capacity and ancillary offerings. We target a hedge range of 60-80% of our expected generation for the prompt 12 months and ratably scale the hedge percentage down further out in time to align with our financial objectives. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. We intend to continue employing a disciplined strategy focused on first-lien hedging while minimizing exchange-based hedging and the associated margin requirements. Importantly, we now have lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) and significantly reduced debt service requirements following the Restructuring and subsequent refinancing transactions.

Maintain disciplined financial policy and capital allocation. We actively manage our capital structure, future capital commitments, and asset base by following disciplined capital allocation principles focused on generating cash flow, maintaining reasonable leverage, and reducing our cost of capital. We have a strong balance sheet underpinned by modest leverage, robust liquidity, and no significant debt maturities until 2030. Our strong balance sheet also provides ample capacity and counterparty appetite for lien-based hedging, which does not require cash collateral posting, and we intend to prioritize balance sheet efficiency through the active preservation of liquidity, targeting a modest leverage profile with a go-forward net leverage ratio of 3.5x or less, depending on seasonal dynamics. In furtherance of our disciplined capital allocation strategy, we are targeting the return of 70% of our adjusted free cash flow to shareholders through the share repurchase program authorized by our Board of Directors. See “Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities—Issuer Purchases of Equity Securities” and Note 18 to the Annual Financial Statements for additional information on the SRP and other share repurchases.

Maximize the value of our platform opportunities in a capital efficient manner. We believe there is significant value embedded in our platform, and that we have the flexibility to explore both organic and inorganic growth options. In addition to optimizing our core operations, we have unlocked previously unrecognized value from our existing assets and believe we have more opportunities to do so. Within our generation portfolio, we remain focused on delivering the most value per megawatt produced, including through long-term power sales to computing, industrial, or other end users, whether from our reliable, zero-carbon nuclear facility - Susquehanna - or our dispatchable fossil fleet. We expect to evolve our asset base both by continuing to evaluate opportunities to drive value uplift for our existing assets and by pursuing opportunistic acquisitions and divestitures in order to drive cash flow generation and investor returns, all in keeping with our commitment to appropriate leverage levels and a thoughtful capital allocation framework. We will continue exploring strategic opportunities if economically favorable, but any strategic investment will require a sound basis and an attractive returns profile when compared to other uses of capital.

Legal, Regulatory, and Environmental Matters

Legal Matters

We are involved in various legal and administrative proceedings, investigations, claims, and litigation from time to time in the course of our business. Such matters may include, but are not limited to, those relating to employment and benefits, commercial disputes, personal injury, property damage, regulatory matters, environmental matters, and various other claims for injuries and (or) damages. While we believe we have meritorious positions and will continue to appropriately respond to all legal matters, because of the inherently unpredictable nature of legal proceedings, there is a wide range of potential outcomes for any such matter. See “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks” for additional information on legal risks related to our business. See “Item 3. Legal Proceedings” and Note 12 to the Annual Financial Statements for additional information on specific legal matters.

Energy Regulation

We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to FERC; the Department of Energy; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. See “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks” for additional information on regulatory risks related to our business. The following discussion provides an overview of certain key regulatory matters applicable to our business. See Note 12 to the Annual Financial Statements for additional information on these and other regulatory topics.

FERC. Our subsidiaries that own or control electric generation facilities are defined as public utilities under the Federal Power Act and are subject to FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. FERC has the authority to grant or deny market-based rate authority for wholesale sales of energy, capacity, and ancillary services to ensure that such sales are just and reasonable and not unduly discriminatory, and to suspend market-based rate authority and set cost-based rates if it finds that its previous grant of market-based rate authority is no longer just and reasonable. Other matters subject to FERC’s jurisdiction include, but are not limited to: review of certain public utility dispositions of jurisdictional facilities, mergers, acquisitions of other public utility securities, or acquisitions of existing generation facilities; review of certain holding company acquisitions of securities of, or mergers with, a public utility or other holding company; third-party financings; affiliate transactions; intercompany financings and cash management arrangements; and certain internal corporate reorganizations.

RTOs and ISOs. RTOs and ISOs are FERC-regulated entities that exist in several regions to provide transmission service across multiple transmission systems. FERC has approved PJM, MISO, ISO-NE, and SPP as RTOs and CAISO and NYISO as ISOs. These entities are responsible for regional planning, managing transmission congestion, developing wholesale markets for energy and capacity, maintaining reliability, market monitoring, the scheduling of physical power sales brokered through ICE and NYMEX, and managing transmission charges across multiple systems. With the exception of Colstrip in Montana, all of our generation facilities currently participate in wholesale electricity markets administered by PJM and ISO-NE. See “—Our Operations—Our Key Markets and Revenue Streams—Wholesale Markets” for additional information on the RTOs and ISOs in which we operate.

Nuclear. Under the Atomic Energy Act of 1954, as amended (the “Atomic Energy Act”), our operation and 90% ownership of Susquehanna are subject to regulation by the NRC, including requirements pertaining to, among other matters: licensing, inspection, and enforcement; testing, evaluation, and modification of all aspects of nuclear reactor power generation facility design and operation; environmental and safety performance; handling and storage of SNF; technical and financial qualifications; decommissioning funding assurance; and transfer and foreign ownership restrictions. The NRC may modify, suspend, or revoke operating licenses and impose civil or criminal penalties for failure to comply with the Atomic Energy Act or the terms of nuclear operating licenses. In addition, new or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. The current facility operating licenses for our two units at Susquehanna expire in 2042 and 2044. See Note 9 to the Annual Financial Statements for additional information on the NDT. See “—Our Operations—Fuel Supply—Nuclear” for additional information on SNF.

Other Regulation. In addition to federal regulation, our operations are subject to various state and local laws and regulations. These include oversight of siting, permitting, and environmental compliance for our facilities, as well as participation in state-specific energy markets and programs. Our operations are also subject to compliance with reliability standards developed and enforced by NERC and its regional entities. Compliance with these standards is critical to maintaining the reliability of the bulk electric system and avoiding penalties for violations. See “—Environmental Regulation” for additional information on environmental regulation of our business.

Environmental Regulation

Our business is subject to extensive federal, state, and local environmental laws, regulations, and requirements, including but not limited to those related to air emissions, water discharges, hazardous substances, and solid waste management. These requirements have become more stringent over time and impose, among other things: (i) permitting requirements for regulated activities; (ii) costs to limit or prevent pollution or other contamination; and (iii) substantial liabilities and remedial obligations for pollution or contamination. Accordingly, in the ordinary course of our business, we may: (i) incur significant costs to comply with environmental requirements; (ii) be required to modify, curtail, replace, or cease certain operations for environmental reasons; (iii) be required to perform environmental remediation work; or (iv) become involved in other environmental matters, including government enforcement actions and citizen’s suit litigation. In addition, environmental requirements are rapidly evolving, and we may become subject to new or revised environmental laws, regulations, or requirements. Legal challenges to environmental regulations, rules, and requirements add to the uncertainty of estimating future compliance and remedial costs. In addition, in January 2025, President Trump issued executive orders directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, future implementation and enforcement of these rules remains uncertain at this time.

See “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks” for additional information on environmental risks related to our business. The following discussion provides an overview of certain key environmental matters. See Note 12 to the Annual Financial Statements for additional information on these and other environmental topics.

Air. Under the Clean Air Act, as well as comparable state laws and local ordinances, our plants are subject to extensive emission control, emission allowance, emission monitoring, and air reporting obligations. Compliance with these requirements impacts the operation of our plants as well as their operating costs. In addition, new or modified obligations could significantly impact how we produce electricity and the life of certain plants (in some cases resulting in premature unit retirements) and could impede strategic planning. Key air matters currently affecting our business include, but are not limited to, nitrogen oxides requirements (including potential implementation of the EPA’s Good Neighbor Plan or similar requirements) as well as the revised EPA MATS and GHG Rules, both of which could significantly impact certain facilities, including our Colstrip facility, and are being legally challenged by us and others.

Hazardous Substances and Waste Handling. Our business is subject to a range of waste laws and regulations at the federal, state, and local levels. These rules are designed to manage and mitigate the potential environmental and health impacts of waste generated by power plants during the production of electricity, and they put controls in place on waste disposal, management, transportation, and storage. The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the “Superfund” law, and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owners or operators of the site where the release occurred and companies that transported or disposed, or arranged for the transport or disposal, of the hazardous substances at the site where the release occurred. Most states have also enacted statutes that contain provisions substantially similar to CERCLA. We generate materials in the course of our operations that may be regulated as hazardous substances based on their characteristics under CERCLA and analogous state laws.

The EPA’s regulation of CCRs under the Resource Conservation and Recovery Act is a currently evolving regulatory program under which we may incur significant costs impacting AROs. We have joined several parties to legally challenge the EPA’s new requirements for legacy CCR surface impoundments under the EPA CCR Rule, while also following the Rule’s timeline to assess applicability and define cost impacts to our business.

Water. Various statutes and regulations at the federal, state, regional, and local levels govern water use, discharge, protection, and influence and add challenge and uncertainty to our business. The Federal Water Pollution Control Act, known as the Clean Water Act (“CWA”), and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants into federal and state waters. The discharge of pollutants into regulated waters is prohibited except in accordance with the terms of a permit issued by the EPA or a state equivalent agency. Compliance with existing and future requirements may increase costs, affect operations, and impede strategic planning. One of the most impactful CWA programs currently affecting our business is the EPA ELG Rule, under which certain of our generation facilities have incurred operating restrictions and committed to prematurely end the use of certain fuels. In the future, new permit conditions could be established to meet the EPA’s most recent revisions to the EPA ELG Rule, which will be defined following negotiations with state permitting authorities. We and other parties are legally challenging the EPA’s latest revisions to the EPA ELG Rule. Until litigation is complete and permit conditions are established, full cost impacts remain uncertain.

Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of employees. In addition, the Occupational Health and Safety Administration's (“OSHA”) hazard communication standard, the Emergency Planning and Community Right to Know Act and implementing regulations and similar state statutes and regulations require us to maintain information about hazardous materials used or produced in our operations, and this information is required to be provided to employees, state and local government authorities, and citizens.

Corporate Responsibility

Through our core values of Excellence, No Harm, Integrity, and Continuous Improvement, we are committed to operating thoughtfully and ethically as we strive to consider impacts to our stakeholders, including communities, employees, customers, suppliers, investors, and the environment. Our approach to corporate responsibility, with oversight from our Board of Directors, is a key to the long-term success of our business.

Environmental

Our emission profile is firmly anchored by Susquehanna, which enabled us to generate over half of our electricity output carbon-free in 2024, and our natural gas portfolio also includes a number of energy-efficient assets with low heat rates, which provide a lower carbon intensity than traditional fossil fuel sources. We have reduced our environmental footprint over the past several years, investing heavily in environmental controls and switching to cleaner fuels in response to market and other conditions. We have already completed the conversion of our Brunner Island, Montour, and H.A. Wagner plants to lower-carbon fuels. See “—Our Fleet—Reliability assets and carbon deleveraging” for additional information.

As of December 31, 2024, we have reduced our annual carbon dioxide emissions by approximately 65% when compared to 2010 levels. We expect to continue reducing our carbon footprint through the recently-completed conversions of our legacy coal fleet discussed above and the eventual retirement of certain other legacy coal assets. See Note 10 to the Annual Financial Statements for additional information on ongoing RMR proceedings and a pending settlement related to our Brandon Shores and H.A. Wagner facilities. As we retire older, economically nonviable conventional power generation assets, we are continuing to explore opportunities to repurpose these sites to advance our carbon deleveraging while also extending the life and increasing the value of our legacy assets.

We are an innovator in the movement to power critical infrastructure and industry with carbon-free nuclear generation. Prior to its sale to AWS, we initially developed the data center campus adjacent to our Susquehanna facility, the world’s first 24x7 carbon-free, direct-connect data center campus, to provide digital infrastructure powered by generation from Susquehanna. We are well-positioned to continue leading the energy transition by responsibly providing zero- and low-carbon power to meet growing demand from energy consumers in a variety of sectors, many of whom have sustainability requirements.

Community Engagement

We generally focus our community engagement and philanthropic efforts in the local communities we serve and where our employees live and work. We believe that a decentralized approach to engagement and giving allows us to more effectively identify areas of need and have a greater local impact. Across our fleet and our corporate offices, our facilities and their employees, often in conjunction with charitable organizations such as United Way, Salvation Army, and local food banks, we strive to participate regularly in events supplying holiday toys, school supplies, food, winter coats, volunteer work, and monetary donations. For instance, to date, events hosted by Susquehanna have raised over $1.1 million for the Berwick Area United Way. Our plants also provide community education through both on-site and off-site programs and events with first responders, professional organizations, students, interns, scouts, and other groups. The majority of our operating facilities also provide nature preserves or other recreational sites that allow for community activities such as golf, fishing and boating, walking and hiking, outdoor education, sports, and other events.

Our business also provides significant support to the communities in which we operate in the form of critical services, high-quality jobs, economic development, and tax dollars. We have adopted a Supplier Code of Conduct (available on our website) to promote safe, ethical, and socially-conscious behavior among our suppliers. Throughout 2024, we worked with all stakeholders to reach an arrangement for the continued operation of our Brandon Shores and H.A. Wagner facilities past their initially planned retirement dates to support grid reliability in the greater Baltimore area. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders to continue running both facilities through May 2029 under an RMR arrangement. The continued operation of these facilities maintains critical infrastructure, facilitates reliable electricity in Baltimore, and protects Maryland consumer electricity rates. See “—Our Key Markets and Revenue Streams—Contracted Revenues—Brandon Shores and H.A Wagner RMR Arrangements” and Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement.

We believe the emerging data economy and the growing importance of artificial intelligence and continued re-shoring will require an all-of-the-above approach to generating the electricity necessary to power load in a responsible and efficient manner. Our AWS PPA is an example of how we are powering the future in partnership with data center and artificial intelligence enterprises and, in the case of the AWS PPA, doing so with large volumes of clean, carbon-free energy. We are actively engaged in the policy discussions taking place between generators, PJM, political leaders, and consumer advocates to solve burgeoning resource adequacy issues and seek to ensure the availability of affordable and reliable power in the regions we serve.

Human Capital

We strive to maintain a culture that empowers our employees to influence operational decisions and to trust and rely on each other, while driving safety, operational excellence, and strong financial performance. We believe our people are a valuable asset. As key stakeholders in our business, we invest in our employees by prioritizing their safety, presenting numerous training and development opportunities, carefully considering employee feedback, offering competitive compensation that includes our employees in the success of our business, providing comprehensive health and wellness benefits, and fostering an inclusive and respectful workplace.

Safety. At Talen, safety is a core value. We strive for a “No Harm” culture for all our employees, suppliers, guests, and communities, and we strive to continuously improve our systems, processes, and communications to support the safe operation of our business. Our safety management system focuses on four key components: Safety Policy, Risk Management, Safety Assurance, and Promotion. Within our safety management framework, we take a decentralized approach to health and safety coupled with centralized reporting, information sharing, and oversight. This empowers our business units and operating plants to determine the most appropriate health and safety procedures, training, engagement, and incident resolution at their sites while facilitating knowledge sharing, enabling continuous improvement, and fostering a “No Harm” culture across our organization.

We track and (or) externally report OSHA recordable incidents, lost time injuries, and near miss incidents to enhance knowledge sharing and organizational learning. In 2024, we had seven OSHA recordable incidents and an OSHA Total Recordable Incident Rate (“TRIR”) of 0.34. Our overall safety performance is a result of an enhanced health and safety framework and training, increased leadership visibility and accountability, and a greater focus on incident reporting, including near misses and good catches. Our safety team reviews several proactive metrics to mitigate risks before they become safety incidents. All employees and contractors are required to immediately report all safety-related incidents and have a responsibility to stop work when there is a safety concern. Once a “stop work” situation has been identified, a corrective plan must be developed and the safety team determines a path to continue work. Prior to resumption of work, a supervisor or manager that is “one step removed” must review and concur with the plan to continue work. Susquehanna has an additional corrective action Employee Concerns Program that establishes procedures for reporting and resolving nuclear safety and general work environment concerns.

We continuously work to improve safety. In 2022, we implemented an annual Safety Assessment Program, under which safety professionals from across the organization inspect plants with a focus on workplace inspections, work observations, and regulatory compliance. Other recent safety enhancements have included improvements to our overall safety management system, as well as the addition of a company-wide safety summit, a strain/sprain program, a supervisor safety assessment program, and a human performance management program. We believe these initiatives will continue to support our strong safety culture. Our safety management system allows frequent analysis of all aspects of safety for continuous monitoring and improvement, and has been key to our safety performance in 2024.

Training, Development, and Feedback. We recognize that our success depends on our ability to attract, retain, motivate, and develop qualified personnel, and we strive to provide our employees with the tools they need to succeed personally and professionally. We provide training programs covering a wide range of relevant job- and Company-specific topics for employees in all positions, including continuing education resources for professional licenses, and we also regularly promote and train interested employees into new roles. To train the next generation of professionals, we offer apprenticeship programs, internships, and educational assistance. To further develop promising leadership across our organization, we offer programs such as the Talen Leadership Academy and the Union Leader Academy, which are seminars covering a variety of business, operational, leadership, and interpersonal skills.

Formal and informal feedback at Talen runs in all directions. In addition to this feedback, non-union employees annually receive a formal review to discuss their performance, development, and goals. Coaching and performance improvement plans are used when appropriate. We strive to thoughtfully consider and respond to ideas and feedback from all employees, including plant management teams, asset managers, and frontline workers, and we provide a variety of avenues for employee feedback, including through performance review dialogue, appropriate escalation of informal feedback, and various identifiable and anonymous formal reporting channels. In 2024, we conducted an anonymous employee engagement survey and, after reviewing the results, reported key themes and next steps to employees. We have already implemented a number of specific employee recommendations.

Compensation, Benefits, and Wellness. We are committed to maintaining a highly competitive compensation structure. We maintain short-term and long-term cash incentive programs for many employees, as well as a long-term equity compensation program that aligns the interests of key team members with our strategy and the interests of our stockholders. Starting in 2025, we also offer an employee stock purchase program, under which eligible employees can purchase our common stock at a discount through payroll deductions. Full- and part-time employees also qualify for our 401(k) plan, under which we make fixed, matching, and (or) additional discretionary contributions (depending on employment specifics).

We maintain a comprehensive benefits program, under which eligible employees and their dependents are offered healthcare coverage, life and accident insurance, short- and long-term disability, maternity and parental leave, and (or) identity theft protection. To further support employee wellness, we also offer virtual health screenings, diabetes management programs, and reduced pricing on specialty medications. All employees are also eligible for our employee assistance program, which provides mental and physical health resources and discounts on essentials such as childcare, education, and insurance, among other things.

Collective Bargaining Agreements. As of December 31, 2024, we had 1,894 full-time employees, approximately 43% of which were represented by labor unions. Our collective bargaining agreements (“CBAs”) include: (i) a CBA with IBEW Local 1638, covering 193 Talen Montana employees, which is in effect until April 2026; (ii) a CBA with Teamsters Local 190, covering six Talen Montana employees, which is in effect until August 2027; and (iii) a CBA with IBEW Local 1600, covering 626 Pennsylvania employees, which is in effect until August 2025. We maintain generally constructive relationships with our labor unions.

Governance

We are committed to maintaining corporate governance policies and practices that support the interests of all our stakeholders. Our values of Excellence, No Harm, Integrity, and Continuous Improvement help foster a culture of robust governance from the Board of Directors and officers to each employee. Additional information about our corporate governance will be set forth in the 2025 Proxy Statement.

Emergence from Restructuring

Increased collateral posting requirements caused by rapid and sustained increases to wholesale natural gas and power prices in mid-2021 resulted in lower available cash and liquidity to operate our business. As a result, TES and 71 of its subsidiaries commenced the Restructuring in May 2022 and TEC joined the Restructuring in December 2022. The Company emerged from the Restructuring in May 2023 with a significantly deleveraged balance sheet. See Notes 3 and 4 to the Annual Financial Statements for additional information on the Restructuring.

Corporate and Other Available Information

We are a Delaware corporation with our principal executive office located at 2929 Allen Parkway, Suite 2200, Houston, TX 77019. The telephone number for our principal executive office is (888) 211-6011. We maintain a website at www.talenenergy.com (http://www.talenenergy.com). Information contained on or accessible from our website is not, and shall not be deemed to be, incorporated by reference into this Report or any other filings with the Securities and Exchange Commission (the “SEC”).

We file our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports with the SEC. You may obtain copies of these documents, free of charge, on the SEC's website at www.sec.gov (http://www.sec.gov). In addition, as soon as reasonably practicable after such materials are filed or furnished with the SEC, we make copies available free of charge on the “Investor Relations” section of our website at https://ir.talenenergy.com. We also post important information, including press releases, investor presentations, and notices of upcoming events on our website, and utilize it as a channel for distributions to public investors and for disclosing material non-public information in compliance with Regulation FD. Investors may be notified of postings to our website by signing up for email alerts under the “Resources” tab on the “Investor Relations” section of our website.

You should carefully read and consider all the risks and uncertainties described below, as well as the other information included in this Report, including the Annual Financial Statements. Although we believe the following discussion includes the key risks affecting our business, new risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on our business. The occurrence of any of the following risks, or additional risks and uncertainties not presently known to us or that we currently believe to be immaterial, could materially and adversely affect our business, financial condition, results of operations, cash flows, and (or) liquidity.

Industry and Market Risks

We may be adversely impacted by changes in the market prices, availability, and transmission of electricity, fuel, and other commodities.

Market prices for electricity, capacity, ancillary services, natural gas, uranium, coal, and fuel oil are unpredictable and fluctuate substantially over relatively short periods. Market prices for electricity are particularly volatile due to the inability to store electricity in large quantities (requiring it to be used as it is produced), which can result in significant price fluctuations based on supply and demand imbalances in the day-ahead and real-time markets. Because natural gas facilities often serve as the marginal, price-setting generating units, there is a strong positive correlation between the price of natural gas and the wholesale market price of electricity in the competitive power markets in which we operate. In recent years, the market price of natural gas has experienced substantial volatility, while prices for other fuels have also varied. Our energy margin is influenced by the relationship between the prices of electricity and natural gas and, to a lesser extent, other fuels like coal and uranium. A decline, or significant volatility, in the price of natural gas or other fuels could negatively impact energy margin and energy revenues.

Additionally, we purchase some of our fuel and other consumables such as water, lime, limestone, and other chemicals and sorbents on a short-term or spot market basis. Delivery of these products to our facilities depends on available transportation infrastructure and available shipping capacity. In certain market conditions, transportation costs to our facilities may be significant and fluctuate substantially. Accordingly, as the prices for our fuels, other consumables, and transportation fluctuate, the price we can obtain for the sale of electricity may not rise similarly or at all to match any increase in our costs. Any inability to obtain supply or delivery of necessary fuel or other products could impair our ability to operate our facilities profitably or at all.

Our business is subject to physical, market, economic, and regulatory risks relating to weather conditions and extreme weather events.

Because weather can influence actual and expected electricity demand, as well as current and future prices of electricity and fuel, mild or unexpected weather conditions could have an adverse effect on our business. Our operations are substantially concentrated in PJM, where sustained cold weather during the winter and sustained hot weather during the summer generally result in increased market demand and higher prices for electricity. Conversely, mild winter or summer temperatures in the Mid-Atlantic tend to suppress electric demand and may result in lower overall settled prices that reduce our energy margin. Additionally, extreme weather events or sustained mild weather could result in market conditions that generate substantial gains or losses. For example, certain market and operating conditions may require us to purchase electricity in the wholesale market during periods of unusually high prices to meet our supply obligations or to sell electricity in the wholesale market during periods of low prices.

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

Furthermore, under PJM’s Capacity Performance model, we may be (and have in the past been) subject to substantial monetary penalties for failing to meet the Capacity Performance requirements set forth by PJM in certain emergency events, including extreme weather events. See also “—Commercial and Operational Risks—We may experience unplanned interruptions or periods of reduced output, which could result in lower energy margin, lost opportunities, monetary penalties, contractual damages, and (or) other losses.” Extreme weather events could also result (and in the past have resulted) in governmental investigations and changes in applicable laws and regulations, reliability requirements, and market rules, including efforts to reform PJM. See also “—Regulatory, Environmental, and Legal Risks—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.” and “—Regulatory, Environmental, and Legal Risks—We may be affected by changes in applicable laws and regulations.”

Expected demand growth from the technology sector, manufacturing, and other uses of electricity, which has driven recent improvements in the outlook for the competitive wholesale power generation market, may not actually occur or be sustained.

Recently, the market outlook for competitive wholesale power generation has improved largely based on expected future demand from several sources, including data centers and other technology sector requirements, re-shoring of manufacturing in the U.S., the electrification of industry, and other demand drivers. Various factors including but not limited to unfavorable macroeconomic conditions, increases in energy efficiency or supply, or advances in technology, could result in lower-than-expected electricity demand and unfavorable market conditions for our business. A general economic slowdown or recession, a downturn in technology, manufacturing, or other sectors, an oversupply of generation resources or natural gas, or various other economic conditions could reduce electricity demand and prices. Improvements in energy efficiency, conservation efforts, and demand-side power management technologies, as well as other shifts in energy consumption, may reduce demand or slow demand growth. Furthermore, the penetration of renewable generation resources has, and may continue to have, negative effects on wholesale power prices and the economics of dispatchable generation units. Advances in technology may also provide alternative methods to produce, dispatch, and store power, which could also lead to increased overall electricity supply. Any of these factors could impact the dispatch, capacity factors, and value of our generation facilities.

We face intense competition in the competitive power generation market.

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

Our business is subject to extensive regulation, which may increase our costs, reduce our revenues, or limit operation of our facilities.

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

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

Instability and unrest, as well as war, other armed conflicts, economic sanctions, acts of terrorism, or threats thereof may lead to economic disruption that could adversely affect our business through high volatility in fuel and other commodity prices, difficulty obtaining products such as nuclear fuel, disruptions in supply chains, disruptions or volatility in financial markets, or other factors. In addition, we could be adversely affected by an epidemic, an infectious disease outbreak, or other public health events, which could impact our workforce and the availability of other resources, resulting in decreased service levels and increased costs. Furthermore, as a significant portion of our power generation facilities are geographically concentrated in the mid-Atlantic area of the United States, we face increased risk that a natural or man-made disaster in that area could adversely affect a large part of our operations.

We are also subject to cyber-based security disruption and integrity risk, which could result in an adverse impact to our results of operations or business reputation. The operation of our business relies on cyber-based technologies and is, therefore, subject to the risk that such systems could be the target of disruptive actions, particularly through cyberattack or cyberintrusion by hackers, foreign governments, state-sponsored actors, or cyberterrorists. Our cyber-based systems and technologies may otherwise also be compromised by unintentional errors or other events, including by vendors or third-parties. As a result, operations could be interrupted or impacted, property or other assets damaged, funds misappropriated, security compromised, or employee or third-party information lost or stolen, causing us to incur significant revenue losses, costs to replace or repair equipment, and other liabilities and damages, including regulatory actions, litigation, or reputational harm. In addition, we may also incur increased capital and operating costs to implement increased cybersecurity systems and protections throughout our business.

Commercial and Operational Risks

Operation of power generation facilities involves significant risks and hazards customary to the power industry, which we cannot assure our insurance will be adequate to cover.

Power generation involves hazardous activities, including transporting, storing and handling fuel, operating industrial, electrical and other equipment, and connecting to high voltage transmission and distribution systems. As a result, our assets, 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 damage or destruction of our assets or other property and equipment, personal injury or loss of life, pollution or environmental damage, and (or) suspension of operations, and any such event may expose us to liability for substantial damages, fines, or penalties. Although we maintain insurance that we believe is reasonable and prudent under the circumstances to cover our operations and assets, we cannot provide any assurance that our insurance program will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. See also “Item 1. Business—Our Operations—Insurance.” Even if we do have coverage for a particular incident, we may be subject to deductibles, caps, and (or) policy limits, and the amount recoverable under applicable insurance may not fully cover the impacts on our revenue or other potential consequences. Furthermore, due to rising insurance costs and changes in the insurance markets, we cannot provide any assurance that our insurance coverage will continue to be available at economic rates or at all.

Our activities related to hedging and asset management may result in economic losses and (or) volatility in our financial results.

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

Additionally, our commercial risk management activities could contribute to significant volatility in our financial results. Commercial transactions with future delivery dates may meet certain accounting criteria requiring them to be carried on the balance sheet at fair value. The “mark-to-market” effect, or remeasurement of these transactions to fair value at current market prices, is generally recognized in earnings through contract delivery. However, many commercial transactions with future delivery dates do not meet the criteria for “mark-to-market” accounting, and the income effect of these transactions is generally recognized at contract delivery. Accordingly, we are exposed to timing differences in the earnings recognition for commercial contracts with the same delivery date. As a result, during periods of extreme price volatility or significant changes in market prices, our quarterly and annual results may be subject to fluctuations due to changes in fair values of commercial transactions caused by changes in market prices.

We may experience unplanned interruptions or periods of reduced output, which could result in lower energy margin, lost opportunities, monetary penalties, contractual damages, and (or) other losses.

Our facilities require periodic planned outages to perform maintenance and repair activities, which are typically scheduled during seasonal non-peak demand periods to minimize their financial impacts to our business. However, our facilities may also experience unplanned outages, periods of reduced output, or other interruptions due to a number of factors, including but not limited to equipment failures, accidents, electrical delivery or transportation problems, fuel supply disruptions, acts of nature, environmental incidents, security or information technology breaches, labor disputes, intentional attacks, obsolescence, or below-expected performance. Any unexpected failure, including those associated with breakdowns or forced outages, could result in reduced profitability, including from lost energy margin, costs to cover power at then-current market prices to satisfy our commitments, and additional repair and (or) ongoing maintenance costs. Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that our insurance coverage will be sufficient to fully compensate us for any such losses.

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

Because our generation facilities are part of interconnected regional grids, we face the risk of congestion and other interruptions that could impact our operations.

Our operations depend on transmission and distribution facilities owned and operated by RTOs, ISOs, and other unaffiliated parties to transmit and deliver the electricity that we produce. 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 power may be materially affected. Electric power blackouts are possible, have occurred, and can disrupt electrical service for extended periods of time, which could result in interruptions to our operations, increased costs to replace existing contractual obligations, possible regulatory investigations, and potential operational risks to our facilities. Furthermore, transmission constraints and outages, including line maintenance outages, can cause transmission congestion that negatively impacts energy prices at our facilities, which could affect the realized margins of our generation fleet. The rates for transmission capacity from our facilities are set by others and thus are subject to changes outside of our control, some of which could be significant.

Our ownership and operation of Susquehanna subjects us to substantial risks associated with nuclear generation.

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 significant, including loss of life, destruction of property, and environmental damage. Because Susquehanna accounts for a substantial amount of our generation and associated earnings, any adverse development in Susquehanna’s operations, such as an unplanned outage or catastrophic event, could have a significant impact on our business. The risks and uncertainties associated with our nuclear generation include, among other things:

• impairment of reactor operation and safety systems, unscheduled outages or unexpected costs due to equipment, mechanical, structural, or other problems, inadequacy or lapses in maintenance protocols, human error, or force majeure;
• costs and liabilities relating to the procurement, safeguarding, storage, handling, treatment, transport, release, use, and disposal of nuclear fuel and other radioactive materials, including the costs of storing and maintaining SNF at our on-site dry cask storage facility;
• potential impacts of natural disasters, terrorist or other attacks, cybersecurity threats and (or) cyber-related attacks, or other unforeseen events, and the costs of preventing, preparing for, and responding to any such events;
• limitations on the amounts and types of insurance coverage commercially available;
• the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives;
• extensive regulation associated with ownership and operation of nuclear facilities (see also “—Regulatory, Environmental, and Legal Risks—Our ownership and operation of a nuclear power facility subjects us to regulations, costs, and liabilities uniquely associated with these types of facilities.”); and
• uncertainties surrounding public perception of nuclear generation, as well as the potential for a serious incident at Susquehanna or another nuclear facility, which could adversely affect the demand for nuclear power and could lead to increased regulation of the nuclear power industry.

The frequency and duration of outages affect Susquehanna’s availability. If future refueling outages last longer than anticipated or Susquehanna experiences unplanned outages, our business could be adversely affected. In addition, a significant operational disruption at Susquehanna could impair our ability to meet our PJM Capacity Performance requirements and our obligations under long-term power supply contracts, including under the AWS PPA. See also “—We may experience unplanned interruptions or periods of reduced output, which could result in lower energy margin, lost opportunities, monetary penalties, contractual damages, and (or) other losses.”

In addition, the costs associated with the nuclear fuel cycle are substantial, and suppliers of 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. Furthermore, 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. See Note 12 to the Annual Financial Statements for additional information on SNF.

Our commercial and operational activities may constrain our liquidity or require excessive levels of financial support.

Many of our commercial counterparties require us to provide credit support in the form of guarantees, LCs, security interests, netting arrangements, and (or) cash collateral. Because we are required to collateralize hedges that settle in future delivery periods, but do not receive settlements for electric generation until delivery, collateral requirements could result in periods of lower available liquidity. Furthermore, significant movements in market prices may require us to provide cash collateral or LCs in very large amounts (for instance, as happened prior to the Restructuring). The effectiveness of our commercial strategy may be dependent on the amount of collateral available to support our hedging arrangements, and these collateral requirements may be greater than we anticipate or are able to meet. Without sufficient working capital or borrowing capacity, we may not be successful in managing market and price risks. Our ability to increase liquidity could be limited by the terms of our debt or other agreements, unwillingness of financing sources to extend us credit or other capital, overall financial market conditions, or other factors. As a result, we could be required to liquidate commercial positions at significant losses to mitigate collateral requirements.

From time-to-time in the ordinary course of our business, we are also required to provide financial assurance to third parties for the performance of certain obligations. This may include guarantees, stand-by LCs issued by financial institutions, surety bonds issued by insurance or surety companies, and indemnifications. Some of these assurance products may limit our available liquidity by requiring collateralization, reducing available borrowings under our credit facilities, or utilizing available basket capacity under our debt agreements. In addition, surety bond providers generally are under no obligation to provide sureties on commercial terms or at all and, upon certain events, have the right to request additional collateral or require replacement of their bonds by alternate surety providers. Among others, we currently have surety bonds posted to the State of Montana on behalf of our proportional share of remediation and closure activities at Colstrip and LCs posted to AWS to support our obligations under the AWS PPA. Any draw down on these or other financial assurances in an event of default could adversely affect our financial position and liquidity, credit ratings, and compliance with our debt agreements and other contractual obligations.

We are exposed to credit risk, concentrations of credit risk, and counterparty risk from RTOs and ISOs, other customers, commercial counterparties, financial institutions, suppliers, and other parties.

In the ordinary course of our business, we are subject to the risk of losses from nonpayment by our contractual counterparties, including RTOs/ISOs, PPA counterparties, other customers, commercial counterparties, and other parties to whom we supply certain products or services, as well as by other market participants whose defaults could indirectly impact our business. Although we have established policies and procedures to evaluate and manage counterparty credit risk, they may not be adequate to identify fully or manage these risks effectively. Furthermore, we cannot predict the impact to our business from any decline in economic conditions, including any deterioration in the creditworthiness of customers and hedging counterparties. Any increase in counterparty nonpayment or nonperformance could require 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 5 to the Annual Financial Statements for additional information.

We purchase fuel, other required consumables, equipment and parts, and other critical products from a number of suppliers. We also enter into service contracts relating to critical operational and maintenance activities. Continued delivery of vital supplies and equipment and performance of vital services is dependent upon the continuing viability of our contractual counterparties. If our suppliers, service providers, or other counterparties fail to perform their obligations to us, we may be forced to suspend or curtail operations, enter into alternative arrangements on less favorable terms, or incur coverage costs, penalties, or other losses. See also “—We may experience unplanned interruptions or periods of reduced output, which could result in lower energy margin, lost opportunities, monetary penalties, contractual damages, and (or) other losses.”

Completed, pending, and potential retirements of our coal assets could result in additional costs and adverse effects on our operating results.

Since 2016, we have retired three economically nonviable coal-fired units, while our remaining coal-fired generation assets continue to be impacted by changing environmental regulations and power market economics. Although we recently reached a settlement agreement for the continued RMR operation of our Brandon Shores (a coal asset) and H.A. Wagner (formerly a coal asset, now operating primarily on fuel oil) facilities through May 2029, we do not currently anticipate that those assets will run beyond that date unless PJM continues to require their operation to maintain grid reliability. In addition, although our Brunner Island facility has been converted and can now run on either coal or natural gas, it remains a legacy coal facility with associated remediation obligations. We likewise have remaining liabilities associated with historical coal-fired generation at other legacy sites. We also own minority interests in three additional coal-fired facilities, including the Colstrip facility in Montana, of which we are the operator. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Forecasted Uses of Cash—Projected ARO and Accrued Environmental Liability Cash Flows” and Note 12 to the Annual Financial Statements for additional information on environmental remediation obligations. In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of capital, internal resources, and time to complete the required closure and reclamation.

The carrying value of our property, plant and equipment is subject to impairment charges.

PP&E used in operations is assessed for impairment whenever changes in facts and circumstances indicate that the carrying amount of a particular asset 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 market conditions or regulatory environment, we could experience future generation facility impairments.

Because we are minority owners in certain of our generation facilities, we cannot exercise complete control over their businesses or operations and are exposed to business, operational, and financial risks associated with co-owners.

We have limited control over the ownership and, in some cases, operation of our jointly-owned facilities. We own minority interests in the Conemaugh and Keystone generation facilities, which are operated by other co-owners, and in the Colstrip facility, which we operate. See Note 10 to the Annual Financial Statements for additional information on jointly owned facilities. While we seek to influence the business and affairs of these facilities, either by serving as operator (i.e., Colstrip) or negotiating certain management, information, or governance rights, we may not always succeed in doing so. We often depend on our co-owners to fulfill obligations important to the success of these joint operations, such as funding their share of capital and operating costs and, in the case of Conemaugh and Keystone, operating the facilities, and their ability to meet these obligations is outside our control. Our co-owners may not have the level of experience, technical expertise, human resources, and other attributes necessary to operate these projects optimally. Moreover, some of our co-owners, including rate-regulated utilities, may have economic incentives and obligations significantly different than ours. If our current or future co-owners are unwilling or unable to meet their obligations under our joint ownership arrangements, the performance, success, and value of these arrangements may be adversely affected. Furthermore, we (as a joint owner) may be forced to undertake the obligations ourselves or incur additional expenses as a result. In such cases, we may also be required to enforce our rights, which may cause disputes among us and our co-owners. Any of these events could adversely impact us, our joint operations, or our ability to enter into future joint operations.

Our success depends on our ability to attract and retain an appropriately qualified workforce.

Our ability to attract and retain key employees is important to both our operational and financial performance. We cannot guarantee that any member of our leadership or workforce will continue to serve in any capacity for any particular period of time. We could have difficulty retaining certain key members of management beyond May 2026, when a significant portion of our outstanding long-term equity-based incentive compensation is scheduled to vest. Furthermore, an aging workforce with significant retirement eligibility, mismatch of skill set, expectation of future needs, uncertainty around the future of our aging assets, or unavailability of short-term contract employees or contractors may lead to difficulty retaining our workforce, operating challenges, and increased costs. Additional challenges we could face include a lack of human resources, losses to our operational knowledge base, and the required time and other resources needed to develop new workers’ skills. In particular, our operations at Susquehanna largely depend on highly specialized personnel whose absence may adversely impact our ability to operate. We are also subject to the risk of organized actions by unionized employees which, as of December 31, 2024, represented approximately 43% of our workforce. If we are unable to negotiate future collective bargaining agreements on favorable terms, or if our union employees were to engage in strikes, work stoppages, slowdowns, or other forms of labor disruption, we would be responsible for obtaining replacement labor and could experience increased costs, reduced power generation, outages, other operational disruptions, or reputational harm.

We could be affected by increases in our labor and benefit expenses, including healthcare and pension costs.

We expect to continue facing increased cost pressures in our operations due to increased labor costs resulting from heightened inflation, the need for higher-cost expertise in the workforce, and other factors. In addition, we are required under collective bargaining agreements to provide specified levels of healthcare and pension benefits to certain current employees and retirees, and we provide similar benefits to our non-union employees. Due to general inflation in costs, the aging demographics of our workforce, healthcare cost trends, and other factors, we expect our healthcare costs, including prescription drug coverage, to continue increasing despite measures we have taken to reduce them.

As of December 31, 2024, our defined benefit pension plans, which cover certain of our retirees and employees, were underfunded by an estimated $291 million, with a total benefit liability of an estimated $1.2 billion, and we expect to continue incurring significant costs under these plans. 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 be significantly higher than anticipated. 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. Under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), the Pension Benefit Guaranty Corporation (“PBGC”) can petition a court to terminate an underfunded defined benefit pension plan under limited circumstances. In the event our pension plans are terminated by the PBGC, we could be liable to the PBGC for the entire amount of the underfunding, as calculated by the PBGC based on its own assumptions (which may result in a significantly larger liability than the assumptions used for financial reporting purposes or in determining the annual funding requirements for the plans).

Acquisitions, divestitures, mergers, or other corporate transactions may expose us to additional risks.

From time to time, we may seek to acquire additional assets or businesses, which is subject to risks including delay or the inability to achieve completion; the failure to identify material problems during due diligence accurately or at all; potential over-payment; the inability to retain acquired employees, customers, or suppliers; and the inability to obtain required or desired financing. We may also acquire assets or businesses beyond our current geographies, markets, or lines of business, which could expose us to increased market, operational, or regulatory risks. There can be no assurance that any acquired assets or businesses will be integrated or perform as expected, provide the anticipated returns, support any related financing obligations, or generate the cash flows needed to operate them profitably. In addition, we may from time to time choose to divest certain assets or businesses, which is subject to risks relating to employment matters; customers, suppliers, and other counterparties; other stakeholders in the disposed business; separation of the disposed assets from our remaining business; management of our ongoing business; failure to realize the anticipated benefits; other financial, legal, and operational risks; and other risks unknown to us at the time. In connection with dispositions, we may also indemnify or guarantee counterparties against certain conditions or liabilities, which could result in disputes, litigation, and (or) future costs or liabilities to us. In addition, any disposition would likely decrease our earnings and cash flows.

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

Regulatory, Environmental, and Legal Risks

Our business is subject to extensive energy-related regulation and oversight.

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

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

In addition to federal regulation, our operations are subject to various state laws and regulations. These include oversight of siting, permitting, and environmental compliance for our facilities, as well as participation in state-specific energy markets and programs. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. See also “—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.”

Our business is subject to extensive state, federal, and local statutes, rules, regulations, and permitting requirements relating to environmental protection and worker health and safety, which could limit our operations, increase our costs, result in other liabilities to us, or render continued operation of certain of our facilities uneconomic.

Our business is subject to extensive federal, state, and local laws, regulations, and requirements relating to environmental protection and human health and safety, which have become more stringent over time. These requirements impose, among other things, permitting requirements for regulated activities, costs to limit or prevent pollution or other contamination, substantial liabilities and remedial obligations for pollution or contamination, and specific standards addressing worker protection and process safety. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters—Environmental Regulation.”

We are required to obtain and to comply with numerous permits, approvals, licenses, and certificates from various environmental agencies, which can be a lengthy and complex process that can sometimes result in permit conditions that make certain activities overly restrictive or uneconomic. Moreover, renewal of existing permits could be denied or jeopardized by various factors, including litigation, environmentalist or community opposition, and political pressures. Costs, conditions, denials or non-renewals, or non-compliance associated with any required permits or approvals could result in increased costs; the cessation, suspension, delay, or limitation of our operations; premature unit retirements; and monetary penalties, increased compliance obligations, or other types of sanctions.

Furthermore, certain of our operations pose risks of liability due to leakage, migration, emissions, releases, or spills of hazardous or otherwise regulated 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 to remediate and restore sites. In addition, claims for personal or property damage 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 facilities, regardless of whether we were responsible for the creation of the environmental condition, it arose from the activities of predecessors or third parties, or our operations met previous industry standards at the time conducted.

New or more stringent enforcement of existing laws or regulations could also adversely affect our business. See also “—We may be affected by changes in applicable laws and regulations.” As a result of various factors, including existing and recently revised rules and regulations, such as those pertaining to air, waste, and water (including the EPA MATS, GHG, CCR, and ELG Rules) we have spent, and expect to continue to spend, substantial amounts on environmental compliance, controls, and remediation. See “Item 1. Business—Legal, Regulatory, and Environmental Matters—Environmental Regulation” and Note 12 to the Annual Financial Statements for additional information. Failure to comply with applicable environmental laws, regulations, and permits could result in liability for administrative, civil, or criminal fines or penalties or in other 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 and seek damages for non-compliance. These factors have also resulted in continuing uncertainty around the environmental costs, profitability, and continued operations of our fossil fuel-fired facilities, and coal-fired facilities in particular. See also “—There is uncertainty related to the future profitability of our fossil fuel-fired power generation business and the amount and timing of associated environmental costs.” and “—Existing and emerging legal and regulatory requirements related to coal-fired generation operations and CCR could adversely affect our business.”

We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.

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

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, as well as the forward markets in which we sell capacity, and may impose offer caps, price limitations, and other mechanisms to guard against the potential exercise of market power. These and other regulatory mechanisms may adversely affect our profitability. Changes in the rules, market operations, or geographic scope of existing RTOs, ISOs, and various regional power markets, as well as any challenges in the formation and operation of similar emerging market structures, could also affect our ability to sell, the prices we receive, or the costs to transmit electricity and capacity from our generation facilities.

The wholesale energy markets vary from region to region with distinct rules, practices, and procedures. Changes in these market rules, problems with rule implementation, and compliance or failure of any of these markets could adversely impact our business. The PJM market is undergoing significant restructuring due to projected increases in demand, projected retirements of supply, and recent weather events that have exposed systemic flaws. Ongoing market reforms have caused delays in the PJM Base Residual Auctions, which determine capacity prices in upcoming years, leading to unpredictability around capacity revenues due to lack of reliable pricing and on-schedule BRAs. While PJM has established dates for certain upcoming PJM BRAs based upon FERC orders establishing rules for such capacity markets, we cannot guarantee those auctions will take place on those dates or at all. In addition, under PJM’s Capacity Performance model, we may be (and have in the past been) subject to substantial monetary penalties for failing to meet the Capacity Performance requirements set forth by PJM in certain emergency events. Continued efforts to address perceived capacity market design issues are ongoing, and we cannot predict the outcome of these market reforms or their impact on future capacity revenues. See Note 12 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, BRA delays, and related legal actions.

Our power generation business relies on a competitive marketplace. See also “—Industry and Market Risks—We face intense competition in the competitive power generation market.” The competitive wholesale marketplace may be undermined by changes in market structure as well as the actions of federal or state entities that interfere in the competitive marketplace, such as subsidies, out-of-market payments, incentives, or bailouts to new or uneconomic facilities; imports of power; permission for regulated utilities to build generation and add it to the rate base; renewable mandates or incentives; and mandates to sell power below cost. Actions that undermine the competitive marketplace could suppress capacity and energy prices or lead to premature retirement of existing facilities, among other things. See also “—We may be affected by changes in applicable laws and regulations.”

There is uncertainty related to the future profitability of our fossil fuel-fired power generation business and the amount and timing of associated environmental costs.

Many political and regulatory authorities, environmental groups, and investors are devoting substantial efforts to minimizing or eliminating fossil fuel-fired electricity generation, which could reduce demand and pricing for electricity generated at our fossil fuel-fired facilities and adversely impact our business, financial condition, growth prospects, and ability to raise capital. See also “—Financial and Equity Risks—We may not have sufficient access to financing for our business.”

These efforts are resulting in increased regulation of fossil fuel combustion, GHG emissions, and other related activities. Any resulting changes to the legal and regulatory framework governing electric generation could materially impact our business. For example, new air, waste, and water rules finalized by the EPA in 2024 could require us to incur significant costs if they withstand legal challenges and potential rescission or revision by the Trump administration. These costs include ARO revisions, potential asset modifications, including investments in environmental control equipment, premature retirement or reduced operations, and increased public reporting requirements. See “Item 1. Business—Legal, Regulatory, and Environmental Matters—Environmental Regulation” and Note 12 to the Annual Financial Statements for additional information. Furthermore, any new legislation or regulatory programs could also increase the cost of electricity production or make certain units unavailable or restricted, overall reducing the amount of reliable and affordable power available to meet our nation’s growing electricity demand.

For example, compliance with the recently revised EPA MATS Rule will require either investment in additional control equipment at Colstrip or retirement of the plant by 2027. We and the other Colstrip co-owners have not yet determined whether to install the equipment necessary to comply with the new EPA MATS Rule; meanwhile, we and others are actively challenging the EPA MATS Rule in ongoing litigation as well as advocating for changes administratively. Furthermore, if we and our co-owners elect to install additional control equipment at Colstrip, the recently revised EPA GHG Rule could still force the plant to retire by 2032, before the costs of installing the equipment can be recovered. We operate an aging fossil fuel 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 or premature retirement. However, the EPA MATS, GHG, CCR, and ELG Rules are currently subject to ongoing litigation. As a result, future implementation and enforcement of these rules remains uncertain. To the extent that new or amended laws or regulations further restrict emissions from the combustion of coal, natural gas, or oil, such requirements could result in further capital expenditures or premature retirements.

Existing and emerging legal and regulatory requirements related to coal-fired generation operations and CCR could adversely affect our business.

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 and Brunner Island have significant decommissioning and environmental remediation liabilities, primarily consisting of remediation, closure, and decommissioning costs for coal ash impoundments. Where applicable, across the fleet, we carry the expected cost of the known CCR and associated wastewater obligations within our ARO liabilities. Actual cash expenditures associated with these AROs are expected to materially increase over the next five years due to recent regulatory changes unless the rules do not withstand legal challenges or are rescinded by the Trump administration. These potential increases would be somewhat offset by ongoing remediation, closure, and decommissioning activities, which will reduce ARO liabilities as scopes are completed. See Note 12 to the Annual Financial Statements for additional information. Future adjustments to our coal ash ARO estimates may be required due to evolving regulatory programs and associated remediation requirements under federal rules and state obligations, which could have an adverse effect on our business. If the assumptions underlying these ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different. See Note 11 to the Annual Financial Statements for additional information on AROs.

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

Our ownership and operation of a nuclear power facility subjects us to regulations, costs, and liabilities uniquely associated with these types of facilities.

Under the Atomic Energy Act, our operation and 90% ownership of Susquehanna are subject to regulation by the NRC, including requirements pertaining to, among other matters: licensing, inspection, and enforcement; testing, evaluation, and modification of all aspects of nuclear reactor power generation facility design and operation; environmental and safety performance; handling and storage of SNF; technical and financial qualifications; decommissioning funding assurance; and transfer and foreign ownership restrictions. The NRC may modify, suspend, or revoke operating licenses and impose civil or criminal penalties for failure to comply with the Atomic Energy Act or the terms of nuclear operating licenses. The current facility operating licenses for our two units at Susquehanna expire in 2042 and 2044.

The NRC could temporarily or permanently shut down Susquehanna, require it to modify its operations, or refuse to permit a unit to restart after any planned or unplanned outage. See also “—Commercial and Operational Risks—We may experience unplanned interruptions or periods of reduced output, which could result in lower energy margin, lost opportunities, monetary penalties, contractual damages, and (or) other losses.” As a result of any shutdown or forced outage, we may also face 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 Department of Energy continues to fail to meet its contractual obligations under the Nuclear Waste Policy Act of 1982 to accept and dispose of Susquehanna’s SNF. See Note 12 to the Annual Financial Statements for additional information on this obligation. 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 NDT funds. See Note 9 to the Annual Financial Statements for additional information on the NDT.

In addition, new or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures, and 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. See also “—Commercial and Operational Risks—Our ownership and operation of Susquehanna subjects us to substantial risks associated with nuclear generation.”

While Susquehanna maintains property and liability insurance and is subject to NRC insurance requirements and the Price-Anderson Act scheme, there may be limitations on the amounts and types of insurance commercially available to us or we may have insufficient coverage with respect to any losses. See Note 12 to the Annual Financial Statements for additional information on nuclear insurance. Uninsured losses and other liabilities and expenses resulting from an incident at Susquehanna, to the extent not recovered from insurers or the nuclear industry, could be borne by us. See also “—Industry and Market Risks—Operation of power generation facilities involves significant risks and hazards customary to the power industry, which we cannot assure our insurance will be adequate to cover.” Additionally, an accident or other significant event at a nuclear facility within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. If an incident did occur at Susquehanna, any resulting operational loss, damages, and injuries would likely have a material adverse effect on our business.

We may be affected by changes in applicable laws and regulations.

Our business is subject to various laws and regulations administered by federal, state, and local governmental agencies. Changes in laws and regulations occur frequently, and sometimes dramatically, as a result of political, economic, or social events or in response to other significant events, and changes in state laws and regulations could be even less predictable, occur more rapidly, or have a more drastic effect than changes at the federal level. 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 policies designed to promote reductions in energy consumption, increased energy efficiency, renewable energy, and self-generation by customers. In addition, extreme weather events have resulted, and in the future may result, in governmental investigations and changes in applicable laws and regulations, reliability requirements, and market rules, including efforts to reform PJM. In the future, we are 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 change in the legal and regulatory landscape for any reason (including but not limited to changes in administration or political climate, energy regulation and policy, environmental and permitting requirements and processes, employee healthcare and benefits obligations, health and safety standards, accounting standards, tax regulations and requirements, and competition laws) could impact our operations, competitive position, or outlook. See “Item 1. Business—Legal, Regulatory, and Environmental Matters—Environmental Regulation” and Note 12 to the Annual Financial Statements for additional information on new water, waste, air, and climate rules recently finalized by the EPA.

The availability and cost of emission allowances could negatively impact our operating costs.

We are required to maintain, through either allocations or purchases, sufficient emission allowances for sulfur dioxide, nitrogen oxide, and carbon dioxide to support the operation of our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws and regulations. 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 increased emissions. If our operational needs require more than our allocated or otherwise acquired allowances, we may be forced to purchase additional allowances on the open market, which could be costly, if available at all. If we are unable to maintain sufficient emission allowances to match our operational needs, we may be required to curtail our operations or install costly new emission controls. In addition, laws and regulations governing emission allowance programs are changing and could continue to change in the future, which could have a negative impact on available allowances, our ability to purchase allowances, or the price of additional allowances. See Note 12 to the Annual Financial Statements for additional information on the EPA CSAPR and nitrogen oxides requirements.

Changes in tax law (including any elimination of the Nuclear PTC), the implementation regulations of certain tax provisions, adverse decisions by tax authorities, or the imposition of tariffs may adversely affect our business.

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

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 our results of operations. This could result in a material and adverse effect on our consolidated income tax provision, financial position, and net income/loss for the period for which such determinations are made.

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

As of December 31, 2024, we had $0.8 billion of U.S. federal net operating loss carryforwards and $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). 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.

We are subject to the risk of litigation and similar legal proceedings.

We are, and in the future may be, subject to litigation or similar legal proceedings arising out of our business and operations. Damages or other remedies sought under such proceedings may be financially or operationally material, and a negative outcome could materially adversely impact our business, operations, and financial condition. While we will assess the merits of any legal proceedings and defend such matters accordingly, we may be required to incur significant expense and (or) devote significant management attention to such defenses. In addition, the adverse publicity surrounding such claims may negatively impact our business and reputation. Our insurance may not adequately cover losses for damages claimed against us, and we do not have insurance coverage for all litigation risks. See Note 12 to the Annual Financial Statements for additional information on our legal matters.

Financial and Equity Risks

We may not have sufficient access to financing for our business.

Our primary liquidity requirements, in addition to our ordinary course operating expenses, are for debt service, capital expenditures, and collateral for our commercial program and AROs. If our liquidity sources are not sufficient to fund our current or future 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, which could result in a higher cost of capital and (or) require additional security, collateral, or other conditions. Our ability to raise capital and access liquidity is subject to numerous factors, including conditions in the capital markets, our current operations, credit ratings, and other events which we may not be able to predict or control. Furthermore, our ability to raise financing may be affected by current geopolitical-social views and investor expectations regarding fossil fuels and environmental matters, which have prompted unfavorable lending policies toward fossil fuel-fired generation facilities, guidelines preventing investors from increasing or taking new stakes in companies with exposure to fossil fuels, and divestment efforts affecting the investment community, all of which could negatively impact the demand for investments in our business. Applicable regulations could also impose additional requirements that may increase the costs of conducting our business or accessing 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, in compliance with the terms of our existing indebtedness, and (or) in a manner that does not negatively impact our business or that such actions, even if achieved, would allow us to meet our financial obligations and operating requirements.

Our historical financial information may not be indicative of our future financial performance.

Our capital structure was significantly altered in the Restructuring. 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. We also adopted accounting policy changes that could result in material changes to our financial reporting and results. Accordingly, our financial condition and results of operations in Successor periods following the Restructuring are not comparable to our financial condition and results of operations in Predecessor periods prior to the Restructuring. See Notes 2 and 4 to the Audited Financial Statements for additional information on accounting policies and fresh start accounting.

The amount and terms of our indebtedness could adversely affect our financial condition and impair our ability to operate our business.

Our indebtedness could have important consequences to our future financial condition, operating results, and business, including: requiring that a substantial portion of our cash flows from operations be dedicated to payments on our indebtedness instead of operations, capital expenditures, future business opportunities, or other purposes; limiting our ability to obtain additional debt or equity financing for working capital, capital expenditures, debt service requirements, acquisitions, and general corporate or other purposes; increasing our cost of borrowing; and (or) limiting our ability to adjust to changing market and economic conditions and to carry out capital spending that is important to our business.

Our borrowings under the Credit Facilities incur interest at variable interest rates that expose us to interest rate risk. If interest rates increase, our debt service requirements would increase even though the amount borrowed remains the same. Furthermore, although the agreements governing our current 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. If the principal or interest of our indebtedness were to increase, our ability to meet our debt service, operational, and other financial requirements may be adversely impacted. See also “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”

In addition, the agreements governing our indebtedness contain covenants that limit our ability to, among other things: incur additional debt and liens; redeem and (or) prepay certain debt; pay dividends or repurchase stock; make certain investments; consolidate, merge, lease, or transfer all or substantially all of our assets; and enter into transactions with affiliates. These restrictions could harm our business by, among other things, limiting our ability to obtain other financing, to operate our business, and (or) to take advantage of mergers, acquisitions, or other corporate opportunities. Furthermore, various risks, uncertainties, and events beyond our control could affect our ability to comply with these covenants which could, among other things, result in events of default/cross-default under these agreements and permit lenders to accelerate amounts due and foreclose upon collateral. Any of these events could adversely affect our financial condition and results of operations and (or) cause us to become bankrupt or insolvent.

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 TES’s indebtedness contain certain restrictions on distributions to TEC.

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

We may not pay any dividends on our common stock in the future.

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; our capital requirements; market conditions; our growth strategy and the availability of growth opportunities; our level of indebtedness, contractual provisions, and other restrictions on our payment of dividends (including those imposed by the agreements governing our indebtedness); applicable law; and other factors that the Board of Directors deems relevant. See also “—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 TES’s indebtedness contain certain restrictions on distributions to TEC.”

A number of factors could adversely affect the market price or trading volume of our common stock, even if our business is doing well, including but not limited to substantial sales of our common stock by existing stockholders, future issuances of equity or debt securities by us, and (or) research or reports published by financial analysts.

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

In the future, we may attempt to obtain financing or increase capital by issuing additional shares of our common stock or by offering debt or other equity securities. The issuance of equity securities or securities convertible into equity may dilute the value of our existing stockholders’ equity. Convertible securities could also be subject to conversion ratio adjustments pursuant to which certain events may increase the ultimate number of issuable equity securities. Any debt financing could involve covenants limiting our financial, operational, and strategic flexibility, make it more difficult for us to obtain additional capital, and (or) result in additional financial obligations to which our stockholders are structurally subordinated.

In addition, the trading market for our common stock is affected by information that industry and financial analysts publish about our business. If analysts cease coverage of us, or if they publish unfavorable or inaccurate information about us, the market price and trading volume of our common stock could be negatively impacted. There are many large, active companies established in our industry, and we could receive less favorable or widespread coverage than our competitors. If one or more analysts cease coverage of us, our common stock may lose visibility in the market. Furthermore, if one or more analysts downgrades their evaluations of our business, common stock, or indebtedness, the price of our common stock could decline. There can be no assurance that analysts will continue to cover our business or that any such coverage will be favorable or accurate.

Stockholders may have a limited ability to influence our business and affairs due to a number of factors.

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

Additionally, our organizational documents contain provisions that could act to discourage, delay, or prevent a change in control or change of management of TEC that stockholders may deem advantageous. These provisions, among other things: authorize the Board of Directors to issue “blank check” preferred stock; require prior written consent of the Board of Directors for certain transfers (except for secondary market purchases) that would result in 10% or greater ownership of our outstanding voting securities; prohibit stockholder action by written consent unless signed by holders having at least the minimum voting power of all outstanding shares entitled to vote thereon; permit the Board of Directors to establish its number of members; eliminate the ability of stockholders to fill vacancies on the Board of Directors; authorize the Board of Directors to make, amend, or repeal our Bylaws; require advance notice for director nominations and other stockholder annual meeting proposals; and designate the Delaware Court of Chancery as the exclusive forum for certain types of stockholder actions. See the Description of Capital Stock included as Exhibit 4.1 to this Report for additional information.

All of these factors could significantly limit the ability of certain stockholders to influence our business and affairs and, in turn, depress the market price of our common stock, including through the influence of larger stockholders, discouraging proxy contests, and making it more difficult to elect directors or cause us to take other corporate actions. These factors could also make it more difficult for a third party to acquire us (even if considered beneficial by many of our stockholders) and, as a result, our stockholders may have a more limited ability to obtain a premium for their shares of common stock.

The requirements of being a public company may require significant resources, and we may be unable to comply with these requirements in a timely or cost-effective manner.

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

In particular, the internal controls and procedures required for public company financial reporting under Section 404 of the Sarbanes-Oxley Act are significantly more stringent than those required for a private company. Fully implementing our internal control framework and testing will require significant resources, and management may not be able to timely and effectively implement the necessary controls and procedures. At any time, we may conclude that our internal controls, once tested, are not operating as designed or do not address all relevant financial reporting risks. In addition, once required to attest to control effectiveness, our independent registered public accounting firm may issue a report concluding that our internal controls over financial reporting are not effective. If we identify material weaknesses in the future or otherwise fail to implement or maintain effective internal controls over financial reporting, we may not be able to accurately or timely comply with our financial reporting obligations, which may subject us to adverse regulatory consequences, negatively affect our business, harm investor confidence, and (or) reduce the market price of our common stock.

We maintain policies and controls designed to identify, assess, manage, mitigate, protect against, and respond to cybersecurity threats. Our cybersecurity risk management strategy is established by management and is implemented by our IT professionals and the business units in which potential threats may occur. The Audit Committee of our Board of Directors (the “Audit Committee”) has primary responsibility for overseeing management’s strategy related to mitigating risk associated with cybersecurity threats. We maintain: (i) business continuity and disaster recovery plans that are expected to be deployed in response to a significant cyberattack; (ii) cyber incident response plans; and (iii) cybersecurity insurance that, subject to policy coverage and limitations, protects against financial harm to the Company caused by material cybersecurity events. While we believe our cybersecurity risk management strategy is appropriate for our current business, no strategy can fully protect against all possible adverse events. See “Item 1A. Risk Factors—Industry and Market Risks—Our business could be adversely affected by events outside of our control, including armed conflicts, war, terrorist attacks or threats, pandemics, natural disasters, cyber-based attacks, or other significant events.”

Cybersecurity and Risk Mitigation

Our cybersecurity policies are guided by standards or recommendations issued by, among others, the National Institute of Standards and Technology, the International Organization for Standardization, the NRC, and NERC. We deploy, configure, and maintain technologies and procedures designed to enforce security policies, detect and protect against cybersecurity threats, and help safeguard our material assets.

Our digital and cybersecurity controls are augmented with physical controls such as security systems, security site plans, security systems monitoring, and access control to mitigate physical security risks at our facilities. Our procurement policies and organizational controls require certain vendors to be assessed and vetted, with enhanced protocols on purchases and installations involving nuclear equipment. Additionally, cybersecurity reviews are performed on critical intellectual property vendors. Additionally, where warranted, we request a detailed cybersecurity questionnaire from our vendors to assess the vendor's practices and preparedness in addressing cyber threats.

Through a multi-functional coordinated effort, we assess and mitigate cybersecurity risks across our business units based on likelihood of the risk and potential impact to the business unit, the Company, and our stakeholders. These risks are identified using tactical, operational, and compliance-based approaches. Risks and associated consequences, should they materialize, are evaluated using likelihood of occurrence considering existing controls and technologies.

Our employees, as well as certain contractors, are required to complete cybersecurity awareness and training programs. Mandatory technical training is provided to employees and vendors performing, verifying, or managing cybersecurity activities. Mitigation efforts also include annual cyber crisis response simulations and annual training.

Third parties conduct periodic assessments on our cyber-related systems. To measure our non-nuclear cybersecurity framework maturity, we utilize internal and external audits and assessments, vulnerability testing, and governance processes. Our nuclear cybersecurity program is inspected biennially by the NRC and assessed annually by a quality assurance audit. Nuclear vulnerability management is implemented in collaboration with Department of Homeland Security and the Cybersecurity and Infrastructure Security Agency.

We have cyber incident response plans to manage significant cybersecurity incidents across different aspects of our operations. Cybersecurity incidents are escalated based on significance to our Chief Administrative Officer, Chief Nuclear Officer, Chief Fossil Officer, General Counsel, Chief Financial Officer, Chief Executive Officer, Audit Committee, and (or) Board of Directors.

Cybersecurity Governance

The Audit Committee oversees our cybersecurity risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Periodic reports are given by senior management to the Audit Committee about material cyber events and our risk mitigation efforts.

Our senior executive team is responsible for the coordination of cybersecurity across the Company. Our cybersecurity teams, which include employees with appropriate professional certifications, are responsible for assessing and managing our cyber risk management protocols in their respective areas. These activities include the prevention, detection, mitigation, and remediation of material cybersecurity incidents as well as communicating risk management matters to key stakeholders. The cybersecurity teams have experience selecting, deploying, and operating cybersecurity technologies, initiatives, and processes, and rely on threat intelligence as well as other information obtained from governmental, public, or private sources. In coordination with our senior management, the relevant cybersecurity teams review risk management strategies to mitigate cybersecurity risks. Additionally, as needed, we engage specialists, consultants, auditors, and (or) other third parties to assist with assessing, identifying, and managing cybersecurity risks.

While cybersecurity incidents have not materially affected the Company or our business strategy, results of operations, or financial condition to date, no assurance can be provided that we will not be subject to a significant cybersecurity incident in the future. See “Item 1A. Risk Factors—Industry and Market Risks—Our business could be adversely affected by events outside of our control, including armed conflicts, war, terrorist attacks or threats, pandemics, natural disasters, cyber-based attacks, or other significant events.” for additional information on our cybersecurity risks.

GENERATION FLEET AS OF DECEMBER 31, 2024

(a) Generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions, which may be subject to revision.

(b) See Note 10 to the Annual Financial Statements for additional information on jointly owned facilities.

(c) Coal-fired electric generation is restricted during the EPA Ozone Season, which is May 1 to September 30 of each year.

(d) Coal-fired electric generation is required to cease at Brunner Island, Keystone, and Conemaugh by December 2028.

(e) See Note 10 to the Annual Financial Statements for additional information on the Brandon Shores and H.A. Wagner deactivations and RMR proceedings.

Susquehanna ISA Amendment. Under a prior, FERC-accepted ISA between PJM, Susquehanna, and a subsidiary of PPL Corporation (“PPL”) (collectively, the “ISA Parties”), Susquehanna is permitted to decrease by up to 300 MW the amount of power supply that it would otherwise provide to the power grid within PPL’s service area. Susquehanna currently provides that power to load via load-owned transmission directly connected to Susquehanna rather than supplying load from the power grid. In June 2024, PJM filed at FERC an Amended Interconnection Service Agreement (the “Susquehanna ISA Amendment”) executed between the ISA Parties permitting Susquehanna to decrease by up to 480 MW the amount of power supply that it would otherwise provide to the power grid and now intends to sell to AWS instead. PJM previously concluded such increase in the amount of withheld power would have no reliability impacts on the grid. In June 2024, despite the Susquehanna ISA Amendment being applicable solely to the PPL service area, Exelon Corporation (“Exelon”) and AEP filed a protest to the Susquehanna ISA Amendment at FERC and raised generic issues involving the direct connection of load service to generators. FERC responded by issuing a deficiency letter in August 2024 seeking more information about the arrangement described in the Susquehanna ISA Amendment and separately setting a Technical Conference for November 2024 to discuss broader issues related to (i) co-located load connected directly to generation; and (ii) emerging reliability issues resulting from the dramatic rise in data center demand for power. In September 2024, PJM provided a response to FERC’s August 2024 deficiency letter on the Susquehanna ISA Amendment and filed a Construction Service Agreement between the ISA Parties and Mid-Atlantic Interstate Transmission, LLC to facilitate certain network upgrades to ultimately accommodate a 960 MW decrease of power supply to the grid. Talen filed its own comments in September 2024 and written testimony in the FERC Technical Conference proceeding in October 2024. Shortly after the conclusion of the FERC Technical Conference in November 2024, FERC issued a 2-1 decision rejecting the Susquehanna ISA Amendment and Talen filed a motion for a rehearing of the FERC order within the 30-day deadline for such motions. In December, FERC issued an order stating that it would address the request for rehearing in a future order, which FERC has not yet issued. Due to FERC’s decision not to address the merits of the motion for rehearing, Talen has filed an appeal in the U.S. Court of Appeals for the Fifth Circuit.

The prior FERC-accepted ISA between the ISA Parties permitting Susquehanna to decrease 300 MW of its current power supply from the power grid remains in place and facilitates the initial sale of power to AWS under the AWS PPA. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.”

We are evaluating our commercial and legal options to provide the most efficient path to full development of the AWS Data Campus. Such options include, but are not limited to, potential submission of a revised form of Susquehanna ISA Amendment or alternative contract structures with AWS. If the Company is unable commercially or legally to resolve the Susquehanna ISA Amendment approval impediments and realize the full development of the AWS Data Campus, there may be a material impact on our future results of operations, and (or) financial condition.

Separate and apart from the Susquehanna ISA proceeding, there are three other pending proceedings before FERC that could shape policy around co-located load, and thus impact the result of the Susquehanna ISA proceeding. First, in August 2024, Exelon made a series of filings on behalf of each of its electric utility subsidiaries to amend portions of the PJM tariff that would clarify that co-located load arrangements must be categorized as either network load or point-to-point service (the “Exelon 205 proceeding”). In effect, the proposed amendments intended to clarify that co-located load arrangements would be treated as either needing network or point-to-point service, making them subject to the same transmission charges and fees for transmission-related services that would be applicable if the same load had located at other points on the PJM grid. Exelon requested a December 2, 2024 effective date, but in November 2024, FERC issued a deficiency letter stating that FERC required more information to make a determination. Second, in November 2024, FERC held a technical conference on co-located load to discuss, among other things, the impacts of various co-location agreements, whether and how large co-located loads receive wholesale market services or benefits from the transmission system, the cost and impact of back-up services for large co-located load and state regulatory and policy issues (the “Co-Location Technical Conference proceeding”). Following the technical conference, FERC requested comments be filed by December 9, 2024. Talen both participated in the technical conference and filed comments. Third, in November 2024, Constellation filed a complaint at FERC alleging that PJM’s tariff is unjust and unreasonable because it is silent on how to treat fully isolated co-located load (the “Constellation 206 proceeding”). The complaint suggests that FERC import into the tariff certain terms and conditions from a non-binding guidance document PJM shared with stakeholders or set the proceeding for settlement discussions on an expedited basis with a mediator.

On February 20, 2025, FERC denied relief in the Exelon 205 proceeding and initiated a new Section 206 proceeding directing PJM to show cause within 30 days why its tariff is just and reasonable in light of potential discrimination around the treatment of co-located load or, in the alternative, to propose changes to its tariff to address the treatment of co-located load (the “Co-Located Load PJM Tariff proceeding”). The order initiating the Co-Located Load PJM Tariff proceeding consolidated the records and proceedings from the Co-Location Technical Conference and Constellation 206 proceedings into the Co-Located Load PJM Tariff proceeding, which will all be considered together by FERC. The order also established a timeline for comments to PJM’s to-be filed showing or proposed tariff revisions (30 days after PJM’s filing) and a tentative timeline for FERC to rule on the matter in the second half of 2025. The Company intends to be an active participant in the PJM and FERC process to revise PJM’s tariff.

See Note 12 to the Annual Financial Statements for information about other material legal proceedings to which we are subject.

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

Recent Developments

Common Stock Transactions

Share Repurchases. During the year ended December 31, 2024 (Successor), we repurchased and retired a total of 13,227,222 shares, or approximately 22%, of TEC’s outstanding common stock through a combination of the SRP and direct repurchases from affiliates of Rubric Capital Management LP (collectively, “Rubric”). A total of: (i) 7,307,300 shares were purchased from Rubric; (ii) 5,275,862 shares through a tender offer; and (iii) 644,060 shares in the open market. The aggregate purchase price after transaction fees and excise tax was approximately $2.0 billion at a weighted average price of $149.50 per share. As of December 31, 2024 (Successor), the remaining capacity under the SRP is approximately $1.1 billion through 2026.

See Note 18 to the Annual Financial Statements for additional information on the SRP, other share repurchases, and other common stock transactions.

Financing Transactions

Secured Notes Consent. In January 2025, we received consents from noteholders representing a majority in principal amount of the Secured Notes to adopt certain amendments to the Indenture to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in the December 2024 transactions discussed below; and (ii) waive TES’s right to optionally redeem up to 10% of the Secured Notes at a price of 103% of par prior to June 1, 2025.

December 2024 Financing Activities. In December 2024, we completed several financing transactions that resulted in the: (i) issuance of $380 million in net additional long-term indebtedness through full repayment of the TLC utilizing restricted cash collateralizing the TLC and issuance of the TLB-2 (at an initial rate of SOFR + 2.5%); (ii) issuance of the new $900 million LCF and termination of the TLC LCF and Bilateral LCF, which had the combined effect of increasing our LC capacity by $355 million; and (iii) favorable repricing and covenant improvements on the existing TLB-1 and RCF (repriced to initial rates of SOFR + 2.5% and SOFR + 2.0%, respectively) as well an extension of the RCF maturity. The proceeds of the TLB-2 issuance were used, together with cash on hand, to repurchase shares of our outstanding common stock held by Rubric.

See Note 13 to the Annual Financial Statements for additional information on long-term debt, other credit facilities, and recent financing activities.

Power Transactions

AWS PPA. In connection with the AWS Data Campus Sale in 2024, we and AWS entered into the AWS PPA, pursuant to which we agreed to supply long-term, carbon-free power from Susquehanna to the AWS Data Campus through fixed-price power commitments. Under the AWS 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 AWS PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, we will receive additional revenue from AWS related to the sales of carbon-free energy to the grid. We expect to begin receiving initial revenues from power sales in 2025. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale.

Susquehanna ISA Amendment. In November 2024, FERC issued an order denying the Susquehanna ISA Amendment between PJM, PPL Corporation, and Susquehanna that would permit Susquehanna to decrease the amount of power supply it would otherwise provide to the power grid. Such order does not have an impact on the existing ISA permitting 300 MW of co-located load at Susquehanna to supply power for the first phases of the AWS Data Campus. In December 2024, FERC issued an order stating that it would address our request for rehearing in a future order, which FERC has not yet issued. Due to FERC’s decision not to address the merits of our motion for rehearing, we have filed an appeal in the U.S. Court of Appeals for the Fifth Circuit. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.” See “Item 3. Legal Proceedings” and “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—Our business is subject to extensive energy-related regulation and oversight.” for additional information on the Susquehanna ISA Amendment.

Brandon Shores and H.A Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules. If approved, the proposed RMR arrangements will extend the operating life of these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. See Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement and the related impairment of the Brandon Shores asset group.

Factors Affecting Our Financial Condition and Results of Operations

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,” and Notes 5 and 12 to the Annual Financial Statements for additional information on our risks.

Commodity Markets

During 2024, natural gas prices for Texas Eastern M-3 settled below their ten-year average as a result of natural gas storage levels above the five-year average and abundant natural gas supplies. In PJM, periodic below average temperatures during the winter and above average temperatures during the summer contributed to increased load demand that resulted in higher annual settled on-peak power prices compared with the prior year.

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

As of December 31, 2024 (Successor), the weighted average forward market prices for the following years were:

(a) Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

As of December 31, 2023 (Successor), the weighted average forward market prices for the following years were:

(a) Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

(b) Represents forward prices for 2024 as of December 31, 2023 (Successor). See weighted average settled prices table above for 2024 realized prices.

Capacity Markets

Our generation capacity is located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, RTO/ISO demand forecasts, reserve margin targets, and (in PJM) adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.

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

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

(a) Displayed prices are from the applicable market publications.

For the 2025/2026 Capacity Year, we cleared a total of 6,820 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas.

Capacity Performance Event. As a result of Winter Storm Elliott in December 2022, PJM experienced extreme cold weather conditions that resulted in PJM’s declaration of a Capacity Performance event requiring generators to operate at their maximum output capacity. Certain of our generation facilities failed to meet PJM’s Capacity Performance requirements while others met or exceeded their obligations. As a result, we incurred final aggregate net Capacity Performance penalties of $29 million, which were remitted during the period from May 18 through December 31, 2023 (Successor) and the period from January 1 through May 17, 2023 (Predecessor). See Note 12 to the Annual Financial Statements for additional information.

Nuclear Production Tax Credit

The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $43.75/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $25/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. See Notes 6 and 7 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the Inflation Reduction Act.

Seasonality/Scheduled Maintenance

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

Results of Operations

The results of operations presented below should be reviewed in conjunction with the Annual Financial Statements and the related notes. Our financial results for the year ended December 31, 2024 (Successor) and for the period from May 18 through December 31, 2023 (Successor) are referred to as the “Successor” periods. Our financial results for the period from January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor) are referred to as the “Predecessor” periods. The operating results for the Successor Periods are not comparable with the operating results for the Predecessor Periods due to the application of fresh start accounting after Emergence in May 2023. See Notes 2, 3, and 4 to the Annual Financial Statements for additional information regarding the Restructuring and related accounting. Our results of operations as reported in 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 and other revenues” relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, 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 derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy Expenses” in the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.

Results for the Year Ended December 31, 2024 (Successor), the Period from May 18 through December 31, 2023 (Successor), the Period from January 1 through May 17, 2023 (Predecessor), and the Year Ended December 31, 2022 (Predecessor)

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

35

Successor Period — Year Ended December 31, 2024

Net Income (Loss) Attributable to Stockholders totaled $998 million for the year ended December 31, 2024 (Successor). Results were driven by:

• Capacity Revenues totaled $192 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM BRAs for the 2023/2024 and 2024/2025 PJM Capacity Years.
• Energy and Other Revenues, net of Fuel and Energy Purchases totaled $1.2 billion. This consisted of: (i) $1.3 billion in third-party wholesale electricity sales and ancillary revenues; (ii) $325 million in other revenue primarily related to Nuclear PTC and Bitcoin revenue; and (iii) $230 million in net realized gains from hedging activities. Such amounts were partially offset by $(659) million in fuel and purchased power costs.
• Unrealized Gain (Loss) on Derivative Instruments totaled $62 million gain, net. This consisted of: (i) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period; and (ii) unrealized gains incurred as a result of decreases in forward power prices.
• Nuclear Fuel Amortization totaled $(123) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $33 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.
• Operation, Maintenance and Development totaled $(592) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
• Depreciation, Amortization and Accretion totaled $(298) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
• Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $178 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
• Interest Expense and Other Finance Charges totaled $(238) million. This primarily consisted of interest expense incurred on the Secured Notes, TLB-1, and TLB-2.
• Gain (Loss) on Sale of Assets, net totaled $884 million. This primarily consisted of the $564 million gain from the ERCOT Sale that closed in May 2024 and the $324 million gain from the AWS Data Campus Sale that closed in March 2024. See Note 20 to the Annual Financial Statements for additional information.
• Other Non-Operating Income (Expense), net totaled $61 million. This primarily consisted of interest income on cash deposits.
• Income Tax Benefit (Expense) totaled $(98) million. This primarily related to federal and state tax expense on pre-tax income, the release of the federal and state valuation allowance, and the exclusion of Nuclear PTC income as a permanent item.

Successor Period — May 18 through December 31, 2023

Net Income (Loss) Attributable to Stockholders totaled $134 million for the period from May 18 through December 31, 2023 (Successor). Results were driven by:

• Capacity Revenues totaled $133 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRA for the 2023/2024 PJM Capacity Year. Capacity revenues were positively impacted by $19 million as a result of the FERC-approved settlement agreement for net PJM Capacity Performance penalties assessed related to Winter Storm Elliot. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.
• Energy and Other Revenues, net of Fuel and Energy Purchases totaled $732 million. This consisted of: (i) $950 million in third-party wholesale electricity sales and ancillary revenues; (ii) $81 million in Bitcoin revenue; and (iii) $33 million in net realized gains from hedging activities. Such amounts were partially offset by $(332) million in fuel and purchased power costs.
• Unrealized Gain (Loss) on Derivative Instruments totaled $52 million gain, net. This consisted of unrealized gains incurred as a result of decreases in forward power prices; and (ii) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
• Nuclear Fuel Amortization totaled $(108) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $53 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.
• Operation, Maintenance and Development totaled $(358) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
• Depreciation, Amortization and Accretion totaled $(165) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
• Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $108 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
• Interest Expense and Other Finance Charges totaled $(176) million. This primarily consisted of interest expense incurred on the Secured Notes and TLB-1.
• Other Non-Operating Income (Expense), net totaled $95 million. This primarily consisted of the gain on the PPL/Talen Montana litigation settlement. See Note 12 to the Annual Financial Statements for additional information.
• Income Tax Benefit (Expense) totaled $(51) million. This primarily related to federal and state tax expense on pre-tax income and changes in the valuation allowance. See Note 7 to the Annual Financial Statements for additional information.

Predecessor Period — January 1 through May 17, 2023

Net Income (Loss) Attributable to Member totaled $479 million for the period from January 1 through May 17, 2023 (Predecessor). Results were driven by:

• Capacity Revenues totaled $108 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRA for the 2022/2023 PJM Capacity Year. Capacity revenues were negatively impacted by $(13) million of net PJM Capacity Performance penalties related to Winter Storm Elliott. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.
• Energy and Other Revenues, net of Fuel and Energy Purchases totaled $866 million. This consisted of: (i) $637 million in net realized gains from hedging activities; (ii) $343 million in third-party wholesale electricity sales and ancillary revenues; and (iii) $27 million in Bitcoin revenue. Such amounts were partially offset by $(141) million in fuel and purchased power costs.
• Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million loss, net. This consisted of unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period, partially offset by unrealized gains incurred as a result of decreases in forward power prices.
• Nuclear Fuel Amortization totaled $(33) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E.
• Operation, Maintenance and Development totaled $(285) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
• Depreciation, Amortization and Accretion totaled $(200) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
• Impairments totaled $(381) million. This consisted of the assessment of Brandon Shores asset group recoverability associated with a decision to deactivate Brandon Shores on June 1, 2025. See Note 10 to the Annual Financial Statements for additional information.
• Other Operating Income (Expense), net totaled $(37) million. This primarily consisted of non-cash charges for fuel inventory net realizable value adjustments. See Note 8 to the Annual Financial Statements for additional information.
• Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $57 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
• Interest Expense and Other Finance Charges totaled $(163) million. This primarily consisted of interest expense incurred on prepetition indebtedness of TES and the LMBE-MC TLB and certain LC fees.
• Reorganization Income (Expense), net totaled $799 million. This primarily consisted of: (i) a $1.5 billion gain on debt discharge recognized upon Emergence, partially offset by a $(460) million loss on revaluation adjustments; (ii) $(70) million in backstop commitment letters; (iii) $(84) million in professional fees; (iv) and $(46) million for the write-off of the carrying value of prepetition debt issuance costs. See Note 2 to the Annual Financial Statements for additional information.
• Gain (loss) on Sale of Assets, net totaled $50 million. This primarily consisted of gains due to non-recurring sales during the period. See Note 20 to the Annual Financial Statements for additional information.
• Income Tax Benefit (Expense) totaled $(212) million. This primarily related to federal and state tax expense on pre-tax income, reorganization adjustments, and changes in the valuation allowance. See Note 7 to the Annual Financial Statements for additional information.

Predecessor Period — Year Ended December 31, 2022

Net Income (Loss) Attributable to Member totaled $(1.3) billion for the year ended December 31, 2022 (Predecessor). Results were driven by:

• Capacity Revenues totaled $377 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRAs for the 2021/2022 and 2022/2023 PJM Capacity Years. Capacity revenues were negatively impacted by $33 million of net PJM Capacity Performance penalties related to Winter Storm Elliott. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.
• Energy and Other Revenues, net of Fuel and Energy Purchases totaled $1.1 billion. This consisted of: (i) $2.8 billion in third-party wholesale electricity sales and ancillary revenues; (ii) $(513) million in net realized losses from hedging activities; and (iii) $(157) million in losses incurred on early terminated commodity contracts. Such amounts were partially offset by $(1.1) billion in fuel and purchased power costs.
• Unrealized Gain (Loss) on Derivative Instruments totaled $625 million gain, net. This consisted of unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period, coupled with unrealized gains incurred as a result of decreases in forward power prices.
• Nuclear Fuel Amortization totaled $(94) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E.
• Operation, Maintenance and Development totaled $(610) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
• Depreciation, Amortization and Accretion totaled $(520) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
• Operational Restructuring totaled $(488) million. This consisted of: (i) a $(453) million loss resulting from charges related to retail power contracts in the PJM market that were rejected in connection with the Reorganization; and (ii) a $(35) million loss primarily due to charges related to long-term service agreements in the ERCOT market that were rejected in connection with the Reorganization.
• Other Operating Income (Expense), net totaled $(40) million. This primarily consisted of: (i) $(17) million of expenses related to environmental liability revisions in the PJM market; and (ii) $(18) million for the estimated costs of a legal settlement.
• Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $(184) million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
• Interest Expense and Other Finance Charges totaled $(359) million. This primarily consisted of interest expense incurred on prepetition indebtedness of TES and the LMBE-MC TLB and certain LC fees.
• Reorganization Income (Expense), net totaled $(812) million. This consisted of (i) $(310) million in backstop commitment letter premium; (ii) $(210) million for professional fees related to the Restructuring; (iii) $(183) million for make-whole premiums and accrued interest on certain indebtedness; (iv) $(70) million for professional fees incurred to obtain the debtor-in-possession credit agreements; and (v) $(30) million for the write-off of the carrying value of prepetition debt issuance costs.
• Consolidation of Subsidiary Gain (Loss) totaled $(170) million. This consisted of losses recognized from the consolidation of Cumulus Digital due to a change of control.
• Other Non-Operating Income (Expense), net totaled $(44) million. This primarily consisted of non-recurring corporate professional fees associated with liability and other management initiatives.
• Income Tax Benefit (Expense) totaled $35 million. This primarily related to federal and state tax benefit on pre-tax loss, changes in the valuation allowance, and non-deductible transaction costs.

Liquidity and Capital Resources

Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our hedging activities including cash collateral and other forms of credit support; (v) legacy environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.

Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.

Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, we now have lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) and significantly reduced debt service requirements following the Restructuring and subsequent refinancing transactions.

We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.

See the following Notes to the Annual Financial Statements for additional information on liquidity topics discussed below: Note 5 for derivatives and hedging, Note 11 for AROs and environmental obligations, Note 13 for long-term debt and credit facilities, and Note 19 for supplemental cash flow information.

Liquidity and Letter of Credit Capacity

(a) As of December 31, 2024 (Successor), all RCF committed capacity can be used for direct cash borrowings and (or) LCs. As of December 31, 2023 (Successor). All RCF committed capacity could be used for direct cash borrowings and up to $475 million of such capacity could be used for LCs.

(b) Excludes LC capacity available under the RCF. Includes (i) LC capacity under the LCF as of December 31, 2024 (Successor); and (ii) aggregate LC capacity under the TLC LCF and Bilateral LCF as of December 31, 2023 (Successor).

Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 13 to the Annual Financial Statements for additional information on the RCF and the issuance of the LCF and termination of the TLC LCF and Bilateral LCF in December 2024.

Guarantees and Other Assurances

Guarantees of Subsidiary Obligations. TES guarantees certain agreements and obligations for its subsidiaries. Certain agreements may contingently require payments to a guaranteed or indemnified party. See Note 12 to the Annual Financial Statements for additional information on guarantees.

Financial Performance Assurances. TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including but not limited to environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.

Forecasted Uses of Cash

Capital Expenditures. Capital expenditure plans are revised periodically for changes in operational needs, market conditions, regulatory requirements, and cost projections. Accordingly, the expected cash requirements for capital expenditures are subject to revision.

(a) Expected capitalized interest on capital expenditures is a non-material amount in 2025 and 2026.

Projected ARO and Accrued Environmental Liability Cash Flows. Certain of our subsidiaries have legal obligations to perform significant decommissioning and remediation activities associated with current operations and (or) at former generation facility sites. Our projected undiscounted spending on AROs and environmental liabilities is presented in the table below. The majority of the estimated non-nuclear spend is related to ash impoundments at Colstrip and Brunner Island. Beginning in 2025, we expect to increase our remediation spend associated with our obligations at Colstrip. The carrying value of these obligations includes certain assumptions, including a rate of inflation of 2.50%. Projections are subject to revision based on changes in estimated inflation rates, changes in the estimated timing of settling AROs, and escalating retirement costs. Susquehanna’s AROs are expected to be settled with funds available from the NDT at the time of decommissioning. See Note 11 to the Annual Financial Statements for additional information.

As of December 31, 2024 (Successor), the expected undiscounted payments are estimated to be:

(a) Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.

Indebtedness. See Note 13 to the Annual Financial Statements and “—Recent Developments—Financing Transactions” above for additional information on our indebtedness.

Cash Flow Activities

The net cash provided by (used in) operating, investing, and financing activities for the periods were:

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Successor Period — Year Ended December 31, 2024

• Operating Cash Flows. Cash provided by operating activities totaled $256 million.
• Investing Cash Flows. Cash provided by investing activities totaled $1.2 billion. This primarily consisted of $635 million of proceeds from the AWS Data Campus Sale and $763 million of proceeds from the ERCOT Sale. Such amounts were partially offset by: (i) net NDT fund investments of $(32) million; and (ii) capital expenditures of $(189) million, which primarily consisted of $(104) million for nuclear fuel and $(85) million for PP&E. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale and the ERCOT Sale.
• Financing Cash Flows. Cash used in financing activities totaled $(2.0) billion. This primarily consisted of: (i) $(2.0) billion for share repurchases; (ii) $(479) million to repay the TLC; (iii) $(182) million for the repayment of the Cumulus Digital TLF; (iv) $(125) million for the repurchases of noncontrolling interests (a) in Cumulus Digital from affiliates of Orion Energy Partners and two former members of Talen senior management, and (b) in Nautilus from TeraWulf; and (v) $(32) million to settle vested restricted stock units in cash. Such amounts were partially offset by $849 million in proceeds from the issuance of new debt. See Notes 13 and 18 to the Annual Financial Statements and “—Recent Developments” above for additional information on debt transactions and share repurchases.

Successor Period — May 18 through December 31, 2023

• Operating Cash Flows. Cash provided by operating activities totaled $402 million. This primarily consisted of: (i) cash provided from operations; and (ii) the net receipt of $104 million related to the settlement of the PPL/Talen Montana litigation. See Note 12 to the Annual Financial Statements for additional information on the PPL/Talen Montana settlement.
• Investing Cash Flows. Cash used in investing activities totaled $(171) million. This primarily consisted of capital expenditures totaling $(161) million, which consisted of: (i) $(116) million for then-current projects, including the Montour gas conversion project and the AWS Data Campus; and (ii) $(45) million related to nuclear fuel expenditures, as we purchased uranium for needs in future periods.
• Financing Cash Flows. Cash used by financing activities totaled $(84) million. This primarily consisted of $(59) million for payments to former affiliates to settle warrants and to repurchase affiliates’ noncontrolling interests in Cumulus Digital.

Predecessor Period — January 1 through May 17, 2023

• Operating Cash Flows. Cash provided by operating activities totaled $462 million.
• Investing Cash Flows. Cash used in investing activities totaled $(157) million. This primarily consisted of capital expenditures totaling $(187) million, which consisted of: (i) $(138) million for then-current projects, including the Montour gas conversion project, the AWS Data Campus, the Nautilus cryptocurrency project, and projects at Susquehanna; and (ii) $(49) million related to nuclear fuel expenditures. Such amounts were offset by $46 million in proceeds from the sale of assets.
• Financing Cash Flows. Cash used in financing activities totaled $(539) million. This primarily consisted of the net effect of issuances and repayments of prepetition debt and make-whole premiums of about $(1.9) billion net cash outflow, partially offset by $1.4 billion cash inflow for a contribution from member.

Predecessor Period — Year Ended December 31, 2022

• Operating Cash Flows. Cash provided by operating activities totaled $187 million.
• Investing Cash Flows. Cash used in investing activities totaled $(368) million. This primarily consisted of: (i) capital expenditures totaling $(312) million, which consisted of: (a) $(232) million for then-current projects, including the Montour gas conversion project and projects at Susquehanna, and (b) $(80) million related to nuclear fuel expenditures; and (ii) $(162) million in equity investments in affiliates. Such amounts were offset by a $123 million increase to cash due to the consolidation of Cumulus Digital.
• Financing Cash Flows. Cash used in financing activities totaled $426 million. This primarily consisted of net proceeds from debtor-in-possession credit facilities of $987 million, after discount and debt issuance costs, partially offset by: (i) repayments on prepetition deferred capacity obligations and inventory repurchase obligations of $(341) million; (ii) $(104) million related to terminations of certain derivative contracts; (iii) $(59) million of deferred financing costs; and (iv) $(52) million related payments of the LMBE-MC TLB.

Non-GAAP Financial Measure

Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.

Adjusted EBITDA

We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.

Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.

Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.

The following table presents a reconciliation of the GAAP financial measure of “Net Income (Loss)” presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:

(a) See Note 4 to the Annual Financial Statements for additional information.

(b) See Note 20 to the Annual Financial Statements for additional information.

(c) See Note 10 to the Annual Financial Statements for additional information.

(d) See Note 12 to the Annual Financial Statements for additional information.

(e) The year ended December 31, 2024 (Successor) primarily includes the effects of nonrecurring ERCOT hedge settlements that occurred after the ERCOT Sale and severance payments associated with cost reduction initiatives.

(f) The periods from May 18 through December 31, 2023 (Successor) and from January 1 through May 17, 2023 (Predecessor) include the effects of nonrecurring costs associated with exit from the Restructuring, severance costs associated with cost reduction initiatives, and nonrecurring post-Restructuring strategic initiative costs.

(g) The year ended December 31, 2022 (Predecessor) includes non-cash charges for retail contracts terminated in connection with the Restructuring. See Note 4 to the Annual Financial Statements for additional information.

(h) See Note 8 to the Annual Financial Statements for additional information.

Critical Accounting Policies and Estimates

Financial statements prepared in conformity with GAAP require the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i) the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to the inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. We believe the following areas contain the most significant accounting judgments, the highest levels of subjectivity, or relate to uncertain matters that are susceptible to material changes in estimates that are critical to understanding the Company’s financial results. Due to such inherent uncertainties, actual results may differ substantially from estimates and (or) estimates may change materially in periods where new information becomes known. Management develops these estimates based on best available information, historical experience, and subject matter experts. See Note 2 to the Annual Financial Statements for additional information on accounting policies for each of the following topics.

Derivative Instruments

Derivative instruments, which are deployed by our commercial organization to manage and (or) mitigate market and commodity price risk, are presented on the Consolidated Balance Sheets at fair value and are comprised primarily of power and natural gas commodity contracts. Derivative identification is challenging. While a conventional financially settled contract, such as a swap or option, generally contains standard terms that facilitate its identification as a derivative instrument, judgment is required to determine whether contracts to buy or sell commodities with physical delivery requirements or contracts that contain certain embedded settlement or fluctuating price features meet the definition of a derivative instrument. This judgment typically includes, among other things, an evaluation of the contract, its expected cash flows, and the activity levels of its principal market. Additionally, judgment is required to determine if a commodity contract intended for physical delivery meets an allowable exemption prior to accounting for its income effects under the accrual accounting method rather than at fair value. This typically includes assumptions regarding the probability of physical delivery and the quantities used in normal business activities.

As our derivative contracts generally settle within future time periods supportable by commodity exchange markets and the frequent occurrence of commercial transactions, the majority of our derivative contracts utilize quoted prices in active markets or other observable market inputs to determine fair value. However, such prices are subject to volatility between periods based on weather, local market events, macroeconomic trends, and (or) other events and factors. Accordingly, changes in fair value for contracts identified as derivatives may result in material changes to unrealized gains or losses presented on the Consolidated Statements of Operations between periods. Changes in fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments” as a component of either “Operating Revenues” or “Fuel and energy purchases” on the Consolidated Statements of Operations, in a consistent manner with the presentation of its realized net gains or losses.

See Note 5 to the Annual Financial Statements for additional information on derivative instruments.

Nuclear Decommissioning Asset Retirement Obligations

We have significant legal obligations associated with Susquehanna’s decommissioning. Susquehanna’s Unit 1 and Unit 2 licenses, if not renewed, will expire in 2042 and 2044, respectively, at or before which time the units will shut down.

Judgment is required to make reasonable ARO assumptions regarding the range of likely outcomes for cost estimates, as these obligations are not expected to be paid until years or decades in the future, and potentially many years after shutdown. Inflation rates and discount rates may be subject to revision until the ARO settlement date. As such, changes in assumptions to the range of likely outcomes could result in different cash outlay for AROs at the settlement date than the current carrying value of the ARO presented on the Consolidated Balance Sheets. Susquehanna periodically assesses its ARO through third-party engineering studies in order to determine expected scope, costs, and timing of decommissioning activities. Generally, its decommissioning cost study is updated approximately every seven years. As part of the cost study update process, we and the third-party engineering firm evaluate cost projections based on the latest engineering techniques and the latest information which incorporates nuclear plant retirements in the industry. We incorporate the results of the study as well as our experience, knowledge, and professional judgment to the specific characteristics of Susquehanna’s decommissioning plan to update the carrying value of the ARO.

AROs are recognized at fair value at the time of installation and as an increase to PP&E. The income effect of AROs is generally presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations through the expected ARO settlement date. However, for an asset that has a fully depreciated PP&E carrying value, revisions in ARO estimates have an immediate effect in earnings. Revisions to the estimated ARO are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.

See Note 11 to the Annual Financial Statements for additional information on AROs.

Recoverability of Long-Lived Assets

PP&E used in operations are assessed for impairment whenever changes in facts and circumstances indicate the carrying amount of the asset group may not be recoverable. Judgment is required to identify these events. In certain instances, the events could be external to us and may include, among other events, changes in the economic environment, such as a decrease in the market price of an asset, significant changes to market rules and regulations in the power markets in which we operate, and changes in federal or state environmental regulations that would materially affect the cash flows of our generation fleet. In other instances, the events result from negative financial trends, physical damage to assets, or decisions of management regarding strategic initiatives, such as sales of assets, generation facility retirements, or significant changes in planned capital expenditures or operating costs.

Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. There is significant judgment in identifying the lowest level of independent cash flows in the merchant power market, given that certain groups of our generation facilities participate in the same market. In determining the appropriate level of aggregation, we consider the manner in which we make economic decisions regarding the revenue and commercial activities of the generation facilities and the manner in which we make operational and maintenance decisions. Accordingly, we generally aggregate assets for impairment at the reporting unit level, unless there are additional facts and circumstances present which indicate that an asset should be tested for recoverability on a standalone basis. Periodically, we evaluate whether events such as changes in market conditions, regulatory changes, or other events require a change in aggregation.

If there is an indication that the carrying value of an asset group may not be recovered, we review the expected future cash flows of the asset group. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the asset group is written down to its estimated fair value. Fair value for PP&E may be determined by a variety of valuation methods, including third-party appraisals, market prices of similar assets, and present value techniques. However, as there is generally a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates that are believed to be consistent with those used by principal market participants. The estimated cash flows and related fair value computations consider all available evidence as of the date of the review, such as estimated future generation volumes, capacity prices, energy prices, operating costs, and capital expenditures.

Impairment charges are presented on the Consolidated Statements of Operations in the period in which the impairment determination is made.

See Note 10 to the Annual Financial Statements for additional information on recognized impairments.

Postretirement Benefit Obligations

Certain of our subsidiaries sponsor postemployment benefits that include defined benefit pension plans. Accounting for defined benefit pensions involves significant estimates to determine projected benefit obligations and company contribution requirements, which inherently require assumptions be made regarding many uncertainties. Such uncertainties include discount rates, expected return on assets, expected wages for participants at retirement, estimated retirement dates, and mortality rates. Over a period of time, we are required to fund all vested benefits for postretirement defined benefit pension plans through plan assets, investment returns, or contributions to the plans.

Actuarial assumptions required under GAAP to determine the projected benefit obligations and actuarial assumptions required under ERISA to determine contribution assumptions differ in their objectives. Actuarial assumptions regarding projected benefit obligations under GAAP affect the net periodic defined benefit cost presented within our Consolidated Statements of Operations. Actuarial assumptions used in the computation to estimate required contributions to the defined benefit plans affect funding requirements over a period of time.

We are responsible for the estimates regarding our postemployment benefits. However, we engage actuarial firms, who apply professional standards in the determination of the judgmental assumptions for plan contributions, to estimate both the contribution requirements for postemployment benefits and the associated projected benefit obligations under GAAP.

Projected benefit obligations are particularly sensitive to expected return on plan assets and the discount rate. The expected return on plan assets is the estimated long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs. The discount rate is used to compute the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. Please see Note 15 to the Annual Financial Statements for the weighted-average assumptions used for the discount rate and expected return on plan assets for all plans.

A variance in the discount rate or expected return on plan assets could have a significant impact on postretirement benefit obligations and annual net periodic pension costs. The following table displays the estimated increase (decrease) for defined benefit pension plans of a 1% increase and a 1% decrease in the discount rate and expected return on plan assets on the postretirement benefit obligation and net periodic pension cost as of December 31, 2024 (Successor).

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Income Taxes

Significant management estimates and judgments are involved to determine the provision for income taxes, deferred tax assets and liabilities, and valuation allowances.

An assessment is performed on a quarterly basis to determine the likelihood of realizing deferred tax assets. We assess the probability of realizing deferred tax assets by evaluating historical income after adjusting for certain nonrecurring items for purposes of projecting future income, our intent and ability to implement tax planning strategies, and performing scheduling of the reversal of temporary differences. We also evaluate negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate an inability to realize deferred tax assets. Based on the combined assessment, we recognize valuation allowances for deferred tax assets when it is more likely than not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, forecasted financial conditions, and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 7 to the Annual Financial Statements for additional information on income taxes.

Recent Accounting Pronouncements

See Note 2 to the Annual Financial Statements for a description of recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted.

The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.

Commodity Price Risk

Volatility in the wholesale power generation markets provides uncertainty in the future performance and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: seasonal changes in demand; weather conditions; available regional load-serving supply; regional transportation and (or) transmission availability; market liquidity; and federal, regional, and state regulations.

Within the parameters of our risk policy, we generally utilize conventional first lien, exchange-traded, and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.

Margin Sensitivities

The table below displays sensitivities for changes in projected margins based upon consistent changes in power prices across our entire portfolio. Actual price changes may differ by market and commodity, which could result in different results than displayed.

The base case for these sensitivities incorporates market prices, our economic hedge position, expected Nuclear PTC, and expected generation (including cost inputs and planned outages) as of December 31, 2024 (Successor):

(a) Margin price sensitivities hold constant certain microeconomic and macroeconomic factors that may impact our margin and the impact of changes in prices; value in millions and includes expected value of Nuclear PTC.

(b) Power price sensitivities hold market heat rate constant for each month; therefore, natural gas prices are adjusted accordingly.

Interest Rate Risk

We are exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.

The following table displays the net fair value of interest rate swaps (including accrued interest, if applicable) outstanding at December 31, 2024 (Successor):

(a) Effect of a 10% adverse interest rate movement decreases assets or increases liabilities, as applicable, which could result in an asset becoming a liability.

Additionally, we are exposed to a potential increase in interest expense and to changes in the fair value of debt. The estimated impact of a 10% adverse movement in interest rates were:

Credit Risk

Credit risk is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due, causing a financial loss to us. Financial assets are considered credit-impaired when facts and circumstances reasonably indicate an event has occurred where the carrying value of the asset will not be recovered through cash settlement. Such events may include deterioration of a customer’s or counterparty’s financial health leading to a probable bankruptcy or reorganization, a breach of contract, or other economic reasons. Credit risk may impact accounts receivable, derivative instruments, cash and cash equivalents, and restricted cash and cash equivalents. The maximum amount of credit exposure associated with financial assets is equal to the carrying value. The carrying values of derivative instruments consider the probability that a counterparty will default when contracts are out of the money (from the counterparty’s standpoint). Additionally, a credit impairment is recognized on receivables when facts indicate a high probability that amounts owed to us will not be paid. Such allowances are presented as part of “Accounts receivable” on the Consolidated Balance Sheets. As of December 31, 2024 (Successor) and December 31, 2023 (Successor), there were no material credit impairments.

We maintain credit procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit standards) and require other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, we have concentrations of 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 5 in the Annual Financial Statements for additional information on credit risk.

Investment Price Risk

In accordance with certain NRC requirements, we maintain trust funds comprised of restricted assets that were established in order to fund our proportional share of Susquehanna's future decommissioning obligations. As of December 31, 2024 (Successor), the NDT was invested primarily in domestic equity securities, fixed-rate, fixed-income securities, and short-term cash-equivalent securities and is presented as fair value on the Consolidated Balance Sheets. The mix of securities is intended to provide returns sufficient to fund our proportional share of Susquehanna's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the NDT are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates. We actively monitor the investment performance and periodically review the asset allocation in accordance with our nuclear decommissioning trust investment policy statement.

The following table shows the impact of a hypothetical 10% increase in interest rates and a 10% decrease in equity values:

See Notes 9 and 14 to the Annual Financial Statements for additional information regarding the NDT.

Disclosure Controls and Procedures

As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized, and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2024 (Successor).

Internal Control Over Financial Reporting

This Report does not include a report of management’s assessment regarding internal control over financial reporting or an attestation report of the Company’s registered public accounting firm due to a transition period established by rules of the SEC for newly public companies. These reports will be required and provided in our Annual Report on Form 10-K for the year ended December 31, 2025.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting that occurred during the year ended December 31, 2024 (Successor) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.