Talen Energy (NASDAQ: TLN) doubles down on PJM with AWS PPA and big gas deals
Filing Impact
Filing Sentiment
Form Type
10-K
Rhea-AI Filing Summary
Talen Energy Corporation files its annual report describing a 13.1 GW U.S. power portfolio anchored by 2.2 GW of nuclear capacity. The company emphasizes low- and zero-carbon baseload generation, including a 90% interest in the 2.5 GW Susquehanna nuclear facility, which produced about 17 TWh in 2025 at roughly $27 per MWh.
Talen highlights long-term contracted revenues, including an expanded AWS power purchase agreement for up to 1,920 MW of carbon-free nuclear power through 2042 and reliability-must-run contracts for its Brandon Shores and H.A. Wagner plants providing $145 million and $35 million in fixed annual payments starting June 2025. The report also details recent and pending acquisitions of efficient natural gas plants totaling about 5.3 GW for roughly $7.25 billion in aggregate consideration, funded largely with new senior notes and additional debt, along with clearing 8,745 MW in PJM’s 2027/2028 capacity auction at $333.44 per MW-day.
Positive
- Long-term contracted revenues: Expanded AWS PPA commits up to 1,920 MW of carbon-free nuclear power through 2042 at anticipated premium prices, adding durable, visible cash flows with minimum commitments and a ramp-up schedule potentially reaching full volume by 2032.
- Growth via large gas acquisitions: Closing the $3.8 billion Freedom and Guernsey Acquisitions and signing the $3.45 billion Cornerstone Merger Agreement adds roughly 5.3 GW of modern natural-gas generation, expanding scale and diversifying the fleet in attractive PJM markets.
- Stabilizing RMR contracts: Reliability-must-run arrangements for Brandon Shores and H.A. Wagner provide fixed annual payments of $145 million and $35 million, respectively, from June 2025 through May 2029 or until transmission upgrades are completed, supporting predictable earnings from previously coal-focused assets.
Negative
- Higher leverage and funding needs: Recent and pending acquisitions rely on significant new indebtedness, including $2.7 billion of senior unsecured notes and expected borrowings for the $2.55 billion cash portion of the Cornerstone Acquisition, increasing interest costs and balance-sheet risk if market conditions weaken.
- Concentrated regulatory and environmental exposure: The fleet faces extensive nuclear, PJM market, and environmental regulation, including contested EPA rules on greenhouse gases, coal combustion residuals, and effluent limits, which may drive additional compliance costs, operating constraints, or early unit retirements.
- Operational and nuclear-specific risks: Susquehanna’s central role in generation and in the AWS PPA heightens the impact of any unplanned outages, Capacity Performance penalties, fuel supply disruptions, or nuclear incidents, which could impair contracted deliveries and financial performance.
Insights
Talen is pivoting to long-term contracts and modern gas assets while deepening PJM exposure.
Talen describes a 13.1 GW fleet increasingly centered on low- and zero-carbon baseload, notably the Susquehanna nuclear plant. The expanded AWS PPA for up to 1,920 MW of carbon-free power through 2042 adds visibility to cash flows and reduces pure merchant exposure.
The company has already closed the $3.8 billion Freedom and Guernsey acquisitions and agreed to the $3.45 billion Cornerstone Acquisition, adding about 5.3 GW of efficient combined-cycle and peaking gas capacity in PJM and nearby regions. These assets are intended to support its “Talen flywheel” strategy of contracting large, high-quality loads and then adding more contractable capacity.
Funding relies heavily on new debt, including
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(Mark One)
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the fiscal year ended December 31 , 2025
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from __________ to __________
Commission File Number: 001-37388
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | ||||
(Address of principal executive offices) (Zip Code)
(888 ) 211-6011
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☒ | ☐ | Accelerated filer | ☐ | Non-accelerated filer | Smaller reporting company | Emerging growth company | |||||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐ No ☒
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant was approximately $13.3 billion as of June 30, 2025, the last business day of the registrant’s most recently completed second fiscal quarter, based on 45,659,227 shares then outstanding at the Nasdaq closing price of $290.77 per share.
As of February 26, 2026, the registrant had outstanding 45,695,007 shares of common stock, par value $0.001 per share (“common stock”).
Documents Incorporated by Reference
The information required pursuant to Part III of this Annual Report on Form 10-K will be set forth in, and incorporated by reference from, the registrant’s definitive proxy statement for the 2026 annual meeting of stockholders (the “2026 Proxy Statement”), which will be filed with the U.S. Securities and Exchange Commission not later than 120 days after the end of the fiscal year ended December 31, 2025.
TALEN ENERGY CORPORATION
ANNUAL REPORT ON FORM 10-K
TABLE OF CONTENTS
| Page | |||||||||||
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION | 1 | ||||||||||
MARKET AND INDUSTRY DATA | 1 | ||||||||||
PART I | 2 | ||||||||||
ITEM 1. | BUSINESS | 2 | |||||||||
ITEM 1A. | RISK FACTORS | 13 | |||||||||
ITEM 1B. | UNRESOLVED STAFF COMMENTS | 29 | |||||||||
ITEM 1C. | CYBERSECURITY | 29 | |||||||||
ITEM 2. | PROPERTIES | 31 | |||||||||
ITEM 3. | LEGAL PROCEEDINGS | 31 | |||||||||
ITEM 4. | MINE SAFETY DISCLOSURES | 32 | |||||||||
PART II | 32 | ||||||||||
ITEM 5. | MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS, AND ISSUER PURCHASES OF EQUITY SECURITIES | 32 | |||||||||
ITEM 6. | RESERVED | 33 | |||||||||
ITEM 7. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 33 | |||||||||
ITEM 7A. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 44 | |||||||||
ITEM 8. | FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA | 46 | |||||||||
ITEM 9. | CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE | 111 | |||||||||
ITEM 9A. | CONTROLS AND PROCEDURES | 111 | |||||||||
ITEM 9B. | OTHER INFORMATION | 112 | |||||||||
ITEM 9C. | DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS | 112 | |||||||||
PART III | 113 | ||||||||||
ITEM 10. | DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE | 113 | |||||||||
ITEM 11. | EXECUTIVE COMPENSATION | 113 | |||||||||
ITEM 12. | SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS | 113 | |||||||||
ITEM 13. | CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE | 113 | |||||||||
ITEM 14. | PRINCIPAL ACCOUNTANT FEES AND SERVICES | 113 | |||||||||
PART IV | 114 | ||||||||||
ITEM 15. | EXHIBITS AND FINANCIAL STATEMENT SCHEDULES | 114 | |||||||||
ITEM 16. | FORM 10-K SUMMARY | 118 | |||||||||
GLOSSARY OF TERMS AND ABBREVIATIONS | 119 | ||||||||||
SIGNATURES | 124 | ||||||||||
Capitalized terms and abbreviations used but not defined in this Annual Report on Form 10-K are defined in the glossary.
Form 10-K Table of Contents
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This Annual Report on Form 10-K (this “Report”) contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, and (or) future performance or other events, as well as underlying assumptions and other statements, that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would,” or similar expressions. Although we believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, there can be no assurance that these expectations and assumptions will prove to be correct. Forward-looking statements are subject to many risks and uncertainties. The results, events, or circumstances reflected in forward-looking statements may not be achieved or occur, and actual results, events, or circumstances may differ materially from those discussed in forward-looking statements.
The risks, uncertainties, and other factors that could cause actual results to differ materially from the forward-looking statements made by us include those discussed in this Report, including but not limited to “Item 1A. Risk Factors.” Moreover, we operate in a very competitive and rapidly changing environment. 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 the forward-looking statements contained in this Report.
You should not rely on forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Report primarily on our current expectations and assumptions about future events. Furthermore, statements such as “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based on information available to us as of the date of this Report. While we believe such information provides a reasonable basis for these statements, such information may be limited or incomplete, and there can be no assurance that any expectations, assumptions, beliefs, or opinions will prove to be correct. Our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all relevant information. These statements are inherently uncertain, and readers are cautioned not to unduly rely on these statements.
The forward-looking statements made in this Report relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this Report to reflect events or circumstances after the date of this Report or to reflect new information, actual results, revised expectations, or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions, or expectations described in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures, or investments.
MARKET AND INDUSTRY DATA
This Report includes estimates regarding market and industry data. Unless otherwise indicated, information concerning our industry and the markets in which we operate, including our general expectations, market position, market opportunity, and market size, are based on our management’s knowledge and experience in the markets in which we operate, together with currently available information obtained from various sources, including publicly available information, industry reports and publications, surveys, our customers, trade and business organizations, and other contacts in the markets in which we operate. Certain information is based on management estimates, which have been derived from third-party sources, as well as data from our internal research.
In presenting this information, we have made certain assumptions that we believe to be reasonable based on such data and other similar sources and on our knowledge of, and our experience to date in, the markets in which we operate. While we believe the estimated market and industry data included in this Report is generally reliable, such information is inherently uncertain and imprecise. Market and industry data is subject to change and may be limited by the availability of raw data, the voluntary nature of the data gathering process, and other limitations inherent in any statistical survey of such data. In addition, projections, assumptions, and estimates of the future performance of the markets in which we operate are necessarily subject to uncertainty and risk due to a variety of factors, including those described in “Cautionary Note Regarding Forward-Looking Information” and “Item 1A. Risk Factors” of this Report. These and other factors could cause results to differ materially from those expressed in the estimates made by third parties and by us. Accordingly, you are cautioned not to place undue reliance on such market and industry data or any other such estimates.
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Form 10-K Table of Contents
PART I.
ITEM 1. BUSINESS
Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 13.1 GW of power infrastructure in the United States, including 2.2 GW of nuclear power and a significant dispatchable fossil 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, Ohio, and Montana. Our team is committed to generating power safely and reliably and delivering the most value per megawatt produced. Talen is also powering the digital infrastructure revolution. We are well-positioned to serve this growing industry, as artificial intelligence data centers increasingly demand more reliable 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
Highly efficient baseload generation. We own and operate over 5.7 GW of low- and zero-carbon baseload generation, including a 90% interest in, the 2.5 GW Susquehanna facility, the seventh largest nuclear-powered generation facility in the U.S. In 2025, we produced approximately 17 TWh of reliable, zero-carbon power from Susquehanna at a low all-in cost of approximately $27 per MWh, while also maintaining excellent safety and operational performance (when measured by standards adopted by the nuclear industry). While Susquehanna has typically comprised approximately half of our total annual generation, we recently added an additional 2.8 GW of low-carbon generation—the equivalent of more than the entire Susquehanna plant—through our recent acquisitions of Freedom and Guernsey, which are some of the new newest, most highly-efficient H-class combined-cycle baseload natural gas facilities in the market. We also recently entered into an agreement to acquire the Lawrenceburg Power Plant and Waterford Energy Center, combined-cycle baseload natural gas facilities totaling an additional 2.0 GW in Indiana and Ohio, as part of the pending Cornerstone Acquisition. These strategically located facilities complement our existing fleet and add to our large load contracting strategy by serving as a backstop for our other existing units, further enhancing our fleet’s efficiency, flexibility, environmental performance, and geographic reach while concurrently modernizing our asset base. See “—Recent Developments” and Note 17 to our Annual Financial Statements for additional information on the Freedom and Guernsey Acquisitions and the proposed Cornerstone Acquisition.
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Form 10-K Table of Contents
Our baseload fleet has historically generated revenues primarily from energy sales into the PJM wholesale market, PJM capacity sales, and strategic hedging; however, as discussed further below, in June 2025, we and AWS entered into an expanded power purchase agreement for the long-term, fixed-price supply of up to 1,920 MW of power annually from Susquehanna to the adjacent AWS data center campus through 2042. See “—Our Key Markets and Revenue Streams—Contracted Revenues—AWS PPA” for additional information. The success of this arrangement opens up contractable opportunities for other assets under our “Talen flywheel” strategy. See “—Our Strategies—Combine the above strengths to execute on our “Talen flywheel” strategy” for additional information.
Dispatchable natural gas and oil intermediate and peaking units. Our 4.6 GW intermediate and peaking fleet (of which 2.9 GW is from Brunner Island and Montour after conversion, as discussed below) currently includes three technologically diverse natural gas generation facilities, with certain units capable of utilizing multiple fuel sources. We also recently entered into an agreement to acquire the Darby Generating Station, a 456 MW dual-fuel natural gas and oil peaking unit in Ohio, as part of the pending Cornerstone Acquisition. See “—Recent Developments” and Note 17 to the Annual Financial Statements for additional information. The dispatch diversity added by our intermediate and peaking units provides meaningful commercial and operational flexibility. These strategically located assets include significant generation in the attractive PJM wholesale market, allowing them to generate predictable revenues on cleared capacity while also benefiting from varying market dynamics and enhancing our ability to backstop long-term contractual obligations and other baseload capacity. 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 and Unit 3 of our H.A. Wagner facility. We are currently running our H.A. Wagner and Brandon Shores facilities, totaling 2.0 GW of capacity, under RMR agreements pursuant to which we receive fixed monthly payments in exchange for continuing to operate those facilities until May 31, 2029 (beyond their previously scheduled 2025 retirement dates) to maintain grid and transmission reliability in the Baltimore area until upgrades can be completed. See “—Our Key Markets and Revenue Streams—Contracted Revenues—Brandon Shores and H.A. Wagner RMR Arrangements” and Note 3 to the Annual Financial Statements for additional information on the RMR arrangements. 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, future contracts, and spot market sales (as applicable). Beginning in mid-2025, our Brandon Shores and H.A. Wagner facilities began operating as reliability resources under RMR agreements that provide fixed payments to us 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 technological and 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 Notes 3 and 4 to the Annual Financial Statements 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, approximately 13 GW of our generation capacity is located in the MAAC (Mid-Atlantic Area Council), BGE (Baltimore Gas and Electric), and AEP (American Electric Power) regions of PJM. The remainder of our generation capacity is from the Colstrip facility within 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 182,000 MW of generating capacity to more than 67 million people and operates wholesale electricity markets with approximately 1,110 members. Generators in PJM may earn revenues from sales of capacity, energy, and (or) ancillary services.
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Form 10-K Table of Contents
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 the FERC has 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 9 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.
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
AWS PPA. In June 2025, we entered into an amended AWS PPA to expand, and eventually replace, the existing PPA with AWS. The existing Susquehanna co-located load AWS PPA between us and AWS will begin transitioning to a “front-of-the-meter” arrangement after the completion of transmission reconfiguration projects expected to occur in spring 2026 with full transition expected to occur in spring 2027. The AWS PPA requires Talen to deliver carbon-free power to AWS over a significant contract term at anticipated premium prices. At the full contract quantity, we will provide AWS with 1,920 MW of carbon-free nuclear power through 2042 (with options to further extend its duration) for operations at the AWS Data Campus adjacent to Susquehanna (with the ability to deliver to other sites throughout Pennsylvania). The AWS PPA, which has minimum commitments, has a power delivery schedule that ramps up over time, which is expected to achieve the full volume no later than 2032, with the potential to meaningfully accelerate. See “Item 3. Legal Proceedings—Susquehanna ISA Amendment” for more information on the resolution of previous legal and regulatory matters relating to the AWS PPA.
Brandon Shores and H.A. Wagner RMR Arrangements. The Brandon Shores and H.A. Wagner RMR arrangements extend the operating life of these plants through May 31, 2029, or until such time the necessary transmission upgrades are placed into service. Beginning June 1, 2025, the RMR arrangements provide an annual fixed-cost payment of $145 million ($312/MWd) for Brandon Shores and $35 million ($137/MWd) for H.A. Wagner, which includes a performance “hold back” of $5 million per year for Brandon Shores and $2.5 million per year for H.A. Wagner, each to be paid out based on unit performance. We also receive separate reimbursement for variable costs and approved project investments. See Note 3 to the Annual Financial Statements for additional information on the RMR arrangements.
Demand Growth from Multiple Sources
Power demand forecasts continue to rise over time in PJM compared to previous expectations. Summer peak load is forecasted to grow by approximately 66 GW by 2036, or an average of 3.6% per year over the next 10-year period. In January 2026, PJM released updated long-term load forecasts which point to RTO-wide load in summer 2036 that is approximately 5% higher than 2025 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.
Fuel Supply
Our power generation assets are advantaged by significant fuel diversity, including nuclear, natural gas, coal, and oil capabilities. Further, our natural gas generation assets are situated near the Marcellus and Utica shale regions of Pennsylvania and Ohio, which provide access to fuel from some 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.
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Form 10-K Table of Contents
Nuclear. Susquehanna has a portfolio of supply contracts for raw uranium, conversion, enrichment, and fabrication. Our nuclear fuel cycle is fully contracted through the 2028 fuel load, more than 50% contracted through 2029, and over 20% contracted through 2030. 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, the government is required to reimburse Susquehanna for certain SNF storage costs through 2025 under a related settlement agreement, which we are currently in the process of seeking to extend through 2028. See Note 9 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 needs are 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. We maintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. 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 9 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 as 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.”
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Form 10-K Table of Contents
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—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.,” “Item 1C. Cybersecurity,” and Note 9 to the Annual Financial Statements.
Our Strategies
We believe we are well-positioned to achieve our business objectives through the following strategies:
Continue to focus on our core generation fleet that provides stable earnings and cash flows through operational excellence, high reliability, capital discipline, and prudent risk management. The foundation of our platform is safe, disciplined operational and commercial performance. Our core fleet, anchored by low-carbon baseload generation, produces stable earnings from cleared capacity and cash flows backed by multiple sources, including our AWS PPA and RMR arrangements. 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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations.” We now also 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.” 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. 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. 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 financial objectives, and we remain focused on maintaining appropriate risk management policies in the context of a right-sized balance sheet and the cash flow stability provided by long-term revenue contracts and backstopped by the Nuclear PTC.
Capture opportunities for long-term contracting arrangements with high quality counterparties. In addition to optimizing core operations, we believe we can unlock further value from our existing assets by driving the highest value per megawatt produced—supported by long-term power sales to computing, industrial, and other end users across our reliable portfolio that provides both baseload and dispatchable generation. We intend to grow our base of long-term contracting arrangements with high-quality, creditworthy counterparties to enhance earnings visibility, support sustainable growth, and create long-term value. Our focus will be on counterparties with strong credit profiles and strategic alignment, with contract terms designed to balance competitive pricing, operational flexibility, and appropriate risk protections. Accelerating demand from hyperscalers, industrial customers, and re-shoring of manufacturing drives load growth, which creates an attractive opportunity to contract reliable baseload generation for extended periods. Our operational track record and ability to deliver speed-to-market, price certainty, and scale position us well to achieve pricing premiums and contract structures that capture significant margin while also materially reducing commodity exposure and cash flow cyclicality. Importantly, these arrangements will also enable more efficient planning and resource deployment across the Company and the markets in which we operate. We will also continue to maintain a balanced portfolio by retaining a merchant component to serve as a backstop, preserve flexibility, provide downside protection, and selectively benefit from volatility.
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Maintain balance sheet strength with disciplined financial policy and capital allocation. We will continue to deploy a disciplined financial policy centered on high-quality cash flow generation, prudent leverage, and an efficient cost of capital. We have a strong balance sheet underpinned by modest leverage, robust liquidity, and long-dated debt maturities, as well as ample capacity and counterparty appetite for lien-based hedging, which does not require cash collateral posting. We view our balance sheet as a tool, providing flexibility to fund operations, manage commercial activity, and pursue value-accretive activities if the right opportunities arise. We will continue balancing reinvestment and deleveraging priorities with a commitment to returning capital to shareholders as free cash flow expands. We expect to target net leverage of approximately 3.5x or less through the cycle, while retaining a deliberate “toggle” to prioritize the most accretive use of capital—whether deleveraging, reinvestment, or shareholder returns—and to selectively lean into opportunities that are clearly cash flow accretive and value-enhancing. This framework preserves financial flexibility, supports counterparties’ confidence, and positions us to execute through market cycles. Our leverage framework is a target, not an absolute constraint, and we retain the flexibility to temporarily lean into incremental leverage for the right opportunity when returns justify it, while maintaining a clear path back to our leverage objectives. This disciplined approach strengthens financial resilience, supports commercial execution, and reinforces our ability to deploy capital dynamically as conditions evolve.
Continue to grow and diversify our fleet in a capital efficient manner. We intend to continue building on our track record to grow and diversify our generation fleet in a capital-efficient manner through a disciplined mix of value-uplift initiatives that expand scale, improve flexibility and reliability, and provide durable economics. We intend to maintain flexibility to pursue both organic and inorganic growth opportunities and to deploy capital where we can generate compelling risk-adjusted returns. This could include uprates and other improvements to existing assets, selectively acquiring assets that are immediately accretive, and advancing development opportunities. We will prioritize opportunities that complement our operational strengths, support long-term contracting premiums, and improve portfolio resilience. For instance, our recent Freedom and Guernsey Acquisitions bring highly-efficient baseload assets with high-capacity performance that are a reliable part of the grid today. Our platform provides additional pathways to growth, including advantaged land positions at or near existing assets with large interconnects that provide speed-to-market and expand our range of development and partnership options. We will continue to evaluate strategic opportunities where the economics are compelling, leveraging our experience to replicate successful structures and transactions, with any investment requiring a clear, durable returns profile relative to other uses of capital. We will apply disciplined investment criteria in our underwriting cases that are centered on risk-adjusted returns, resilience across market cycles, and clear pathways to value creation while also maintaining appropriate liquidity and leverage and adhering to a thoughtful overall capital allocation framework.
Combine the above strengths to execute on our “Talen flywheel” strategy. The Talen flywheel is a repeatable value creation strategy that leverages our platform of reliable, scalable generation assets and commercial capabilities to deliver durable free cash flow growth across market cycles. The flywheel includes contracting long-term power sales with high-quality, large-load counterparties where our assets and sites are advantaged in delivering speed-to-market, large-scale capability, price certainty, and appropriate credit support. These contracts can lock in meaningful premiums and provide visible, stable cash flows, improving the risk profile of our business and its related cash flows, which ultimately strengthen our financial foundation. With that strengthened cash flow profile and balance sheet, we are positioned to grow and diversify our fleet in a capital-efficient manner through a disciplined mix of acquisitions, selective development, land and interconnection monetization, and strategic partnerships, expanding our long-term contracting opportunity set while maintaining operational flexibility. This strategy is enabled by utilizing our balance sheet capacity as a strategic asset—toggling between shareholder returns and accretive strategic investments as market conditions and relative returns warrant—while targeting prudent leverage levels over time. For instance, we recently completed the acquisitions of Freedom and Guernsey and expect to acquire additional facilities through our pending Cornerstone Acquisition later this year. This cycle—contract assets, add assets, contract again—which we call the “Talen flywheel,” is designed to increase the number of high-quality, contractable opportunities across the portfolio, enabling us to pair reliable assets with long-term, creditworthy demand in a way that enhances stability while preserving flexibility.
Recent Developments
Cornerstone Acquisition
On January 15, 2026, we entered into the Cornerstone Merger Agreement to acquire from affiliates of Energy Capital Partners (“ECP”) the 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana, for an aggregate purchase price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $900 million at the time of the entry into the Cornerstone Merger Agreement. The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness. The stock consideration will be subject to lock-ups of 90 days on 50% of the stock consideration and 180 days on the remaining stock consideration.
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The addition of these assets to Talen’s portfolio will increase generation capacity by approximately 2.5 GW of natural gas generation, substantially expanding Talen’s presence in the western PJM market and adding additional efficient baseload generation assets to its fleet.
In connection with the stock consideration, at the closing of the Cornerstone Acquisition, we intend to enter into the Cornerstone RRA with certain parties thereto substantially in the form attached to this Report as Exhibit 4.16. Pursuant to the terms of the Cornerstone RRA, the Company will agree to use its commercially reasonable efforts to file a registration statement on Form S-3 under the Securities Act of 1933, as amended, to register the TEC common stock issued pursuant to the Cornerstone Merger Agreement with the SEC within three business days (and in any event within five business days) after issuance. See also “Item 1A. Risk Factors—Financial and Equity Risks—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 shareholders, future issuances of equity or debt securities by us, and (or) research or reports published by financial analysts.”
The proposed Cornerstone Acquisition is subject to regulatory approvals and the satisfaction of other customary closing conditions, and is expected to close early in the second half of 2026.
See Note 17 to the Annual Financial Statements for additional information on the Cornerstone Acquisition and “Item 1A. Risk Factors—Risks Related to the Cornerstone Acquisition” of this Report for a discussion of the associated risks.
The foregoing description of the Cornerstone Merger Agreement and the transaction contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Cornerstone Merger Agreement, a copy of which is incorporated by reference as Exhibit 2.1 to this Report. The Cornerstone Merger Agreement is being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Cornerstone Merger Agreement, which may be subject to important limitations and qualifications, and which may change after the date of the Cornerstone Merger Agreement, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.
PJM 2027/2028 Base Residual Auction
In December 2025, PJM announced the results of the 2027/2028 PJM BRA. Talen cleared 8,745 MW at a price of $333.44/MWd.
See “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” for additional information.
Closing of the Freedom and Guernsey Acquisitions
In November 2025, the Company consummated the Freedom and Guernsey Acquisitions for an aggregate $3.8 billion which is subject to certain post-closing adjustments for net working capital and other customary items. The Freedom and Guernsey Acquisitions were funded from the proceeds of the Unsecured Notes and the TLB-3. Additionally, TES increased its RCF (including its revolving LC capacity) from $700 million to $900 million and increased its LCF from $900 million to $1.1 billion and extended its maturity from December 2026 to December 2027.
Issuance of Senior Notes. In October 2025, TES issued (i) $1.4 billion in aggregate principal amount of 6.250% Senior Unsecured Notes due 2034, and (ii) $1.3 billion in aggregate principal amount of 6.500% Senior Unsecured Notes due 2036
See Notes 10 and 17 to the Annual Financial Statements for additional information on the financing transactions and issuance of the Unsecured Notes, and the Freedom and Guernsey Acquisitions, respectively.
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 9 to the Annual Financial Statements for additional information on specific legal matters.
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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 the 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 9 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 the FERC’s exclusive ratemaking jurisdiction over wholesale sales of electricity and the transmission of electricity in interstate commerce. The 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 the 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 the FERC-regulated entities that exist in several regions to provide transmission service across multiple transmission systems. The 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 the wholesale electricity markets administered by PJM. 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 6 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.
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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 9 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 2024 GHG Rule, which could significantly impact certain facilities, including our Colstrip facility. These rules are being legally challenged by us and others and are being reconsidered by the EPA.
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 RCRA 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 requirements for legacy CCR surface impoundments under the EPA CCR Rule that was finalized in 2024, 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 2024 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 requirements in the EPA ELG Rule, which will be defined following negotiations with state permitting authorities. We and other parties are legally challenging the 2024 EPA ELG Rule. Additionally, the EPA has extended the compliance deadlines for the 2024 EPA ELG Rule by five years. The extension rule has been legally challenged by environmental groups. 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 anchored by Susquehanna, which enabled us to generate 42% of our electricity output carbon-free in 2025, and our natural gas portfolio also includes a number of energy-efficient assets with low heat rates that provide a lower carbon intensity than traditional fossil fuel sources. The acquisitions of the Freedom and Guernsey plants further enhance our fleet, adding approximately 2.8 GW of high-quality, modern, efficient, baseload natural gas generation to our portfolio. 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.
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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 hours, and monetary donations. For instance, to date, events hosted by Susquehanna have raised approximately $1.5 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. In 2025, we reached a settlement with key stakeholders to continue running both of our Maryland generation facilities through May 2029 under RMR arrangements. 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 3 to the Annual Financial Statements for additional information on the RMR arrangements.
We believe the emerging data economy and the growing importance of artificial intelligence and continued re-shoring of manufacturing and other industries 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 view our people as vital assets and key stakeholders in our business. Accordingly, we invest in our employees by prioritizing their safety, offering numerous training and development opportunities, valuing employee feedback, providing competitive compensation that shares in the success of our business, delivering 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 2025, we had eleven OSHA recordable incidents and an OSHA Total Recordable Incident Rate (“TRIR”) of 0.55. 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.
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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 2025.
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 support continuous development, we offer a self-directed professional learning framework that enables employees to take ownership of their learning through curated development pathways, skill-building resources, and development planning tools aligned to business needs. This framework supports internal mobility, leadership readiness, and the development of skills critical to our evolving business. 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.
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. In 2025, we began offering 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, 2025, we had approximately 1,880 full-time employees, approximately 43% of which were represented by labor unions. Our collective bargaining agreements (“CBA”) include: (i) a CBA with IBEW Local 1638, covering 186 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 624 Pennsylvania employees, which is in effect until August 2030.
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 2026 Proxy Statement.
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. 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 U.S. Securities and Exchange Commission (the “SEC”).
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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. 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.
ITEM 1A. RISK FACTORS
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 secure and economical fuel and water supplies in some locations, both of which are 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.”
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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 futures contracts. Our business model depends on us successfully operating in a competitive environment and, unlike regulated utilities, we are not assured of any rate of return on capital investments through a regulated rate structure. Competitors in wholesale power markets include other non-utility generators, regulated utilities and their competitive subsidiaries, industrial companies, financial institutions, and other energy marketers. See also “Item 1. Business—Our Operations—Competition.” Some of our competitors may have advantages over us through access to greater resources, newer generation facilities, lower costs, or more experience. Our ability to compete is affected primarily by electricity prices, fuel prices, the relative cost of electric generation, and the reliability and availability of generation assets. These factors can be impacted by generation additions or retirements from the market, changes in natural gas distribution networks that affect the price and availability of fuel utilized for electric generation, changes in storage assets and transmission capacity, and technological advances in power generation and efficiency. Competition may also be impacted by the actions of environmental and other governmental authorities, including but not limited to the establishment of legislation or subsidies favoring one form of generation over another (such as investment tax credits, production tax credits, and other factors); for example, the Inflation Reduction Act contains a number of tax credits and incentives relating to renewable energy projects and clean energy technologies. Any negative impact on our ability to compete could adversely impact our business. See also “—Regulatory, Environmental, and Legal Risks—We could be impacted by changes in, or state interference with, the structure or operation of the markets in which we operate, including ongoing market restructuring in PJM.”
Our business is subject to extensive 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) the FERC, relating to the generation, sale, and transmission of electricity, and its designated Electric Reliability Organization (currently NERC), relating to reliability standards for the bulk power system; (ii) PJM, 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.”
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Our business could be adversely affected by events outside of our control, including armed conflicts, war, terrorist attacks or threats, government shutdowns, pandemics, natural disasters, cyber-based attacks, or other significant events.
Instability and unrest, as well as war, other armed conflicts, economic sanctions, acts of terrorism, or threats thereof may lead to economic disruption that could adversely affect our business through high volatility in fuel and other commodity prices, difficulty obtaining products such as nuclear fuel, disruptions in supply chains, disruptions or volatility in financial markets, or other factors. Additionally, during periods of federal government shutdowns, many government agencies cease to operate at full capacity or at all, which could result in the suspension of ongoing application processes, significant delays in regulatory approvals or other project timing, and difficulty in conducting any other business requiring government participation or approval. In addition, we could be adversely affected by an epidemic, an infectious disease outbreak, or other public health events, which could impact our workforce and the availability of other resources, resulting in decreased service levels and increased costs. Furthermore, as a significant portion of our power generation facilities are geographically concentrated in the mid-Atlantic area of the United States, we face increased risk that a natural or man-made disaster in that area could adversely affect a large part of our operations.
We are 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—Continue to focus on our core generation fleet that provides stable earnings and cash flows through operational excellence, high reliability, capital discipline, and prudent risk management.” 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.
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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, certain of our generation facilities incurred Capacity Performance penalties for failing to meet PJM’s Capacity Performance requirements during Winter Storm Elliott in 2022. See also “—Regulatory, Environmental, and Legal Risks.” Additionally, under the AWS PPA, we have committed to certain delivery quantities over time with agreed reliability standards and AWS may be entitled to contractual or other remedies in the event of our 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;
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•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 9 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 2 to the Annual Financial Statements for additional information.
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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 uneconomic coal-fired units, while our remaining coal-fired generation assets continue to be impacted by changing environmental regulations and power market economics. Although we 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, those assets may not continue to run beyond that date unless PJM continues to require their operation to maintain grid reliability. In addition, although our Brunner Island facility has been converted and can now run on either coal or natural gas, it remains a legacy coal facility with associated remediation obligations. We likewise have remaining liabilities associated with historical coal-fired generation at other legacy sites. We also own minority interests in three additional coal-fired facilities, including the Colstrip facility in Montana, of which we are the operator. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Forecasted Uses of Cash—Projected ARO and Accrued Environmental Liability Cash Flows” and Note 9 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 7 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.
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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. In addition, effective succession planning is also important to our long-term success. We cannot guarantee that any member of our leadership or workforce will continue to serve in any capacity for any particular period of time and we could have difficulty retaining certain key members of management beyond their currently agreed employment and compensation arrangements, many of which expire in early 2027. Failure to timely and effectively ensure the transfer of knowledge and smooth transitions involving senior management and other key personnel could hinder our strategic planning and execution. Furthermore, an aging workforce with significant retirement eligibility, mismatch of skill set, expectation of future needs, uncertainty around the future of our aging assets, or unavailability of short-term contract employees or contractors may lead to difficulty retaining our workforce, operating challenges, and increased costs. Additional challenges we could face include a lack of human resources, losses to our operational knowledge base, and the required time and other resources needed to develop new workers’ skills. In particular, our operations at Susquehanna largely depend on highly specialized personnel whose absence may adversely impact our ability to operate. We are also subject to the risk of organized actions by unionized employees which represent a significant proportion of our workforce. If we are unable to negotiate future collective bargaining agreements on favorable terms, or if our union employees were to engage in strikes, work stoppages, slowdowns, or other forms of labor disruption, we would be responsible for obtaining replacement labor and could experience increased costs, reduced power generation, outages, other operational disruptions, or reputational harm.
We could 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, 2025, our defined benefit pension plans, which cover certain of our retirees and employees, were underfunded by an estimated $212 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.
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We could also engage in mergers, business combinations, or similar corporate transactions. In addition to the types of risks discussed above, mergers and similar transactions may subject us to risks associated with: required stockholder approvals and other stockholder legal actions; changes or fluctuations in merger consideration that could affect the value our stockholders receive; changes in management or control of our business; challenges integrating or operating the combined company; or failure to realize the anticipated business opportunities, synergies, growth prospects, or other benefits. Any acquisition, divestiture, merger, or other corporate transaction could occupy a significant amount of our time and may strain our resources, increase our costs, and distract management. Furthermore, the extensive regulation of our business could delay, prevent, limit the scope of, or increase the costs associated with any such transaction. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters” and “—Regulatory, Environmental, and Legal Risks.” Any failure to meet contractual terms, whether for regulatory or other reasons, could result in transaction cancellation, costly disputes or litigation, breakage or other fees, or other costs and liabilities. No assurance can be provided that any such transaction will result in the anticipated benefits to our business or stockholders. See also “—Risks Related to the Cornerstone Acquisition.”
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 the FERC; the Department of Energy; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. See also “Item 1. Business—Legal, Regulatory, and Environmental Matters—Energy Regulation” and “—Our ownership and operation of a nuclear power facility subjects us to regulations, costs, and liabilities uniquely associated with these types of facilities.”
Certain of our subsidiaries sell electricity into the wholesale markets and are subject to rate, financial, and organizational regulation by the FERC. The FERC has authorized us to sell energy, capacity, and ancillary services at wholesale at market-based rates and has granted us various related customary waivers and blanket approvals, including a blanket authorization to issue securities and to assume liabilities. The FERC retains the authority to modify or withdraw our market-based rate authority and impose cost-based rates if it determines that the market is not competitive, we possess market power in one or more markets, we are not charging just and reasonable and not unduly discriminatory rates, or we have violated the FERC’s market behavior rules or engaged in market manipulation. Any reduction by the FERC in the rates that we may receive, revocation of the FERC’s waivers and blanket authorizations, or unfavorable changes to the regulation of our business by federal or state regulators could materially adversely affect our business. In addition, if we were found to have violated the FERC’s market behavior rules or other requirements of the FERC, the FERC could impose civil penalties or order us to disgorge associated profits. Our generation assets are also subject to the reliability standards promulgated by the FERC-designated Electric Reliability Organization (currently NERC) and approved by the FERC. If we fail to comply with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties and increased compliance obligations.
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.
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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 9 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. The FERC has issued regulations that require wholesale electricity transmission services, even when offered by parties other than RTOs and ISOs, to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale markets, there can be no assurance that transmission capacity will be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives, the adequacy of transmission facilities, or whether RTOs, ISOs, or other transmission providers will efficiently operate transmission networks and provide related services. Furthermore, regulatory approvals and orders that we have obtained may be subject to challenge and protest from time to time.
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 the FERC’s orders establishing rules for such capacity markets, we cannot guarantee those auctions will take place on those dates or at all. In addition, under PJM’s Capacity Performance model, we may be (and have in the past been) subject to substantial monetary penalties for failing to meet the Capacity Performance requirements set forth by PJM in certain emergency events. Continued efforts to address perceived capacity market design issues are ongoing, and we cannot predict the outcome of these market reforms or their impact on future capacity revenues. See Note 9 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.”
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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, 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 9 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.
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 9 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 8 to the Annual Financial Statements for additional information on AROs.
In addition, the EPA finalized standards under the EPA GHG Rule in 2024 for new and certain existing power plants. These regulations primarily affect baseload units in the national power fleet, including our coal-fired generation facilities that have not set near-term retirement dates (e.g., Colstrip). More stringent limits on carbon dioxide and other GHG emissions and carbon taxes could be implemented or expanded at the state or regional levels. Recently, certain state legislatures have considered bills that could materially affect our ability to operate our coal-fueled generation facilities. Furthermore, other EPA rules (e.g., the CCR and ELG Rules) could have a significant impact on our business as discussed herein. Each of these rules are currently subject to ongoing legal challenges. In addition, in January 2025, President Trump issued an executive order directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Under the Trump Administration, the EPA is currently reconsidering many of the regulations that impact fossil fuel-fired power plants. Consequently, future implementation and enforcement of these rules remains uncertain at this time.
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.
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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 9 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 6 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 9 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 “—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.” 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 9 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 9 to the Annual Financial Statements for additional information on the EPA CSAPR and nitrogen oxides requirements.
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Changes in tax law, the implementation regulations of certain tax provisions, adverse decisions by tax authorities, or changes to (and uncertainty surrounding) U.S. and international tariffs and trade may adversely affect our business.
The laws and rules pertaining to U.S. federal, state, and local income taxation are routinely being reviewed and modified by governmental bodies, officials, and regulatory agencies, including the Internal Revenue Service (“IRS”) and the U.S. Treasury Department. It cannot be predicted whether, when, in what form, or with what effective dates tax laws, regulations, and rulings may be enacted, promulgated, or issued, which could result in changes in the estimated values of recorded deferred tax assets and liabilities and future income tax assets and liabilities and an increase in our effective tax rate and tax liability. For example, the Inflation Reduction Act includes amendments to the Internal Revenue Code of 1986, as amended (the “Code”) to, among other things, create the Nuclear PTC program which, if eliminated, could negatively impact our business.
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.
Additionally, United States and international laws, rules, and practices pertaining to trade are currently undergoing frequent changes, including the imposition of new or expanded tariffs on international trade by U.S. and foreign governments. Moreover, President Trump has directed various federal agencies to further evaluate key aspects of U.S. trade policy, and discussion is ongoing regarding other potentially significant changes to U.S. and international trade policies, treaties, and tariffs. Accordingly, there continues to exist significant uncertainty about the future relationship between the U.S. and international trade partners. We cannot predict the timing or scope of any potential changes to, or the volatility of governmental decisions around, tariffs or other trade policies. Any new or increased trade tariffs, restrictions, or controls, as well as any resulting delays or disruptions in global supply chains or shipping channels, could materially increase the prices we pay for, or negatively impact our ability to obtain, on a timely basis or at all, fuel, materials, supplies, equipment, parts, and (or) other products critical to our operations. Furthermore, any of these developments, or the perception that any of them could occur, may have a material negative impact on the macro-level U.S. and global economy, which could negatively impact our interest rates, stock price, and ability to access capital markets.
Our ability to utilize our tax attributes, including net operating loss and interest carryforwards, if any, may be limited.
If an "ownership change" (as defined in Sections 382 and 383 of the Code) occurs, the amount of attributes that could be used in any one year following such ownership change could be substantially limited. In general, an "ownership change" would occur when there is a greater than 50 percentage point increase in ownership of a company's stock by stockholders, each of which owns (or is deemed to own under Section 382) 5 percent or more of such company's stock. If there is an "ownership change" (including by the normal trading activity of greater than 5% stockholders), the utilization of all NOLs existing at that time would be subject to additional annual limitations based upon a formula provided under Section 382 that is based on the fair market value of the company and prevailing interest rates at the time of the ownership change. In addition, any ownership change could result in additional limitations on our ability to use certain tax attributes, including interest and depreciation, existing at the time of any such ownership change and have an impact on our tax liabilities.
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 9 to the Annual Financial Statements for additional information on our legal matters.
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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 1 and 20 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.
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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 from June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components. See also “—The amount and terms of our indebtedness could adversely affect our financial condition and impair our ability to operate our business.”
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 and (or) become unrestricted in May 2026 upon the vesting and (or) release from lock-up of shares pursuant to certain existing awards under equity compensation plans. We may also issue additional shares under future grants of equity compensation awards, to raise capital, or in connection with future potential corporate alliances or acquisitions. For example, we expect to issue, and will be required to register, a substantial amount of common stock in connection with the proposed Cornerstone Acquisition. See “Item 1. Business—Recent Developments—Cornerstone Acquisition” for additional information.
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.
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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 four largest TEC stockholders collectively own approximately 33% of our outstanding shares of common stock. Large holders such as these may be able to significantly affect matters requiring approval by our stockholders, including but not limited to the election of directors and the approval of mergers or other business combination transactions. Furthermore, we are a Delaware corporation and the anti-takeover provisions of the Delaware General Corporation Law may discourage, delay, or prevent a change in control by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder, even if a change in control would be beneficial to our existing stockholders.
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 an independent, publicly traded company, we are required to comply with additional laws, regulations, and requirements, including but not limited to applicable SEC rules and regulations, certain provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), including maintaining internal control over financial reporting and reporting any material weaknesses in our control, and Nasdaq rules and requirements. These requirements cover a wide variety of topics including many aspects of disclosure, financial reporting, internal controls, and corporate governance, among others. Complying with these laws, regulations, and requirements will occupy a significant amount of our time and may strain our resources, increase our costs, and distract management, all of which may inhibit our ability to comply with these requirements in a timely or cost-effective manner.
Beginning with this Report we are required to furnish a report by management on the effectiveness of our internal control over financial reporting, pursuant to Section 404 of the Sarbanes-Oxley Act. Additionally, our independent registered public accounting firm is also required to express an opinion as to the effectiveness of our internal control over financial reporting.
We have, and will continue to, design, implement and test the internal control over financial reporting required to comply with this obligation but such process is complex, time-consuming, and costly, and management may not be able to timely and effectively implement the necessary controls and procedures. At any time, we may conclude that our internal controls, once tested, are not operating as designed or do not address all relevant financial reporting risks. Furthermore, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate. If we identify material weaknesses in the future or otherwise fail to 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.
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Risks Related to the Cornerstone Acquisition
The proposed Cornerstone Acquisition is subject to a number of conditions which, if not satisfied or waived, could delay or impair our ability to complete the transactions on the agreed terms or at all. Failure to consummate the Cornerstone Acquisition as contemplated or at all could adversely affect us and the price of our common stock.
Completion of the Cornerstone Acquisition is subject to the satisfaction or waiver of a number of conditions, including: (i) receipt of approval from the FERC under Section 203 of the Federal Power Act; (ii) expiration or termination of the applicable waiting period under the HSR Act; (iii) receipt of approval from the Indiana Utility Regulatory Commission, and (iv) other customary closing conditions, including but not limited to the absence of certain “material adverse events.” We cannot guarantee if or when these conditions will be satisfied or that the proposed Cornerstone Acquisition will be completed on the current terms or at all. There can also be no assurance as to the cost, scope, or impact of the actions, restrictions, or other conditions that may be required to obtain regulatory consents and approvals, and the Cornerstone Merger Agreement generally does not permit us to terminate the transactions due to the terms of required regulatory consents or approvals.
It is a condition to closing the Cornerstone Acquisition that no governmental law, ruling, or order is in effect that prohibits its consummation. Although we are not currently aware of any, legal actions relating to the proposed Cornerstone Acquisition could be filed under antitrust, securities, or other laws. There can be no assurance of the outcome of any such actions and, regardless, defending against them could result in delays, additional costs, or diversion of time and resources.
The Cornerstone Merger Agreement provides that either we or the sellers can terminate the applicable agreement if the respective acquisition is not completed by January 15, 2027 (which may be automatically extended to July 15, 2027 in the case of pending antitrust and (or) regulatory approvals). If the Cornerstone Acquisition is not consummated, or is consummated on different terms or timing than currently contemplated, we could be subject to a variety of risks, including but not limited to: (i) being required to pay the sellers a termination fee; (ii) incurrence of other significant transaction costs; (iii) inability to realize the anticipated benefits of the proposed acquisition; (iv) a decline in the market price of our common stock; (v) reputational harm; and (vi) diversion of management and employee attention from day-day-matters or other aspects of our business.
If completed, the proposed Cornerstone Acquisition may not achieve its intended results.
Although we currently anticipate that the Cornerstone Acquisition will be accretive to our earnings and cash flow, that expectation is based on preliminary estimates that are subject to change. We may fail to realize the anticipated benefits of the Cornerstone Acquisition, encounter additional transaction and integration-related costs, or be affected by other factors that impact preliminary estimates, any of which could decrease or delay the expected accretion and (or) contribute to a decrease in the price of our common stock.
We entered into the Cornerstone Merger Agreement with the expectation that the Cornerstone Acquisition would result in various benefits to the Company, including enhanced generation capabilities. Achievement of the anticipated benefits is subject to a number of uncertainties, including our ability to effectively integrate the acquired assets, which may be complex, costly, and time-consuming. Additional challenges could include, among others: (i) achieving the targeted operating or long-term strategic benefits from the acquired assets; (ii) issues or costs in integrating our key systems, keeping industry, vendor, and other business, relationships, and integrating key hedging and other commercial arrangements; (iii) possible inconsistencies between our standards, controls, policies, and procedures and those of the acquired assets and the resources required to implement or improve them to meet public company standards; (iv) potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions, as well as any unexpected write offs or impairment charges; and (v) the performance of the acquired assets and the related costs to operate and maintain them, including any unanticipated capital expenditures or investments.
Furthermore, the Company will not control the acquired assets until completion of the proposed Cornerstone Acquisition, and the acquired assets or their value could be negatively impacted by conditions occurring while the Cornerstone Acquisition is pending. Adverse changes could result from, among other things, physical asset damage, legal or regulatory developments, deteriorating general business, market, industry, or economic conditions, and other factors both within and beyond the control of the Company and the sellers. In addition, there could be potential unknown liabilities or unforeseen expenses not discovered during due diligence and not adequately covered by any representation and warranty insurance we may obtain or otherwise adjusted for in the Cornerstone Merger Agreement. Any such conditions could cause the value of the acquired assets to decline and (or) reduce the benefits of the Cornerstone Acquisition to the Company and its stockholders.
Any of the foregoing risks could result in failure to achieve the anticipated benefits of the Cornerstone Acquisition, and the expectations of our future financial condition and results of operations following the Cornerstone Acquisition might not be met. See also “—Commercial and Operational Risks—Acquisitions, divestitures, mergers, or other corporate transactions may expose us to additional risks.”
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We expect to incur a significant amount of indebtedness to finance a portion of the Cornerstone Acquisition. However, we are obligated to complete the transaction whether or not we have obtained the necessary funding.
We intend to raise approximately $2.55 billion of additional indebtedness to fund the Cornerstone Acquisition, in addition to issuing approximately $900 million in direct stock consideration. The amount of our indebtedness following the Cornerstone Acquisition could have adverse consequences for us, including, among others: (i) hindering our ability to adjust to changing market, industry, or economic conditions; (ii) making us more vulnerable to economic or industry downturns (including interest rate increases); (iii) limiting the amount of free cash flow available for future operations, acquisitions, dividends, stock repurchases, or other uses; (iv) reducing our flexibility under the terms of our indebtedness to, among other things, make restricted payments, obtain other financing, operate our business, and (or) take advantage of mergers, acquisitions, or other corporate opportunities; and (v) placing us at a competitive disadvantage compared to less leveraged competitors. Increased indebtedness could also impact our credit ratings, borrowing costs, access to capital markets, and ability to comply with our indebtedness. See also “—Financial and Equity Risks—The amount and terms of our indebtedness could adversely affect our financial condition and impair our ability to operate our business.”
The Cornerstone Merger Agreement does not contain a financing condition, and we would be required to complete the proposed Cornerstone Acquisition even if we do not have the required funds on hand. TEC has issued a parent guaranty in favor of the sellers to guarantee performance of our obligations under the Cornerstone Merger Agreement. We will be required to raise financing for the Cornerstone Acquisition on the timeline required to close the transaction, which could subject us to less favorable timing, costs, and market conditions than we would otherwise choose. If we cannot close on any element of our financing plan, we will need to pursue other financing options and certain existing indebtedness of the acquired assets or their affiliates may remain in place, which could result in less favorable financing terms that could negatively impact our costs, credit ratings, financing and operating flexibility, or realization of the anticipated benefits from the acquisition. See also “—Financial and Equity Risks—We may not have sufficient access to financing for our business.”
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
ITEM 1C. CYBERSECURITY
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, government shutdowns, pandemics, natural disasters, cyber-based attacks, or other significant events.”
Cybersecurity and Risk Mitigation
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.
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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 Operating Officer, General Counsel, Chief Financial Officer, President, Chief Executive Officer, Audit Committee, and (or) Board of Directors.
As of the date of this Report, we are not aware of previous cybersecurity incidents that have materially affected or are reasonably like to materially affect the Company.
Cybersecurity Governance
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ITEM 2. PROPERTIES
GENERATION FLEET AS OF DECEMBER 31, 2025
| Generation Facility | MW Capacity (a) | Percentage Ownership | MW Ownership | Fuel Type | Plant Type | State | ||||||||||||||||||||||||||||||||
| PJM | ||||||||||||||||||||||||||||||||||||||
Susquehanna (b) | 2,494 | 90 | % | 2,245 | Nuclear | Baseload | PA | |||||||||||||||||||||||||||||||
| Guernsey | 1,771 | 100 | % | 1,771 | Natural Gas | Baseload | OH | |||||||||||||||||||||||||||||||
| Martins Creek | 1,710 | 100 | % | 1,710 | Natural Gas/Fuel Oil | Peaker | PA | |||||||||||||||||||||||||||||||
Montour | 1,505 | 100 | % | 1,505 | Natural Gas | Peaker | PA | |||||||||||||||||||||||||||||||
Brunner Island (c) (d) | 1,419 | 100 | % | 1,419 | Natural Gas/Coal | Intermediate | PA | |||||||||||||||||||||||||||||||
Brandon Shores (e) | 1,273 | 100 | % | 1,273 | Coal | RMR | MD | |||||||||||||||||||||||||||||||
| Freedom | 1,049 | 100 | % | 1,049 | Natural Gas | Baseload | PA | |||||||||||||||||||||||||||||||
H.A. Wagner (e) | 702 | 100 | % | 702 | Fuel Oil | RMR | MD | |||||||||||||||||||||||||||||||
Lower Mt. Bethel | 607 | 100 | % | 607 | Natural Gas | Baseload | PA | |||||||||||||||||||||||||||||||
Conemaugh (b) (d) | 1,763 | 22.22 | % | 392 | Coal | Intermediate | PA | |||||||||||||||||||||||||||||||
Keystone (b) (d) | 1,724 | 12.34 | % | 213 | Coal | Intermediate | PA | |||||||||||||||||||||||||||||||
| Total | 16,017 | 12,886 | ||||||||||||||||||||||||||||||||||||
| WECC | ||||||||||||||||||||||||||||||||||||||
Colstrip Unit 3 (b) | 740 | 30 | % | 222 | Coal | Baseload | MT | |||||||||||||||||||||||||||||||
| Total | 740 | 222 | ||||||||||||||||||||||||||||||||||||
| Generation Fleet | 16,757 | 13,108 | ||||||||||||||||||||||||||||||||||||
__________________
(a)Generation capacity (summer rating, where applicable) is based on factors, among others, such as operating experience and physical conditions, which may be subject to revision.
(b)See Note 7 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 by December 31, 2028 and at Keystone and Conemaugh by December 31, 2034.
(e)See Note 3 to the Annual Financial Statements for additional information on the Brandon Shores and H.A. Wagner RMR arrangements.
ITEM 3. LEGAL PROCEEDINGS
Susquehanna ISA Amendment. As previously disclosed, in November 2024, the FERC issued an order denying an Amended Interconnection Service Agreement (the “ISA Amendment”) between PJM, a subsidiary of PPL Corporation, and Susquehanna that would have permitted Susquehanna to decrease by up to 480 MW the amount of power it would have otherwise supplied to the grid and instead supply that power directly to AWS in a co-located “behind-the-meter” arrangement. Talen promptly filed a motion for rehearing of the denial and the FERC subsequently stated, in an order issued in December 2024 and reaffirmed in April 2025, that it would address our request for rehearing in a future order. We subsequently filed an appeal in the U.S. Court of Appeals for the Fifth Circuit, which was transferred to the Third Circuit in November 2025.
Meanwhile, in June 2025, we entered into an amended AWS PPA to, among other things, transition to a “front-of-the-meter” arrangement with AWS. See “—Our Key Markets and Revenue Streams—Contracted Revenues—AWS PPA” for additional information. Following this revision, the load that was previously behind-the-meter was moved into PJM’s load forecast and, as a result, in October 2025, PJM filed a waiver request at the FERC to restore 148 MW of capacity interconnection rights (“CIRs”) to Susquehanna and add the corresponding generation back into the capacity auction. The FERC approved the request and the additional CIRs were available for the 2027/2028 BRA in December 2025 and should continue to be available for future auctions. In January 2026, following approval of the CIR waiver request, the ISA Amendment appeal was voluntarily dismissed by Talen. This matter is now closed.
FERC Co-Location Proceedings. Several consolidation matters before the FERC are likely to shape FERC and PJM policy around co-located load. In August 2024, Exelon sought to amend portions of the PJM tariff to clarify that co-located load arrangements must be categorized as either network load or point-to-point service (the “Exelon 205 Proceeding”), making them subject to the same transmission charges and fees for transmission-related services as grid-connected load pays. In November 2024, the FERC held a separately-docketed technical conference on co-located load and requested comments. Talen both participated in the technical conference and filed comments. Finally, in November 2024, Constellation filed a complaint at the FERC alleging that PJM’s tariff is unjust and unreasonable because it is silent on how to treat fully isolated co-located load.
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In February 2025, the FERC denied relief in the Exelon 205 Proceeding, consolidated the records and proceedings from the other proceedings, and initiated a new Section 206 proceeding directing PJM to show cause 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. After receipt of PJM’s proposed tariff revisions and extensive comments from stakeholders, the FERC issued an order on December 18, 2025 and outlined its views on several allowable co-location configurations, concluding with instructions to PJM to propose to the FERC final tariff language implementing these configurations. That PJM filing was made on February 23, 2026. When final, the new PJM tariff language will govern how large load may co-locate with generation facilities in PJM.
See Note 9 to the Annual Financial Statements for information about other material legal proceedings to which we are subject.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
PART II.
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Market Information and Holders
TEC’s common stock trades on the Nasdaq Global Select Market under the ticker symbol “TLN.” As of February 26, 2026, there were two shareholders of record of our common stock. The number of beneficial owners is substantially greater than the number of shareholders of record because all of our common stock is held in “street name” by brokers, banks, and other nominees on behalf of beneficial owners.
Stock Performance Graph
The following performance graph compares cumulative total stockholder return on TEC’s common stock from July 10, 2024, the first day TEC’s common stock began trading on Nasdaq, through December 31, 2025 with the cumulative returns of the S&P 500 Stock Market Index and the S&P 500 Utilities Index over the same period. The performance graph assumes an initial investment of $100 and reinvestment of all dividends in our common stock and in each of the indices. The performance graph and related text are based on historical data and are not necessarily indicative of future performance.
Value of Investment | ||||||||||||||||||||
| 7/10/2024 | 12/31/2024 | 12/31/2025 | ||||||||||||||||||
TLN | $ | 100 | $ | 158 | $ | 294 | ||||||||||||||
S&P 500 | 100 | 104 | 122 | |||||||||||||||||
S&P Utility | 100 | 109 | 123 | |||||||||||||||||
The information in this “Stock Performance Graph” section is being furnished solely pursuant to Item 201(e) of Regulation S-K and shall not be deemed “filed” for the purpose of Section 18 of the Exchange Act, or otherwise subject to the liabilities of that Section. Such information shall not be incorporated by reference into any registration statement or other filings with the SEC, whether made before or after the date hereof, regardless of any general incorporation language in such filing.
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Dividends
The holders of shares of our common stock are entitled to receive dividends and other distributions (payable in cash, property, or capital stock of the Company) when, as, and if declared thereon by the Board of Directors from time-to-time out of any assets or funds of the Company legally available for the payment of dividends and shall share equally on a per share basis in such dividends and distributions. Any future determination regarding the declaration and payment of dividends will be at the discretion of our Board of Directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects, and other factors our Board of Directors may deem relevant. In addition, our ability to pay dividends may be restricted by agreements governing TES’s indebtedness, which place certain limitations on TES’s ability to pay dividends to TEC, and by other agreements we may enter into in the future. See “Item 1A. Risk Factors—Financial and Equity Risks—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.”
Issuer Purchases of Equity Securities
Our Board of Directors approved the SRP in October 2023, initially authorizing the Company to repurchase up to $300 million of the Company’s shares of common stock. In May 2024, the Board of Directors approved an increase in the then-remaining SRP capacity to $1 billion through the end of 2025. In September 2024, the Board of Directors approved an increase in the then-remaining capacity to $1.25 billion through the end of 2026. In September 2025, the Board of Directors again approved an increase in the then-remaining capacity to $2 billion through the end of 2028.
Repurchases under the SRP may be made from time-to-time, at the Company’s discretion, in open market transactions at prevailing market prices, in negotiated transactions, or by other means in accordance with federal securities laws, and may be repurchased pursuant to a Rule 10b5-1 trading plan. The Company intends to fund repurchases under the SRP from cash on hand. Repurchases will be subject to a number of factors, including the market price of TEC’s common stock, alternative uses of capital, general market and economic conditions, and applicable legal requirements, and the SRP may be suspended, modified, or discontinued by the Board of Directors at any time without prior notice. The Company has no obligation to repurchase any amount of its common stock under the SRP. See Note 15 to the Annual Financial Statements for additional information on the SRP.
There were no share repurchases, including under the SRP, during the three months ended December 31, 2025. As of December 31, 2025, there was $2 billion of remaining capacity under the SRP.
ITEM 6. RESERVED
Not Applicable.
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the Annual Financial Statements and the accompanying notes included elsewhere in this Report.
This MD&A discusses activity for the years ended December 31, 2025 (Successor) and December 31, 2024 (Successor). The operating results for the period from May 18 through December 31, 2023 (Successor) and for the period from January 1 through May 17, 2023 (Predecessor) are not comparable with the operating results for the years presented in this MD&A due to the application of fresh start accounting after our Emergence from Restructuring in May 2023. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report on Form 10-K, filed with the SEC on February 28, 2025, for a discussion of the activities and results of operations for each of these periods.
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
Cornerstone Acquisition
On January 15, 2026, we entered into the Cornerstone Merger Agreement to acquire from affiliates of Energy Capital Partners (“ECP”) the 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana, for an aggregate purchase price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $900 million at the time of the entry into the Cornerstone Merger Agreement. The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness. The stock consideration will be subject to lock-ups of 90 days on 50% of the stock consideration and 180 days on the remaining stock consideration.
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The addition of these assets to Talen’s portfolio will increase generation capacity by approximately 2.5 GW of natural gas generation, substantially expanding Talen’s presence in the western PJM market and adding additional efficient baseload generation assets to its fleet.
In connection with the stock consideration, at the closing of the Cornerstone Acquisition, we intend to enter into the Cornerstone RRA with certain parties thereto substantially in the form attached to this Report as Exhibit 4.16. Pursuant to the terms of the Cornerstone RRA, the Company will agree to use its commercially reasonable efforts to file a registration statement on Form S-3 under the Securities Act of 1933, as amended, to register the TEC common stock issued pursuant to the Cornerstone Merger Agreement with the SEC within three business days (and in any event within five business days) after issuance. See also “Item 1A. Risk Factors—Financial and Equity Risks—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 shareholders, future issuances of equity or debt securities by us, and (or) research or reports published by financial analysts.”
The proposed Cornerstone Acquisition is subject to regulatory approvals and the satisfaction of other customary closing conditions, and is expected to close early in the second half of 2026.
See Note 17 to the Annual Financial Statements for additional information on the Cornerstone Acquisition and “Item 1A. Risk Factors—Risks Related to the Cornerstone Acquisition” of this Report for a discussion of the associated risks.
The foregoing description of the Cornerstone Merger Agreement and the transaction contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Cornerstone Merger Agreement, a copy of which is incorporated by reference as Exhibit 2.1 to this Report. The Cornerstone Merger Agreement is being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Cornerstone Merger Agreement, which may be subject to important limitations and qualifications, and which may change after the date of the Cornerstone Merger Agreement, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.
PJM 2027/2028 Base Residual Auction
In December 2025, PJM announced the results of the 2027/2028 PJM BRA. Talen cleared 8,745 MW at a price of $333.44/MWd.
See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets” for additional information.
Closing of the Freedom and Guernsey Acquisitions
In November 2025, the Company consummated the Freedom and Guernsey Acquisitions for an aggregate $3.8 billion which is subject to certain post-closing adjustments for net working capital and other customary items. The Freedom and Guernsey Acquisitions were funded from the proceeds of the Unsecured Notes and the TLB-3. Additionally, TES increased its RCF (including its revolving LC capacity) from $700 million to $900 million and increased its LCF from $900 million to $1.1 billion and extended its maturity from December 2026 to December 2027.
Issuance of Senior Notes. In October 2025, TES issued (i) $1.4 billion in aggregate principal amount of 6.25% Senior Unsecured Notes due 2034, and (ii) $1.3 billion in aggregate principal amount of 6.50% Senior Unsecured Notes due 2036.
See Notes 10 and 17 to the Annual Financial Statements for additional information on the financing transactions and issuance of the Unsecured Notes, and the Freedom and Guernsey Acquisitions, respectively.
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 2 and 9 to the Annual Financial Statements for additional information on our risks.
Commodity Markets
During 2025, PJM experienced weather-related volatility, as extreme winter and summer temperatures over certain days contributed to increased load demand and higher settled on-peak power prices during the year. TETCO M-3 natural gas prices settled higher in the period due to the effect of increased electric demand despite elevated storage levels that exceeded the five-year average.
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The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, were:
| 2025 | 2024 | 2023 | ||||||||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 60.30 | $ | 40.91 | $ | 39.22 | ||||||||||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 47.40 | 31.51 | 29.59 | |||||||||||||||||
| TETCO M-3 - $/MMBtu | 3.69 | 2.07 | 1.90 | |||||||||||||||||
As of December 31, 2025 (Successor), the weighted average forward market prices for the following years were:
| 2026 | 2027 | |||||||||||||
| PJM West Hub ATC - $/MWh | $ | 55.60 | $ | 59.29 | ||||||||||
| TETCO M-3 - $/MMBtu | 3.69 | 4.04 | ||||||||||||
PJM West Hub ATC Spark Spreads - $/MWh (a) | 29.76 | 31.00 | ||||||||||||
__________________
(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
As of December 31, 2024 (Successor), the weighted average forward market prices for the following years were:
2025 (a) | 2026 | 2027 | ||||||||||||||||||
| PJM West Hub ATC - $/MWh | $ | 47.43 | $ | 51.16 | $ | 54.34 | ||||||||||||||
| TETCO M-3 - $/MMBtu | 3.45 | 3.73 | 3.72 | |||||||||||||||||
PJM West Hub ATC Spark Spreads - $/MWh (b) | 23.25 | 25.07 | 28.27 | |||||||||||||||||
__________________
(a)Represents forward prices for 2025 as of December 31, 2024 (Successor). See weighted average settled prices table above for 2025 realized prices.
(b)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Capacity Markets
Our generation facilities are 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, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM market seller offer cap as determined by the PJM independent market monitor. Additionally, capacity prices may be affected by regulatory proceedings and (or) interventions by government stakeholders.
PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.
Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2027/2028 PJM Capacity Year was held in December 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 9 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, auction 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:
| 2027/2028 | 2026/2027 | 2025/2026 | 2024/2025 | 2023/2024 | ||||||||||||||||||||||||||||
PJM Capacity Performance ($/MWd) (a) | ||||||||||||||||||||||||||||||||
| MAAC | $ | 333.44 | $ | 329.17 | $ | 269.92 | $ | 49.49 | $ | 49.49 | ||||||||||||||||||||||
| PPL | 333.44 | 329.17 | 269.92 | 49.49 | 49.49 | |||||||||||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
For the 2027/2028 PJM Capacity Year, the Company cleared 8,745 MW at a price of $333.44/MWd.
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Form 10-K Table of Contents
Nuclear Production Tax Credit
The Nuclear PTC program, established by the Inflation Reduction Act, provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $44.60/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $26/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. Susquehanna earned Nuclear PTC revenue during the year ended December 31, 2024 (Successor). However, as prevailing market prices exceeded the PTC recognition threshold during the year ended December 31, 2025 (Successor), no such tax credits were earned for the period. See Notes 3 and 4 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the tax impact.
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. We maintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. 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 are prepared in accordance with GAAP and should be reviewed in conjunction with the Annual Financial Statements and the related notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the year ended December 31, 2025 (Successor), compared to the year ended December 31, 2024 (Successor).
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 hedges, Bitcoin revenue, and Nuclear PTC revenue. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
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.” We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.
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Form 10-K Table of Contents
Results for the Years Ended December 31, 2025 (Successor) and 2024 (Successor)
The following table and subsequent sections display the results of operations:
| Successor | Favorable (Unfavorable) Variance | |||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Energy and other revenues | $ | 2,141 | $ | 1,881 | $ | 260 | ||||||||||||||
| Capacity revenues | 485 | 192 | 293 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (45) | 42 | (87) | |||||||||||||||||
| Operating Revenues (Note 3) | 2,581 | 2,115 | 466 | |||||||||||||||||
| Fuel and energy purchases | (908) | (694) | (214) | |||||||||||||||||
| Nuclear fuel amortization | (97) | (123) | 26 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (61) | 20 | (81) | |||||||||||||||||
| Energy Expenses | (1,066) | (797) | (269) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (620) | (592) | (28) | |||||||||||||||||
General and administrative (includes stock-based compensation of $(526) and $(33)) (Note 13) | (624) | (163) | (461) | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (279) | (298) | 19 | |||||||||||||||||
| Impairments (Note 7) | — | (1) | 1 | |||||||||||||||||
| Other operating income (expense), net | (82) | (38) | (44) | |||||||||||||||||
| Operating Income (Loss) | (90) | 226 | (316) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | 182 | 178 | 4 | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (302) | (238) | (64) | |||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 34 | 884 | (850) | |||||||||||||||||
| Other non-operating income (expense), net | 10 | 61 | (51) | |||||||||||||||||
| Income (Loss) Before Income Taxes | (166) | 1,111 | (1,277) | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | (53) | (98) | 45 | |||||||||||||||||
| Net Income (Loss) | (219) | 1,013 | (1,232) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | — | 15 | 15 | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) | $ | (219) | $ | 998 | $ | (1,217) | ||||||||||||||
Year Ended December 31, 2025 (Successor) compared to Year Ended December 31, 2024 (Successor)
Net Income (Loss) Attributable to Stockholders decreased by $(1.2) billion, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $197 million favorable increase, primarily due to the following:
◦Energy and other revenues, net of Fuel and energy purchases. $46 million favorable increase. This is primarily related to the effects of a $519 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices at Susquehanna and our dispatchable generation facilities, and higher generation volumes at our dispatchable generation facilities. Such amounts are partially offset by (i) $(318) million decrease in digital revenue and Nuclear PTC revenue, coupled with (ii) $(155) million decrease in realized hedge results.
◦Capacity revenues. $293 million favorable increase. This is primarily driven by higher cleared capacity prices, partially offset by a decrease to lower cleared volumes through the PJM 2025/2026 BRA compared to the PJM 2024/2025 BRA.
◦Unrealized gain (loss) on derivative instruments, net. $(168) million unfavorable decrease. This is primarily related to the combined effects of: (i) $(82) million lower volume of hedge positions executed in the current period and (ii) $(45) million decrease in net short positions resulting from higher forward power prices, coupled with (iii) $(42) million unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
◦Nuclear fuel amortization. $26 million favorable decrease. This is primarily related to a decrease in the amortization of intangible assets related to certain nuclear fuel supply contracts which have expired.
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Form 10-K Table of Contents
•Operation, maintenance and development. $(28) million unfavorable increase. This is primarily due to increased maintenance costs, including the incremental maintenance at Susquehanna performed during its extended planned Unit 2 refueling outage in the spring of 2025, partially offset by lower maintenance costs at ERCOT and development costs at Cumulus Digital, both of which were sold in 2024.
•General and administrative. $(461) million unfavorable increase. This primarily consisted of a $(493) million increase of stock-based compensation expense primarily due to a change in accounting for certain stock-based awards. See Note 13 to the Annual Financial Statements for additional information. This was offset by a $32 million decrease in other compensation.
•Depreciation, amortization and accretion. $19 million favorable decrease. This is primarily due to a decrease in amortization and depreciation because of the derecognition of Nautilus assets in June 2025. See Note 7 to the Annual Financial Statements for additional information.
•Other operating income (expense), net. $(44) million unfavorable increase. This is primarily related to transaction costs for the Freedom and Guernsey Acquisitions and the loss resulting from the sale of Nuclear PTCs.
•Interest expense and other finance charges. $(64) million unfavorable increase. This primarily consisted of: (i) a $(34) million increase in cash interest expense on the Unsecured Notes, TLB-2, and TLB-3, partially offset by the absence of interest expense on the TLC and lower interest expense on the TLB-1, and (ii) a $(30) million increase in non-cash interest expense resulting from changes in unrealized positions on interest rate swaps and increases in deferred finance cost amortization. See Note 10 to the Annual Financial Statements for additional information on activity related to the above debt instruments.
•Gain (loss) on sale of assets, net. $(850) million unfavorable decrease. This primarily consisted of: (i) $564 million gain from the ERCOT Sale and (ii) $324 million gain from the AWS Data Campus Sale, both of which closed in 2024; and (iii) a $22 million gain from the sale of the Camden and Dartmouth in September 2025. See Note 17 to the Annual Financial Statements for additional information.
•Other non-operating income (expense), net. $(51) million unfavorable decrease. This primarily consisted of lower interest income on cash deposits in 2025 due to the release of restricted cash in 2024 after refinancing the TLC, combined with additional debt restructuring fees in 2025. See Note 19 to the Annual Financial Statements for additional information.
•Income tax benefit (expense). $45 million favorable decrease. This is primarily due to a decrease in pre-tax income for the year ended December 31, 2025 (Successor), the absence of valuation adjustments and the tax benefit associated with the Nuclear PTC recognized in 2024, and changes in nondeductible and other items. See the reconciliation of the effective tax rate in Note 4 to the Annual Financial Statements for additional information.
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) the settlement of, or forms of credit in support of, legacy asset retirement and (or) 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, the stability provided by contracted cash flows associated with long-term contracts lowers our overall hedging requirements.
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 2 for derivatives and hedging, Note 8 for AROs and environmental obligations, Note 10 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.
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Form 10-K Table of Contents
Liquidity and Letter of Credit Capacity
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Cash and cash equivalents, unrestricted | $ | 689 | $ | 328 | ||||||||||
Unutilized RCF capacity (a) | 900 | 700 | ||||||||||||
Total available liquidity | $ | 1,589 | $ | 1,028 | ||||||||||
Additional unutilized LC capacity (b) | $ | 652 | $ | 526 | ||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
(b)Includes LC capacity under the LCF and excludes LC capacity available under the RCF.
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 10 to the Annual Financial Statements for additional information on the RCF and LCF.
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.
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Outstanding surety bonds | $ | 228 | $ | 234 | ||||||||||
In May 2025, the Company elected to replace a surety provider and, as of December 31, 2025 (Successor), the replacement surety bonds issued by the new provider were outstanding. However, an aggregate $6 million of replaced surety bonds (included in the total above) continued to be outstanding as their release was not yet completed as of December 31, 2025 (Successor).
Forecasted Uses of Cash
Indebtedness. See Note 10 to the Annual Financial Statements and “—Recent Developments” above for additional information on our indebtedness.
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.
| 2026 | 2027 | |||||||||||||
| Nuclear fuel | $ | 122 | $ | 137 | ||||||||||
| PJM nuclear generation facility | 53 | 46 | ||||||||||||
| PJM fossil generation facilities | 118 | 73 | ||||||||||||
| Other | 25 | 12 | ||||||||||||
Total (a) | $ | 318 | $ | 268 | ||||||||||
__________________
(a)Expected capitalized interest on capital expenditures is a non-material amount in 2026 and 2027.
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. We believe the NDT, which was established to fund the Company’s proportionate share of Susquehanna’s ARO decommissioning costs, will be adequate when decommissioning commences at the expiration of Susquehanna’s licenses.
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Form 10-K Table of Contents
Non-nuclear AROs and accrued environmental costs are expected to be funded with available cash on hand. The majority of these obligations relate to ash impoundments at Colstrip, Brunner Island, and Montour. Based on the scope of work, a significant portion of the Colstrip and Brunner Island obligations are expected to be settled through 2030 as remediation activities are scheduled for completion. Settlements thereafter are forecasted to continue at reduced levels for several decades. No assurance can be provided as to the timing or amount of ARO and (or) accrued environmental cost settlements. Projections are subject to revision based on changes to the scope of work, estimated inflation rates, changes in the estimated timing of settling AROs, escalating retirement costs, and (or) other projections. Additionally, projections do not contemplate settlements for conditional AROs, which are AROs not presented on the consolidated balance sheets as they cannot be determined. See Note 8 to the Annual Financial Statements for additional information on AROs and Note 9 for additional information on the EPA CCR Rule.
As of December 31, 2025 (Successor), the expected undiscounted payments of non-nuclear AROs are estimated to be:
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||
| Accrued environmental costs | $ | 3 | $ | 3 | $ | 4 | $ | 4 | $ | 3 | $ | 13 | $ | 30 | ||||||||||||||||||||||||||||||
Non-nuclear AROs (a) | 40 | 53 | 47 | 56 | 38 | 255 | 489 | |||||||||||||||||||||||||||||||||||||
__________________
(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.
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
| Successor | Favorable (Unfavorable) Variance | |||||||||||||||||||
| Year Ended December 31, | ||||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Operating activities | $ | 704 | $ | 256 | $ | 448 | ||||||||||||||
| Investing activities | (4,003) | 1,171 | (5,174) | |||||||||||||||||
| Financing activities | 3,686 | (1,963) | 5,649 | |||||||||||||||||
Operating activities
A change of $448 million in net cash provided by (used in) operating activities is generally aligned with results from operations combined with working capital changes in the normal course of business. See “—Results of Operations” for additional information.
Investing activities
A change of $(5.2) billion in net cash provided by (used in) investing activities was primarily due to: (i) $(3.8) billion used to finance the Freedom and Guernsey Acquisitions in 2025; (ii) a $(635) million decrease in proceeds from the AWS Data Campus Sale in 2024; and (iii) a $(763) million decrease in proceeds from the ERCOT Sale in 2024. See Note 17 to the Annual Financial Statements for additional information on acquisitions and divestitures.
Financing activities
A change of $5.6 billion in net cash provided by (used in) financing activities was primarily due to: (i) $3.9 billion in new debt from the TLB-3 and the Unsecured Notes raised in 2025; (ii) $(370) million of net debt issuances in 2024; (iii) $182 million repayment of the Cumulus Digital TLF and (iv) $125 million purchase of noncontrolling interest in Cumulus Digital, both of which closed in 2024; and (v) a $1.9 billion decrease in share repurchases.
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.
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Form 10-K Table of Contents
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:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| (Millions of Dollars) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||
| Net Income (Loss) | $ | (219) | $ | 1,013 | $ | 143 | $ | 465 | |||||||||||||||||||||
| Adjustments | |||||||||||||||||||||||||||||
| Interest expense and other finance charges | 302 | 238 | 176 | 163 | |||||||||||||||||||||||||
| Income tax (benefit) expense | 53 | 98 | 51 | 212 | |||||||||||||||||||||||||
Depreciation, amortization and accretion (a) | 266 | 281 | 157 | 200 | |||||||||||||||||||||||||
Nuclear fuel amortization (a) | 97 | 123 | 108 | 33 | |||||||||||||||||||||||||
Reorganization (income) expense, net (Note 20) (b) | — | — | — | (799) | |||||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 106 | (62) | (52) | 63 | |||||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | (182) | (178) | (108) | (57) | |||||||||||||||||||||||||
Stock-based and other long-term incentive compensation expense (Note 13) (b) | 535 | 54 | 21 | — | |||||||||||||||||||||||||
(Gain) loss on asset sales, net (Note 17) (b) | (34) | (884) | (7) | (50) | |||||||||||||||||||||||||
Non-cash impairments and other charges (c) | 11 | 24 | 15 | 438 | |||||||||||||||||||||||||
Legal settlements and litigation costs | 6 | 4 | (84) | 1 | |||||||||||||||||||||||||
Acquisition and divestiture activities (d) | 65 | 62 | — | — | |||||||||||||||||||||||||
Operational and other restructuring activities (e) | 21 | 9 | 30 | 19 | |||||||||||||||||||||||||
| Noncontrolling interest | — | (21) | (42) | (14) | |||||||||||||||||||||||||
| Other | 8 | 9 | 18 | 21 | |||||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 1,035 | $ | 770 | $ | 426 | $ | 695 | |||||||||||||||||||||
__________________
(a)Includes the periodic amortization of fair value adjustments associated with acquired executory contracts and intangible assets.
(b)See the corresponding Note to the Annual Financial Statements for additional information.
(c)Includes impairments, net realizable value adjustments and other write-offs. See Note 7 to the Annual Financial Statements for additional information associated with the Brandon Shores impairment group recognized during the period of January 1 through May 17, 2023 (Predecessor).
(d)Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.
(e)Non-recurring severance and retention costs and strategic initiative costs.
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Form 10-K Table of Contents
Critical Accounting 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 that 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 1 to the Annual Financial Statements for accounting policies related to each of the following topics.
Business Combinations
The purchase price paid by the Company to acquire a business is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. If the purchase price exceeds the net fair value of the acquired business, the difference is recognized as goodwill on the consolidated balance sheet. Conversely, a bargain purchase gain is recognized on the consolidated statement of operations if the purchase price of an acquired business is below its net fair value.
Valuations of material long-term assets and (or) liabilities associated with an acquired business that lack quoted market prices contain the most significant fair value assumptions as they require substantial management judgment due to inherently uncertain future market, regulatory, and operational conditions. The Company engages third party specialists to assist with the preparation of fair value estimates as of the acquisition date utilizing present value techniques. The most significant factors influencing fair value measurements include: (i) the forecasted prices for capacity, wholesale power, and natural gas; (ii) volumetric assumptions; and (iii) discount rates. Although these inputs are believed to be consistent with reasonable market participant-based assumptions, the resulting fair value estimates are inherently unpredictable and uncertain. Changes to these assumptions may result in materially different fair value estimates, which in turn, could result in a different expense recognition pattern for future depreciation and amortization.
If the preliminary accounting for a business combination is incomplete by the end of the reporting period in which an acquisition occurs, purchase price allocation estimates are recognized on the consolidated balance sheet. Revisions to such estimates are permitted within one year from the acquisition date based on new information obtained that would have existed as of the acquisition date. Any adjustment that arises from information obtained that did not exist as of the acquisition date is recognized in the period in which the adjustment arises.
See Note 17 to the Annual Financial Statements for additional information on business combinations.
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 be 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 use the results of the study along with our experience, knowledge, and professional judgment to update Susquehanna’s decommissioning plan and the related carrying value of the ARO.
AROs are recognized at fair value at the time of installation of the related asset 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 8 to the Annual Financial Statements for additional information on AROs.
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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 to account 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, our derivative contracts are valued using a market approach utilizing 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 2 to the Annual Financial Statements for additional information on derivative instruments.
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. See Note 12 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, 2025 (Successor).
| Sensitivity | ||||||||||||||
| Actuarial Assumption | 1% Increase | 1% Decrease | ||||||||||||
| Discount rate | ||||||||||||||
| Postretirement benefit obligation | $ | (106) | $ | 126 | ||||||||||
| Net periodic pension cost | 4 | (6) | ||||||||||||
| Expected return on plan assets | ||||||||||||||
| Net periodic pension cost | (10) | 10 | ||||||||||||
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Form 10-K Table of Contents
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 4 to the Annual Financial Statements for additional information on income taxes.
Recent Accounting Pronouncements
See Note 1 to the Annual Financial Statements for a description of recently issued accounting pronouncements not yet adopted. There have been no recently adopted accounting pronouncements that had a material effect on the Company’s financials statements and (or) disclosures.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 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 (to the extent applicable), and expected generation (including cost inputs and planned outages) as of December 31, 2025 (Successor):
| Sensitivity Range | 2026 Margin Effect (a) | 2027 Margin Effect (a) | |||||||||||||||||||||||||||
| Low | High | Low $ | High $ | Low $ | High $ | ||||||||||||||||||||||||
Change in power price per $/MWh (b) | $ | (5) | $ | 5 | $ | (50) | $ | 55 | $ | (185) | $ | 185 | |||||||||||||||||
__________________
(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, rounded to nearest $5 million, 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.
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Form 10-K Table of Contents
Interest Rate Risk
Interest rate risk represents the risk that changes in benchmark interest rates could adversely affect our financial condition, results of operations, and cash flows. We are exposed to interest rate risk as it relates to our long-term debt. Generally, as interest rates rise, periodic cash interest payments due on the Company’s variable rate long term debt increases while lower interest rates decrease such payments. Although the Company is provided with cash flow predictability because changes to benchmark interest rates do not affect the Company’s periodic cash fixed rate debt interest payments, this could result in the Company paying above prevailing market rates during periods of declining interest rates. Accordingly, the fair value associated with the Company’s fixed rate debt generally increases as benchmark interest rates decline and decreases during periods of rising rates.
Within the parameters of our risk policy, a portion of our variable rate long-term debt is hedged through the use of financial derivative instruments that is intended to mitigate the variability of cash flows associated with the changes in benchmark rates. Additionally, the Company proactively monitors market conditions which may result, at its election, accessing capital markets to refinance its long-term debt portfolio.
As of December 31, 2025 (Successor), the Company’s long term debt portfolio included approximately: (i) $4.0 billion of fixed rate debt, (ii) $2.9 billion of variable rate debt, and (iii) $990 million of aggregate interest rate swap notional that hedges variable rate exposure through 2029. The following table displays the estimated effect of a hypothetical 10% increase in benchmark interest rates:
Change to interest expense, net (a) | $ | 7 | ||||||
Change in fair value of long-term debt, net (b) | (151) | |||||||
(a)Estimated increase of variable rate long-term debt interest expense over the next twelve months, net of interest rate swap settlement.
(b)Estimated decrease in the fair value of fixed rate long-term debt as of December 31, 2025 (Successor).
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, 2025 (Successor) and 2024 (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 financial institutions, ISOs, and marketing and trading companies. 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 2 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 proportionate share of Susquehanna's future decommissioning obligations. As of December 31, 2025 (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 proportionate 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.
As of December 31, 2025 (Successor), the net estimated effect of a hypothetical 10% increase in interest rates and a 10% decrease in equity values was:
| Estimated increase (decrease) in the fair value of NDT assets | $ | (117) | ||||||
See Notes 6 and 11 to the Annual Financial Statements for additional information regarding the NDT.
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Form 10-K Table of Contents
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
TALEN ENERGY CORPORATION AND SUBSIDIARIES
ITEM 8. TABLE OF CONTENTS
| Page | ||||||||
Reports of Independent Registered Public Audit Firm (PCAOB ID | 47 | |||||||
Consolidated Statements of Operations | 51 | |||||||
Consolidated Statements of Comprehensive Income (Loss) | 52 | |||||||
Consolidated Balance Sheets | 53 | |||||||
Consolidated Statements of Cash Flows | 54 | |||||||
Consolidated Statements of Equity | 56 | |||||||
Notes to the Annual Financial Statements | 57 | |||||||
1. Business, Basis of Presentation, and Summary of Significant Accounting Policies | 57 | |||||||
2. Risk Management, Derivative Instruments and Hedging Activities | 66 | |||||||
3. Revenue | 68 | |||||||
4. Income Taxes | 69 | |||||||
5. Inventory | 72 | |||||||
6. Nuclear Decommissioning Trust Funds | 73 | |||||||
7. Property, Plant and Equipment | 74 | |||||||
8. Asset Retirement Obligations and Accrued Environmental Costs | 76 | |||||||
9. Commitments and Contingencies | 77 | |||||||
10. Long-Term Debt and Other Credit Facilities | 84 | |||||||
11. Fair Value | 88 | |||||||
12. Postretirement Benefit Obligations | 89 | |||||||
13. Stock-Based Compensation | 94 | |||||||
14. Earnings Per Share | 96 | |||||||
15. Stockholders' Equity | 97 | |||||||
16. Supplemental Cash Flow Information | 98 | |||||||
17. Acquisitions and Divestitures | 99 | |||||||
18. Segments | 101 | |||||||
19. Talen Emergence from Restructuring | 103 | |||||||
20. Fresh Start Accounting | 104 | |||||||
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Item 8. Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of Talen Energy Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Talen Energy Corporation and its subsidiaries (Successor) (the "Company") as of December 31, 2025 and 2024, and the related consolidated statements of operations, of comprehensive income (loss), of equity and of cash flows for the years ended December 31, 2025 and 2024, and for the period from May 18, 2023 through December 31, 2023, including the related notes and financial statement schedule listed in the index appearing under Item 15(a)(2) (collectively referred to as the "consolidated financial statements"). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for the years ended December 31, 2025 and 2024, and for the period from May 18, 2023 through December 31, 2023 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.
Basis of Accounting
As discussed in Note 19 to the consolidated financial statements, the bankruptcy court confirmed the Company's Plan of Reorganization (the "plan") in December 2022. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 2022 and substantially alters rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of May 17, 2023.
Basis for Opinions
The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk.
Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
As described in Management’s Report on Internal Control Over Financial Reporting, management has excluded the Freedom and Guernsey entities from its assessment of internal control over financial reporting as of December 31, 2025, because they were acquired by the Company in a purchase business combination during 2025. We have also excluded the Freedom and Guernsey entities from our audit of internal control over financial reporting. The Freedom and Guernsey entities are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment and our audit of internal control over financial reporting collectively represent 20% and 6%, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2025.
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Item 8. Table of Contents
Definition and Limitations of Internal Control over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Acquisition of Freedom and Guernsey - Valuation of Plant and Equipment and Fuel Supply Contract Liabilities
As described in Note 17 to the consolidated financial statements, on November 25, 2025, the Company purchased all the ownership interests of Freedom and Guernsey for an aggregate purchase price of $3.8 billion in cash. Of the acquired assets and liabilities assumed, $4,509 million related to property, plant and equipment, a majority of which relates to plant and equipment, and $667 million of fuel supply contract liabilities were recorded. Fair value of plant and equipment was determined by management using the income approach and involved the use of significant assumptions including the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates. The fair values of fuel supply contract liabilities were estimated by management using the income approach and involved the use of significant assumptions including forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates.
The principal considerations for our determination that performing procedures relating to the valuation of plant and equipment acquired and fuel supply contract liabilities assumed in the acquisition of Freedom and Guernsey is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the plant and equipment acquired and the fuel supply contract liabilities assumed; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to (a) forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates for plant and equipment acquired and (b) forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates for fuel supply contract liabilities assumed; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the acquisition accounting, including controls over management’s valuation of the plant and equipment acquired and fuel supply contract liabilities assumed. These procedures also included, among others (i) reading the purchase agreements and the fuel supply agreements; (ii) testing management’s process for developing the fair value estimate of the plant and equipment acquired and the fuel supply contract liabilities assumed; (iii) evaluating the appropriateness of the income approach used by management; (iv) testing the completeness and accuracy of the underlying data used in the income approach; and (v) evaluating the reasonableness of the significant assumptions used by management related to (a) forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates for plant and equipment acquired and (b) forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates for fuel supply contract liabilities assumed. Evaluating management’s assumptions related to (a) forecasted prices for capacity, wholesale power, and natural gas, and volumetric assumptions for plant and equipment and (b) forecasted prices for wholesale power and natural gas and volumetric assumptions for fuel supply contract liabilities involved considering (i) the current and past performance of Freedom and Guernsey; (ii) the consistency with external market and industry data; and (iii) whether the assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the income approach and (ii) the reasonableness of the discount rates assumption for plant and equipment acquired and fuel supply contract liabilities assumed.
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Item 8. Table of Contents
Commodity Derivatives Valuation
As described in Notes 1, 2, and 11 to the consolidated financial statements, the Company’s commodity derivatives had a fair value net derivative asset position of $60 million and a fair value net derivative liability position of $156 million as of December 31, 2025. The Company utilizes 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 their generation portfolio. As disclosed by management, commodity derivative contracts are valued using a market approach which utilizes inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties.
The principal considerations for our determination that performing procedures relating to commodity derivatives valuation is a critical audit matter are (i) the significant judgment by management when developing the estimated fair value of commodity derivatives; (ii) a high degree of auditor judgment and effort in performing procedures and evaluating management’s significant assumptions related to the forward commodity prices and commodity price volatility; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to the commodity derivatives valuation, including controls over the development of significant assumptions. These procedures also included, among others (i) testing management’s process for developing the estimated fair value of commodity derivatives; (ii) evaluating the appropriateness of management’s market approach; (iii) testing, on a sample basis, the completeness and accuracy of the underlying contract terms and the accounting treatment conclusions; and (iv) evaluating, on a sample basis, the reasonableness of the significant assumptions used by management related to forward commodity prices and commodity price volatility. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of forward commodity prices and commodity price volatility assumptions.
/s/ PricewaterhouseCoopers LLP
February 26, 2026
We have served as the Company’s auditor since 2017.
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Item 8. Table of Contents
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Managers and Members of Talen Energy Supply, LLC
Opinion on the Financial Statements
We have audited the consolidated statements of operations, comprehensive income (loss), equity and cash flows of Talen Energy Supply, LLC and its subsidiaries (Predecessor) (the “Company”) for the period from January 1, 2023 through May 17, 2023, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the results of operations and cash flows of the Company for the period from January 1, 2023 through May 17, 2023 in accordance with accounting principles generally accepted in the United States of America.
Basis of Accounting
As discussed in Note 19 to the consolidated financial statements, the Company filed a petition in May 2022 with the bankruptcy court for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Plan of Reorganization was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 14, 2024
We have served as the Company’s auditor since 2017.
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Item 8. Table of Contents
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Successor | Predecessor | ||||||||||||||||||||||||||||
| (Millions of Dollars, except share data) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||
| Energy and other revenues | $ | $ | $ | $ | |||||||||||||||||||||||||
| Capacity revenues | |||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | ( | ||||||||||||||||||||||||||||
| Operating Revenues (Note 3) | |||||||||||||||||||||||||||||
| Fuel and energy purchases | ( | ( | ( | ( | |||||||||||||||||||||||||
| Nuclear fuel amortization | ( | ( | ( | ( | |||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | ( | ( | ( | ||||||||||||||||||||||||||
| Energy Expenses | ( | ( | ( | ( | |||||||||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||||||||
| Operation, maintenance and development | ( | ( | ( | ( | |||||||||||||||||||||||||
General and administrative (Includes stock-based compensation of $( | ( | ( | ( | ( | |||||||||||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Impairments (Note 7) | ( | ( | ( | ||||||||||||||||||||||||||
| Other operating income (expense), net | ( | ( | ( | ( | |||||||||||||||||||||||||
| Operating Income (Loss) | ( | ( | |||||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | |||||||||||||||||||||||||||||
| Interest expense and other finance charges (Note 10) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Reorganization income (expense), net (Note 20) | |||||||||||||||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | |||||||||||||||||||||||||||||
| Other non-operating income (expense), net | |||||||||||||||||||||||||||||
| Income (Loss) Before Income Taxes | ( | ||||||||||||||||||||||||||||
| Income tax benefit (expense) (Note 4) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Net Income (Loss) | ( | ||||||||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | ( | ||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Per Common Share | |||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | ( | $ | $ | N/A | ||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | $ | ( | $ | $ | N/A | ||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | N/A | ||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | N/A | ||||||||||||||||||||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| Successor | Predecessor | ||||||||||||||||||||||||||||
| (Millions of Dollars) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||
| Net Income (Loss) | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Other Comprehensive Income (Loss) | |||||||||||||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net (Note 6) | ( | ||||||||||||||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net (Note 12) | ( | ||||||||||||||||||||||||||||
| Postretirement benefit prior service (credits) costs, net (Note 12) | |||||||||||||||||||||||||||||
| Income tax benefit (expense) | ( | ( | |||||||||||||||||||||||||||
| Gains (losses) arising during the period, net of tax | ( | ||||||||||||||||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net (Note 6) | ( | ||||||||||||||||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | ( | ||||||||||||||||||||||||||||
| Postretirement benefit prior service (credits) costs, net (Note 12) | ( | ( | |||||||||||||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net (Note 12) | ( | ||||||||||||||||||||||||||||
| Income tax (benefit) expense | ( | ( | ( | ||||||||||||||||||||||||||
| Reclassifications from AOCI, net of tax | ( | ( | |||||||||||||||||||||||||||
| Total Other Comprehensive Income (Loss) | ( | ||||||||||||||||||||||||||||
| Comprehensive Income (Loss) | ( | ||||||||||||||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | ( | ||||||||||||||||||||||||||||
| Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| Successor | ||||||||||||||
| (Millions of Dollars, except share data) | December 31, 2025 | December 31, 2024 | ||||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Restricted cash and cash equivalents (Note 16) | ||||||||||||||
| Accounts receivable (Note 3) | ||||||||||||||
| Inventory, net (Note 5) | ||||||||||||||
| Derivative instruments (Notes 2 and 11) | ||||||||||||||
| Other current assets | ||||||||||||||
| Total current assets | ||||||||||||||
| Property, plant and equipment, net (Note 7) | ||||||||||||||
| Nuclear decommissioning trust funds (Notes 6 and 11) | ||||||||||||||
| Derivative instruments (Notes 2 and 11) | ||||||||||||||
| Other noncurrent assets | ||||||||||||||
| Total Assets | $ | $ | ||||||||||||
| Liabilities and Equity | ||||||||||||||
| Long-term debt, due within one year (Notes 10 and 11) | $ | $ | ||||||||||||
| Accrued interest | ||||||||||||||
| Accounts payable and other accrued liabilities | ||||||||||||||
| Derivative instruments (Notes 2 and 11) | ||||||||||||||
| Stock-based compensation liabilities (Note 13) | ||||||||||||||
| Other current liabilities | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Long-term debt (Notes 10 and 11) | ||||||||||||||
| Derivative instruments (Notes 2 and 11) | ||||||||||||||
| Postretirement benefit obligations (Note 12) | ||||||||||||||
| Asset retirement obligations and accrued environmental costs (Note 8) | ||||||||||||||
| Deferred income taxes (Note 4) | ||||||||||||||
| Acquired fuel supply contract liabilities (Note 17) | ||||||||||||||
| Other noncurrent liabilities | ||||||||||||||
| Total Liabilities | $ | $ | ||||||||||||
| Commitments and Contingencies (Note 9) | ||||||||||||||
| Stockholders' Equity (Note 15) | ||||||||||||||
Common stock ($ | $ | $ | ||||||||||||
| Additional paid-in capital | ||||||||||||||
| Accumulated retained earnings (deficit) | ( | ( | ||||||||||||
| Accumulated other comprehensive income (loss) | ( | ( | ||||||||||||
| Total Stockholders' Equity | $ | $ | ||||||||||||
| Total Liabilities and Stockholders' Equity | $ | $ | ||||||||||||
__________________
(a)45,687,828 45,961,910
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | ||||||||||||||||||||||||||||
| (Millions of Dollars) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||||||||
| Net Income (Loss) | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Non-cash reconciliation adjustments: | |||||||||||||||||||||||||||||
| Stock-based compensation (Note 13) | |||||||||||||||||||||||||||||
| Depreciation, amortization and accretion (Note 16) | |||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) (Note 6) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Unrealized (gains) losses on derivative instruments (Note 2) | ( | ( | |||||||||||||||||||||||||||
| Deferred income taxes | ( | ||||||||||||||||||||||||||||
| Nuclear fuel amortization (Note 7) | |||||||||||||||||||||||||||||
| (Gain) loss on sales of assets, net (Note 17) | ( | ( | ( | ||||||||||||||||||||||||||
| (Gain) loss on AWS Data Campus Sale and ERCOT Sale (Note 17) | ( | ||||||||||||||||||||||||||||
| Reorganization (income) expense, net (Note 20) | ( | ||||||||||||||||||||||||||||
| Impairments (Note 7) | |||||||||||||||||||||||||||||
| Other (Note 16) | ( | ( | |||||||||||||||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||||||||||||||
| Accounts receivable | ( | ||||||||||||||||||||||||||||
| Inventory, net | ( | ||||||||||||||||||||||||||||
| Other assets | ( | ||||||||||||||||||||||||||||
| Accounts payable and accrued liabilities | ( | ( | ( | ( | |||||||||||||||||||||||||
| Accrued interest | ( | ( | |||||||||||||||||||||||||||
| Collateral received (posted), net | ( | ( | |||||||||||||||||||||||||||
| Other liabilities | ( | ( | |||||||||||||||||||||||||||
| Net cash provided by (used in) operating activities | |||||||||||||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||||||||
| Freedom and Guernsey Acquisitions, net (Note 17) | ( | ||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds investment purchases (Note 6) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds (Note 6) | |||||||||||||||||||||||||||||
| Nuclear fuel expenditures (Note 7) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Property, plant and equipment expenditures (Note 7) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Proceeds from AWS Data Campus Sale and ERCOT Sale (Note 17) | |||||||||||||||||||||||||||||
| Proceeds from the sale of assets | |||||||||||||||||||||||||||||
| Other | ( | ( | ( | ||||||||||||||||||||||||||
| Net cash provided by (used in) investing activities | ( | ( | ( | ||||||||||||||||||||||||||
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | ||||||||||||||||||||||||||||
| (Millions of Dollars) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||||||||
| Debt issuances (Note 10) | |||||||||||||||||||||||||||||
| Share repurchases (Note 15) | ( | ( | |||||||||||||||||||||||||||
| Deferred financing costs | ( | ( | ( | ( | |||||||||||||||||||||||||
| Revolving credit facility borrowings (Note 10) | |||||||||||||||||||||||||||||
| Revolving credit facility repayments (Note 10) | ( | ||||||||||||||||||||||||||||
| Debt repayments (Note 10) | ( | ( | |||||||||||||||||||||||||||
| Cumulus Digital TLF repayment | ( | ( | |||||||||||||||||||||||||||
| Repurchase of noncontrolling interest | ( | ( | |||||||||||||||||||||||||||
| Cash settlement of restricted stock units | ( | ||||||||||||||||||||||||||||
| Exercise or repurchase of warrants | ( | ( | |||||||||||||||||||||||||||
| LMBE-MC TLB payments | ( | ( | |||||||||||||||||||||||||||
| TLB-1 proceeds, net | |||||||||||||||||||||||||||||
| Repayment of prepetition secured indebtedness | ( | ||||||||||||||||||||||||||||
| Financing proceeds at Emergence, net of discount | |||||||||||||||||||||||||||||
| Contributions from member | |||||||||||||||||||||||||||||
| Payment of make-whole premiums on prepetition secured indebtedness | ( | ||||||||||||||||||||||||||||
| Derivatives with financing elements | ( | ||||||||||||||||||||||||||||
| Other | ( | ||||||||||||||||||||||||||||
| Net cash provided by (used in) financing activities | ( | ( | ( | ||||||||||||||||||||||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents | ( | ( | |||||||||||||||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | |||||||||||||||||||||||||||||
| End of period cash and cash equivalents and restricted cash and cash equivalents | $ | $ | $ | $ | |||||||||||||||||||||||||
See Note 16 for supplemental cash flow information.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Treasury stock | Member's Equity | Non controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||||
| December 31, 2022 (Predecessor) | — | $ | — | $ | — | $ | — | $ | — | $ | ( | $ | $ | ( | ||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Cancellation of member’s equity (b) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Issuance of member’s equity (b) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Issuance of warrants (b) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Common equity from member’s equity exchange | — | — | — | ( | — | |||||||||||||||||||||||||||||||||||||||||||||
Non-cash contributions (c) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Non-cash distributions (d) | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| May 17, 2023 (Predecessor) | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
| May 18, 2023 (Successor) | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | ( | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||
Purchase of noncontrolling interest (e) | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||||||||
| Cash contribution | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Non-cash distributions (d) | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Equity incentive plans | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Other | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 (Successor) | $ | $ | $ | ( | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | — | — | ( | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||
| Retirement of treasury stock | — | ( | ( | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Purchase of noncontrolling interest (e) | — | ( | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Cash settlement of restricted stock units | — | ( | — | — | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||
| Exercise of warrants | ( | — | — | — | — | — | ( | |||||||||||||||||||||||||||||||||||||||||||
Cash distributions (f) | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
Non-cash distributions (g) | — | — | — | — | — | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Equity incentive plans | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2024 (Successor) | $ | $ | ( | $ | ( | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | ( | — | — | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | — | — | ( | — | — | ( | ||||||||||||||||||||||||||||||||||||||||||
| Retirement of treasury stock | — | ( | ( | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
Equity incentive plans (h) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2025 (Successor) | $ | $ | ( | $ | ( | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Pursuant to the Plan of Reorganization: (i) existing equity interests were canceled; and (ii) new equity interests and equity-classified warrants were issued.
(c)Related to contributions of cryptocurrency miners by TeraWulf to Nautilus.
(d)Related primarily to distribution of Bitcoin to TeraWulf.
(e)TES acquisition of remaining noncontrolling interests in Cumulus Digital and Nautilus.
(f)Distributions to noncontrolling interest owners of Cumulus Digital and Nautilus.
(g)Related primarily to distribution of Bitcoin and cryptocurrency miners to TeraWulf.
(h)Includes cash payments for tax withholdings on vested stock-based awards of $26 million and impact of modification of certain awards from equity to liability.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO THE ANNUAL FINANCIAL STATEMENTS
Capitalized terms and abbreviations appearing in these notes to the Annual Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted.
“TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. For periods after May 17, 2023, the terms “Talen,” the “Company,” “we,” “us,” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary.
1. Business, Basis of Presentation, and Summary of Significant Accounting Policies
Organization and Operations
Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 13.1 GW of power infrastructure in the United States, including 2.2 GW of nuclear power and a significant dispatchable fossil 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, Ohio, and Montana. Talen is headquartered in Houston, Texas.
Basis of Presentation and Principles of Consolidation
Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition. In May 2022, TES and 71 of its subsidiaries voluntarily commenced the Restructuring under Chapter 11 of the U.S. Bankruptcy Code. TEC joined the Restructuring in December 2022. The Plan of Reorganization was approved by the requisite parties and confirmed by the bankruptcy court in late 2022, and was consummated and became effective in May 2023, when TEC, TES, and the other debtors emerged from the Restructuring.
Upon commencement of the Restructuring, TES was deconsolidated from TEC for financial reporting purposes because TEC no longer controlled TES. TEC regained control of TES at Emergence, which resulted in TEC’s reconsolidation of TES. The combination was accounted for as a reverse acquisition in which TEC was the legal acquirer and TES was the accounting acquirer. Accordingly, these Annual Financial Statements are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer.
After Emergence, TES applied fresh start accounting, which resulted in a new basis of accounting, as the Company became a new financial reporting entity. As a result of the application of fresh start accounting and the implementation of the Plan of Reorganization, our financial position and results of operations beginning after Emergence are not comparable to our financial position or results of operations prior to that date. The financial results are presented for: (i) the Predecessor period from January 1 through May 17, 2023 (Predecessor); and (ii) the Successor periods from May 18 through December 31, 2023 (Successor) and the years ended December 31, 2024 (Successor) and December 31, 2025 (Successor). These Annual Financial Statements and notes hereto have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
See Note 19 for additional information on the Restructuring and Note 20 for additional information on fresh start accounting.
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Item 8. Table of Contents
Summary of Significant Accounting Policies
Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity, or cash flows.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Restructuring Effects. Income, expenses, gains, or losses that were incurred or realized as a direct result of the Restructuring since entering bankruptcy proceedings are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations.
See Notes 19 and 20 for additional information on the Restructuring and fresh start accounting, respectively.
Business Combinations. The purchase price paid by the Company to acquire a business is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. If the initial accounting for a business combination is incomplete by the end of the reporting period in which the combination occurs, provisional amounts are reported. Provisional amounts can be adjusted prospectively during a measurement period not to exceed one year from the acquisition date. If the purchase price exceeds the net fair value of the acquired business, the difference is recognized as goodwill on the consolidated balance sheets. Conversely, a bargain purchase gain is recognized on the consolidated statements of operations if the purchase price of an acquired business is below its net fair value.
See Note 17 for additional information on recent business combinations.
Fair Value of Financial Instruments and Hierarchy. The portion of our assets and liabilities carried at fair value are measured as of a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability). An exit price may be developed under a market approach utilizing market transactions, an income approach utilizing present value techniques, or a replacement cost approach. The exit prices are disclosed according to the quality of valuation inputs under a three-tiered hierarchy comprised of:
(i)Level 1 inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities;
(ii)Level 2 inputs that are other than quoted prices that are directly or indirectly observable; and
(iii)Level 3 inputs that are unobservable inputs for assets or liabilities.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Those initially classified as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of a reporting period. For qualifying investments without readily determinable fair values, NAV is elected as a practical expedient to determine the fair values based on firm quotes of NAV per share.
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The following is a description of the Company’s fair value hierarchy associated with assets and liabilities presented on the Consolidated Balance Sheets as “Derivative instruments,” “Long-term Debt,” “Nuclear decommissioning trust funds,” and pension and other postretirement plan asset investments within “Postretirement benefit obligations” or “Other noncurrent assets.”
| Fair Value Hierarchy | Description | ||||
| Level 1 | Derivative instruments: Commodity and interest rate futures and/or options. NDT funds: Equity securities and U.S. Government debt securities, which include U.S. Treasury bills, notes and (or) bonds. Pension plan asset investments: Alternative and other investments, which include U.S. Treasury futures contracts. Other postretirement plan asset investments: U.S. Government debt securities, which include U.S. Treasury bills, notes, and/or bonds. | ||||
| Level 2 | Derivative instruments: Over-the-counter swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers, or pricing service companies that are all corroborated by market data. NDT funds: U.S. government debt securities, municipal debt securities and corporate debt securities are valued using pricing provided by brokers or pricing service companies and corroborated by market data. Long-term debt: The reported fair value of fixed and variable rate debt is valued using prices provided by brokers or pricing service companies and corroborated by market data. The carrying value of certain other short-term indebtedness approximates fair value. Other postretirement plan asset investments: Corporate debt securities are valued using pricing provided by brokers or pricing service companies and corroborated by market data. | ||||
| Level 3 | There are no material assets or liabilities valued utilizing such inputs. | ||||
| Net Asset Value (NAV) | NDT funds: ▪Cash equivalents consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily. ▪Equity securities consist of commingled fixed income funds that can be redeemed daily and real estate investment trusts that can be redeemed quarterly, subject to investment manager approval. Pension plan asset investments: ▪Cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily. ▪Commingled equity securities consist of large and small cap U.S. and international funds that can be redeemed daily. ▪Commingled debt securities consist of funds that invest in investment-grade intermediate and long-duration corporate and government fixed-income securities that can be redeemed daily. ▪Alternative and other investments primarily consist of fund investments in real estate, private equity, hedge funds, and infrastructure, which have redemption limitations subject to the respective general partner’s approval. Other postretirement plan asset investments: ▪Cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds that can be redeemed daily. ▪Commingled equity securities consist of investments in a passively-managed equity index fund that invests in securities and a combination of other collective funds that can be redeemed daily. ▪Commingled debt securities consist of investments in funds that invest in a diversified portfolio of investment-grade fixed income securities that can be redeemed daily. | ||||
See Notes 2, 6, 11, and 12 for disclosures on fair value measurements and fair value levels.
Operating Revenues and Revenue Recognition. Operating revenues on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) “Capacity revenues;” (ii) “Energy and other revenues;” and (iii) “Unrealized gain (loss) on derivative instruments” for certain electricity contracts.
Capacity revenues. Include amounts earned from auctions in ISOs and RTOs and under bilateral contracts to provide available generation capacity that is needed to satisfy system reliability and integrity requirements. Capacity revenues are recognized ratably over the PJM Capacity Year by Talen-owned generation facilities that participate in the auctions and stand ready to deliver generated power. Capacity revenues are based on invoiced amounts corresponding directly to the value provided over a specific time interval.
Energy and other revenues.
Energy revenues primarily include: (i) amounts earned from sales to ISOs and RTOs for electric generation and ancillary services products that support transmission and grid operations; (ii) amounts earned for wholesale and retail electricity and other energy-related product sales to bilateral counterparties; and (iii) realized gains and losses on commodity derivative instruments.
Sales of each electric generation and ancillary services to ISOs and RTOs represent performance obligations recognized over time based on volumes delivered or services performed at contractually agreed upon day-ahead or real-time market prices.
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Sales of wholesale electricity to bilateral counterparties represent performance obligations recognized over a contractually agreed period of time based on volumes delivered at the contractually agreed price.
Such sales are recognized based on invoiced amounts, which correspond directly with the value provided over a specific time interval. Accrued and unbilled revenues are estimated at the end of each reporting period.
Realized gains and losses on commodity derivative instruments include the settlements of financial and physical power transactions utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Energy and other revenues” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Energy Expenses” below for additional information on realized gains and losses of derivative instruments presented as “Fuel and energy purchases” on the Consolidated Statements of Operations.
Other revenues primarily include: (i) Nuclear PTC revenues; and (ii) Nautilus revenues from Bitcoin mining.
The Nuclear PTC provides qualified nuclear power generation facilities with transferable credits for electricity produced and sold to an unrelated party during each tax year. These credits, which are accounted for by analogy to income-based grants under international accounting standards for government grants and disclosure of government assistance, are recognized when there is reasonable assurance that the Company will comply with the applicable conditions and that the credit will be received, which is generally over the period of production. As the credits that are generated each tax year are based on annual gross receipts and production volumes, the measurement of the credit value is estimated at each period until the final value can be determined at the end of the year, which may be different than the estimated amount. The credit value includes a five -times multiplier (up to $15 per MWh) for meeting prevailing wage requirements. Accordingly, Nuclear PTCs are recognized based on production volumes generated during the period and measured at the credit value for the tax year. See Note 3 for amounts recognized, which are presented as “Energy and other revenues” on the Consolidated Statements of Operations and “Other current assets” on the Consolidated Balance Sheets. Credits that are utilized to reduce federal income taxes payable are presented as a reduction of “Other current liabilities” on the Consolidated Balance Sheets. Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value recognized.
Prior to its suspension of operations in October 2024, the primary output of Nautilus’s ordinary business activities was providing hash calculation services to solve complex cryptographic algorithms in support of blockchain mining. Nautilus was party to a mining pool arrangement to provide an unspecified amount of its available hash calculations to an unaffiliated mining pool operator. Nautilus was entitled to an enforceable right to compensation from the mining pool operator only for the duration of time over which Nautilus provides its hash calculations.
In exchange for providing hash calculation services to the mining pool operator, Nautilus was entitled to consideration, whether or not the mining pool operator successfully solves a block, based on a ‘full-pay-per-share’ payout methodology. Nautilus’s only performance obligation was to provide hash calculations to the mining pool operator. If Nautilus did not provide hash calculations to the mining pool operator, no consideration was earned by Nautilus nor did Nautilus incur any penalties from the mining pool operator. The Bitcoin earned by Nautilus was all variable noncash consideration. Accordingly, Nautilus recognized revenue that was measured at fair value using the quoted price for Bitcoin in Nautilus’s principal market at the beginning of each day (Coordinated Universal Time). Nautilus operations were suspended in October 2024 and no Bitcoin mining revenues have been generated since that time.
Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain power contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Energy Expenses” below for additional information on unrealized gains and losses of derivative instruments presented as “Energy Expenses” on the Consolidated Statements of Operations.
See Note 3 for additional information on revenue.
Energy Expenses. Energy expenses on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) “Fuel and energy purchases;” (ii) “Nuclear fuel amortization;” and (iii) “Unrealized gain (loss) on derivative instruments” for certain commodity purchase contracts.
Fuel and energy purchases. Primarily includes: (i) fuel costs; (ii) environmental product costs; and (iii) realized gain (loss) on commodity derivative instruments.
Fuel costs include: (i) the costs incurred by Talen-owned generation facilities for the conversion of natural gas, coal, and (or) oil products to electricity, and (ii) the periodic amortization (through contract expiry) of the acquisition date fair value of acquired executory fuel supply contracts. Fuel for electric generation from natural gas purchases are recognized at the agreed price for natural gas delivered to the applicable generation facility over a contractually agreed period of time. Fuel for electric generation from coal and oil product inventories are recognized at the applicable weighted average inventory cost of volumes consumed.
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Environmental product costs primarily include RGGIs and other emission product compliance costs that are mandated by certain states. The estimated cost of compliance is accrued at the time an obligation under the applicable terms of each state's environmental compliance program arises.
Realized gains and losses on commodity derivative instruments primarily include the settlements of financial and physical fuel contracts utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Fuel and energy purchases” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Operating Revenues and Revenue Recognition” above for additional information on realized gains and losses on derivative instruments presented as “Energy and other revenues” on the Consolidated Statements of Operations.
Nuclear fuel amortization. Nuclear fuel-related costs, including procurement of uranium, conversion, enrichment, fabrication and assemblies, are capitalized and presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets and presented as a cash outflow within the investing activities section on the Consolidated Statements of Cash Flows. Such costs are amortized as the fuel is consumed using the units-of-production method and presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain fuel contracts and environmental product contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Operating Revenues and Revenue Recognition” above for additional information on unrealized gains and losses of derivative instruments presented as “Operating Revenues” on the Consolidated Statements of Operations.
Derivative Instruments. The fair value of derivative contracts required to be measured at fair value are presented as “Derivative instruments” within assets or liabilities on the Consolidated Balance Sheets. The primary type of derivative instruments utilized are commodity derivatives. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the inputs and assumptions are generally observable.
In most instances, master netting agreements govern derivative transactions between parties and contain certain provisions for setoff rights. The fair value of derivative instruments is presented net of setoff rights and cash collateral deposits. The fair value of commercial contracts that are not subject to netting and (or) collateral provisions is presented gross. Prior to Emergence, the fair value of derivative instruments presented on the Consolidated Balance Sheets was presented gross of setoff rights and cash collateral deposits exchanged between parties under such arrangements.
Unrealized gains or losses associated with a derivative instrument that economically hedges certain risks but where qualified cash flow hedge accounting is not elected or not met are presented on the Consolidated Statements of Operations in the period when such gains or losses arise. As there are no derivatives where qualified hedge accounting has been elected, changes in the fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments,” as a component of either “Operating Revenues” or “Energy Expenses” on the Consolidated Statements of Operations in a manner consistent with the presentation of net realized gains and losses. See “Operating Revenues” and “Energy Expenses” above for a discussion of net realized gains and losses on commodity derivatives. The cumulative net gains or losses for interest rate contracts are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Notes 2 and 11 for additional information on the presentation of derivative contracts and fair value measurements, respectively.
Operation, Maintenance and Development. The costs of removal, repairs, maintenance, and other operating costs, pre-commercial development activities, and salaries and benefits for operations personnel that each do not meet capitalization criteria are recognized as an expense when incurred. Materials and supplies inventories are recognized as an expense at the weighted average cost of materials consumed as they are used for repairs and maintenance. Costs for pre-commercial development stages of certain projects that are not capitalized as “Property, plant and equipment, net” on the Consolidated Balance Sheets and recurring operational and maintenance activities are each presented as “Operation, maintenance and development” on the Consolidated Statements of Operations. Development expenses incurred were primarily related to pre-commercial activities at Nautilus and hyperscale construction activities at Cumulus Digital.
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Stock-Based Compensation. TEC grants performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors. The fair value of PSUs is estimated on the grant date utilizing a Monte Carlo Valuation Model, which contains significant unobservable inputs that are believed to be consistent with those used by principal market participants. The fair value of RSUs is derived from the closing price of TEC common stock at the grant date. Forfeitures are recognized as they occur. Unvested PSUs and RSUs are entitled to dividends or dividend equivalents, which are accrued and distributed to award recipients at the time such awards vest. Dividends and dividend equivalents are subject to the same vesting and forfeiture provisions as the underlying awards. Liability classified awards that settle in cash, or include an election to be settled in cash, are remeasured at fair value through settlement or maturity and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets. Stock-based compensation expense is recognized for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Stock-based compensation expense is presented as “General and administrative” on the Consolidated Statements of Operations.
See Note 13 for additional information on stock-based compensation.
Income Taxes. TEC and its subsidiaries file a consolidated U.S. federal income tax return. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis, tax credits and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income in the period that includes the enactment date. Valuation allowances are recognized to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not to be realized. Disproportionate income tax effects are removed from AOCI when the circumstance upon which they are premised ceases to exist.
The financial statement effect of a tax position is recognized when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. A previously recognized tax position is reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Interest and penalties from tax uncertainties are presented as “Income tax benefit (expense)” on the Consolidated Statements of Operations.
See Note 4 for additional information on income taxes.
Concentrations of Credit Risk. Concentrations of credit risk exist primarily within cash and cash equivalents, receivables, and commodity derivative assets. Cash and cash equivalents are generally held in accounts where the amounts deposited exceed the maximum deposit insurance provided by the Federal Deposit Insurance Corporation. Cash and cash equivalents and restricted cash balances are primarily deposited in accounts with major financial institutions with investment grade credit ratings. In certain instances, funds are invested in highly liquid U.S. Treasury securities or other obligations with original maturities of less than 90 days that are issued by or guaranteed by the U.S. Government. Concentrations of credit risk for receivables are primarily attributable to entities that reimburse Talen for certain capital expenditures and operating costs associated with jointly owned facilities. Concentrations of credit risk for commodity derivative assets are primarily attributable to unaffiliated investment grade counterparties which engage in energy marketing activities with Talen Energy Marketing. See Note 2 for additional information on concentrations of credit risk.
Cash and Cash Equivalents. Bank deposits, liquid investments, and other similar assets with original maturities of three months or less. Cash and cash equivalents, including cash deposits supporting the Company’s commodity exchange activities, that are contractually restricted are presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.
See Note 16 for additional information.
Accounts Receivable. Receivables primarily consist of amounts due from customers or other contract counterparties, net of any collection allowances. Uncollected receivables greater than 30 days past due are assessed for collectability based on a variety of factors that include, but are not limited to, customer credit worthiness, duration receivables are outstanding, and (or) historical collection experience. Management continuously assesses and considers current economic trends that might impact the amount of future credit losses. If it becomes known that a specific customer may not have the ability to settle its obligation that is not yet past due, such receivables are assessed for collectability. If these assessments indicate a receivable collection is remote, its carrying value is reduced through an allowance for doubtful accounts measured at management’s best estimate, and a charge is presented on the Consolidated Statements of Operations. If any portion of the original carrying value of the receivable is recovered, the allowance and the associated charge are reversed in the period of collection.
Inventory. Inventory consists of fuel for generation (primarily coal and fuel oil), materials and supplies, and environmental products each of which are valued at the lower of weighted average cost or net realizable value. See Note 5 for additional information on inventory.
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Investments in Debt and Equity Securities. The NDT holds investments in available-for-sale debt securities and equity securities, which are carried at fair value and presented as “Nuclear decommissioning trust funds” on the Consolidated Balance Sheets.
Unrealized gains and losses, net of income tax, on available-for-sale debt securities are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income in the period when such gains and losses arise. Realized gains and losses on available-for-sale debt securities are transferred from AOCI to “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when the sale of the security occurs. The specific identification method is used to calculate realized gains and losses on debt and equity securities. If an available-for-sale debt security's fair value declines below cost and the decline is determined to be other-than-temporary, the unrealized loss is recognized on the Consolidated Statements of Comprehensive Income in the period when such determination arises.
See Notes 6 and 11 for additional information on investments in debt and equity securities.
Property, Plant and Equipment. Expenditures for land, the construction of facilities, the addition or refurbishment of major equipment, and commercially viable new development projects are capitalized at cost. Such capitalized amounts include interest costs, where appropriate. Facilities, land, and other equipment acquired in a business combination are recognized at acquisition date fair value. In each case, such amounts are presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets. Reductions in the carrying value of PP&E are accumulated over the estimated useful life of each depreciable unit using group or straight-line depreciation methods. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. Generally, upon normal retirement of PP&E under the group depreciation method, the costs of such assets are retired against accumulated depreciation in the period of the retirement and no gain or loss is recognized. Any remaining carrying value of PP&E at its retirement date that depreciated under the straight-line depreciation method is presented as a loss within “Other operating income (expense), net” on the Consolidated Statements of Operations. Any remaining carrying value of PP&E at its sale date and any proceeds from the disposition are presented as a gain or loss net on the Consolidated Statements of Operations.
See Note 17 for information on recent business combinations.
See Note 7 for additional information on PP&E.
Impairment. PP&E used in operations are assessed for impairment when changes in facts and circumstances indicate the carrying value of the asset group may not be recoverable. Indicators of impairment may include changes in the economic environment, negative financial trends, physical damage to assets or management’s decisions regarding strategic initiatives. Where applicable, individual assets are grouped for impairment analysis 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. If there is an indication the carrying value of an asset group may not be recoverable, management reviews 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 carrying value of the asset group is written down to its estimated fair value. Impairment charges are presented as “Impairments” on the Consolidated Statements of Operations in the period in which the impairment condition arises. If facts and circumstances indicate that the carrying value of an asset under construction will have no future economic benefit, such amounts are presented on the Consolidated Statements of Operations in the period in which such projects are abandoned, canceled, or management otherwise determines the costs to be unrecoverable.
See Note 7 for information on impairments.
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Asset Retirement Obligations. A liability for an ARO or conditional ARO exists when a legal obligation arises from laws, regulations or other contractual requirements for the retirement of tangible long-lived assets. When an ARO liability is incurred, which is typically at asset construction or through assumption of the liability in connection with a business combination, it is initially recognized at fair value. Fair value measurements are estimated under a present value technique and are discounted using a credit-adjusted risk-free rate. Additionally, given the inherent uncertainty in estimating the amount of cash flows to settle an ARO liability or its settlement date, fair value estimates include a market risk premium and a range of possible cash flow outcomes, where applicable. At the initial recognition, the effects on the Consolidated Balance Sheets include: (i) an increase to “Asset retirement obligations and accrued environmental costs” for the portion of ARO to be settled after one year and (or) “Other current liabilities” for the portion of the ARO to be settled within one year; and (ii) an offsetting increase to “Property, plant and equipment, net” for the asset retirement capitalized cost. Estimated future ARO cash expenditures and settlement dates are reviewed periodically to identify any required amendments to the carrying value of each ARO liability.
ARO liabilities increase through the recognition of accretion expense to recognize changes in the obligation due to the passage of time. The asset retirement capitalized cost is depreciated at a rate consistent with the useful life of the associated long-lived asset. The depreciation of the asset retirement capitalized cost and the accretion of the ARO liability are each presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. An ARO liability amendment associated with a long-lived asset that is not fully impaired or depreciated is recognized through an adjustment to the ARO liability and the asset retirement capitalized cost. Any revision to the asset retirement capitalized cost is generally depreciated over the remaining life of the associated long-lived asset. An ARO liability amendment associated with a fully impaired or depreciated asset is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. At settlement, a gain or loss will arise if the cash expenditures to settle the ARO liabilities are different than the carrying values. Such gains or losses are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
A conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement is conditional on a future event that may or may not be within the entity’s control, including legal or regulatory requirements. There may also be instances when there is no available information regarding the ultimate ARO settlement timing or the fair value of the obligation may not be reasonably estimable. If sufficient information becomes available to reasonably estimate the fair value of the liability for an ARO or a conditional ARO, a liability is recognized in the period in which it is determined.
See Note 8 for additional information on AROs.
Contingencies. Potential loss contingencies may result from environmental remediation, litigation claims, regulatory penalties or other events. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. Loss contingencies are recognized at management's best estimate, which may be discounted, where appropriate. Loss contingencies exclude estimates for any legal fees, which are recognized as incurred when the legal services are performed. Additionally, pursuant to federal and state legislation, the Company assesses the funding associated with certain legacy health care benefit plans for retired mine workers and recognizes expected funding shortfall, if any, as a contingent liability. See Note 9 for additional information on loss contingencies.
Business interruption insurance proceeds are considered gain contingencies and not recognized until realized.
Debt. Proceeds received on the issuance of new term loans, secured notes, unsecured notes, bonds, and similar indebtedness are presented as “Long-term debt” or “Long-term debt, due within one year” on the Consolidated Balance Sheets. Interest incurred as paid-in-kind, whether accrued or capitalized as additional principal are presented as “Long-term debt” with the associated outstanding amounts of indebtedness. Costs incurred to issue new indebtedness and any original issuance discounts or premiums are deferred at issuance on the Consolidated Balance Sheets and presented together with the associated outstanding principal amounts of indebtedness.
Interest accrues on outstanding principal amounts of indebtedness based on contractually determined rates during each period. Costs incurred for the issuance of indebtedness and any original issuance discounts or premiums are subsequently amortized through the expected maturity date of the associated indebtedness under the effective interest rate method and are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
Gains and losses on the: (i) early redemption of indebtedness; or (ii) early termination and (or) reduction of revolving credit facility committed capacity are presented as a gain or loss on the Consolidated Statements of Operations. Such amounts include the proportional derecognition of any deferred financing costs, fees, discounts, and (or) premiums associated with the indebtedness.
Direct cash borrowings under secured lines of credit, revolving credit facilities, and similar indebtedness are presented as a current liability on the Consolidated Balance Sheets. Costs incurred to issue new arrangements are deferred and presented as “Other current assets” or “Other noncurrent assets” on the Consolidated Balance Sheets. Interest accrues on direct cash borrowings and LCs based on contractually determined rates during each period.
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Costs incurred to issue new arrangements are subsequently amortized through the expected expiration of the associated arrangement under the straight-line method. Commitment fees on available but unused credit facility capacity are expensed as incurred. Such costs are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Note 10 for additional information on debt.
Postretirement Benefit Obligations. Certain Talen subsidiaries sponsor various defined benefit pension plans and other postretirement benefit plans. Gains and losses, net of income tax, that arise and are not a component of net periodic defined benefit costs are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income. Service cost is presented as “Operation, maintenance and development” while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
Following Emergence, actuarial gains and losses in excess of the greater of 10% of the plan's projected benefit obligation or the market-related value of plan assets are amortized over (i) the expected average remaining service period of active plan participants for active plans; or (ii) the average future remaining lifetime of the plan participants of frozen plans. Prior to Emergence, Talen used an accelerated amortization method for the recognition of gains and losses for defined benefit pension plans: (i) actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants; and (ii) actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants.
Following Emergence, a spot rate curve that represents a portfolio of high-quality corporate bonds is used to develop the discount rate utilized to measure the projected benefit obligations and service costs for benefit plans. Prior to Emergence, a bond matching methodology was utilized, based on a specific portfolio of bonds that closely match the overall cash flow timing and duration of the benefit plans.
See Note 12 for additional information on the plans and the accounting for defined benefits.
Treasury Stock and Retirement of Treasury Shares. Share repurchases are accounted for under the cost method, which recognizes the entire cost of the acquired stock, including transaction costs and excise tax, as a reduction in additional paid-in-capital and are presented as “Treasury stock” on the Consolidated Balance Sheets. Share repurchases are recognized on a trade date basis when we are contractually obligated to purchase the shares. Treasury shares are retired on the settlement date of the transaction. At retirement, the common stock balance is reduced for the par value of the shares. The excess of the acquisition cost of repurchased shares over the par value is recognized in additional paid-in capital (up to the amount credited to additional paid-in capital upon original issuance of the shares), with any remaining cost deducted from retained earnings.
Recently Adopted Accounting Pronouncements
There have been no recently adopted accounting pronouncements that had a material effect on the Company’s financials statements and (or) disclosures.
Recent Accounting Pronouncements Not Yet Adopted
ASU 2024-03. In November 2024, the FASB issued ASU 2024-03, Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses. This ASU requires public companies to disclose, in the notes to financial statements, specified information about certain costs and expenses at each interim and annual reporting period. This ASU is effective for annual reporting periods beginning after December 15, 2026. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
ASU 2025-11. In December 2025, the FASB issued ASU 2025-11, Interim Reporting (Topic 270): Narrow-Scope Improvements. This ASU provides clarification to certain elements of Topic 270, but does not change the fundamental nature of interim reporting or expand or reduce current interim disclosure requirements. This ASU is effective for annual periods beginning after December 15, 2027, and interim periods within those annual periods. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
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2. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk, and interest rate risk. The hedging strategies deployed by our commercial and treasury organizations manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors, including the risk committee, and management have established procedures to monitor, measure, and manage hedging activities and credit risk in accordance with the risk policy.
Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk, and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future earnings 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: (i) seasonal changes in demand; (ii) weather conditions; (iii) available regional load-serving supply; (iv) regional transportation and (or) transmission availability; (v) market liquidity; and (vi) federal, regional, and state regulations.
Within the parameters of our risk policy, we generally utilize 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.
Open commodity purchase (sales) derivatives range in maturity through 2027. The net notional volumes of commodity derivatives were:
| Successor | ||||||||||||||
December 31, 2025 (a) | December 31, 2024 (a) | |||||||||||||
| Power (MWh) | ( | ( | ||||||||||||
| Natural gas (MMBtu) | ||||||||||||||
| Emission allowances (tons) | ||||||||||||||
__________________
(a)The volumes may be different than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
Interest Rate Risk. Talen is 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.
Open interest rate derivatives range in maturity through 2029. The net notional volumes of open interest rate derivatives were:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
Interest rate (in millions) | $ | $ | ||||||||||||
Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, and derivative instruments. The maximum amount of credit exposure associated with financial assets is equal to the carrying value of such assets. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default, and executing master netting arrangements that permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, LCs, and credit insurance may be employed to mitigate credit risk.
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Cash and cash equivalents are placed in depository accounts or high-quality, short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity, and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of December 31, 2025 (Successor) and 2024 (Successor).
As of December 31, 2025 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $652 million and its credit exposure including such netting effects was $47 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements and congestion products are subject to applicable market controls, the ten largest single net credit exposures account for 83 % of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, LCs, or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in Talen’s credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of December 31, 2025 (Successor) and 2024 (Successor).
Derivative Instrument Presentation
Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
| Successor | ||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||||||
| Commodity contracts | $ | $ | $ | $ | ||||||||||||||||||||||
| Interest rate contracts | ||||||||||||||||||||||||||
| Total current derivative instruments | ||||||||||||||||||||||||||
| Commodity contracts | ||||||||||||||||||||||||||
| Interest rate contracts | ||||||||||||||||||||||||||
| Total non-current derivative instruments | $ | $ | $ | $ | ||||||||||||||||||||||
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy and other revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. Changes in the fair value and realized settlements on interest rate derivative instruments are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations. See Note 11 for additional information on fair value of commodity and interest rate derivatives.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of December 31, 2025 (Successor) and 2024 (Successor).
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Item 8. Table of Contents
The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:
| Gross Derivative Instruments | Eligible for Offset | Net Derivative Instruments | Collateral (Posted) Received | Net Amounts | ||||||||||||||||||||||||||||
| December 31, 2025 (Successor) | ||||||||||||||||||||||||||||||||
| Assets | $ | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||
| Liabilities | ( | ( | ||||||||||||||||||||||||||||||
| December 31, 2024 (Successor) | ||||||||||||||||||||||||||||||||
| Assets | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||
| Liabilities | ( | ( | ||||||||||||||||||||||||||||||
Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Realized gain (loss) on commodity contracts | |||||||||||||||||||||||||||||
Energy revenues (a) | $ | $ | $ | $ | |||||||||||||||||||||||||
Fuel and energy purchases (a) | ( | ( | ( | ( | |||||||||||||||||||||||||
| Unrealized gain (loss) on commodity contracts | |||||||||||||||||||||||||||||
Operating revenues (b) | ( | ||||||||||||||||||||||||||||
Energy expenses (b) | ( | ( | ( | ||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | |||||||||||||||||||||||||||||
| Interest expense and other finance charges | ( | ( | |||||||||||||||||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.
3. Revenue
The components of operating revenues for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Electricity sales and ancillary services, ISO/RTO | $ | $ | $ | $ | |||||||||||||||||||||||||
| Capacity revenues | |||||||||||||||||||||||||||||
| Physical electricity sales, bilateral contracts, other | |||||||||||||||||||||||||||||
| Other revenue from customers | |||||||||||||||||||||||||||||
| Total revenue from contracts with customers | |||||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | |||||||||||||||||||||||||||||
| Nuclear PTC | |||||||||||||||||||||||||||||
| Other revenue | |||||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | $ | |||||||||||||||||||||||||
Accounts Receivable
“Accounts receivable” presented on the Consolidated Balance Sheets were:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Customer accounts receivable | $ | $ | ||||||||||||
| Other accounts receivable | ||||||||||||||
| Accounts receivable | $ | $ | ||||||||||||
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Item 8. Table of Contents
During the years ended December 31, 2025 (Successor), and 2024 (Successor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 2 for additional information on Talen’s credit risk on the carrying value of its receivables.
Future Performance Obligations
Talen’s estimated future fixed fee performance obligations primarily include capacity volumes awarded, net of capacity repurchases by the Company, through PJM BRAs and incremental PJM capacity auctions. See Note 9 for additional information on the PJM BRAs.
As of December 31, 2025 (Successor), future performance obligations that were unsatisfied or partially unsatisfied were:
| 2026 | 2027 | 2028 (a) | 2029 (a) | 2030 (a) | ||||||||||||||||||||||||||||
| Future performance obligations | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
__________________
(a)As PJM BRAs have not yet occurred for periods after the 2027/2028 PJM Capacity Year, there are no future performance obligations after May 31, 2028.
Brandon Shores and H.A. Wagner RMR Agreements
In May 2025, the FERC approved each of the Brandon Shores and H.A. Wagner RMR agreements, under which: (i) Talen will operate the generation facilities in accordance with such arrangements from June 1, 2025 through May 31, 2029, or until such time as the necessary third-party transmission upgrades are placed into service; (ii) Brandon Shores will earn annual fixed-cost payments of $145 million ($312 /MWd), inclusive of a $5 million per year unit performance “hold back;” (iii) H.A. Wagner will earn annual fixed-cost payments of $35 million ($137 /MWd), inclusive of a $2.5 million per year unit performance “hold back;” and (iv) each facility will receive separate reimbursement for variable costs and approved project investments. In August 2025, the Maryland Office of People’s Counsel filed an appeal of the FERC’s order approving the Brandon Shores and H.A. Wagner RMR agreements. Talen has intervened in that proceeding and plans to participate.
4. Income Taxes
The components of “Income tax benefit (expense)” for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Federal | $ | $ | ( | $ | $ | ( | |||||||||||||||||||||||
| State | ( | ( | |||||||||||||||||||||||||||
| Current income taxes | ( | ( | |||||||||||||||||||||||||||
| Federal | ( | ( | ( | ||||||||||||||||||||||||||
| State | ( | ( | |||||||||||||||||||||||||||
| Deferred income taxes | ( | ( | ( | ||||||||||||||||||||||||||
| Income tax benefit (expense) | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||||||||
| Income (loss) before income taxes | ( | ||||||||||||||||||||||||||||
| Effective income tax rate | ( | % | % | % | % | ||||||||||||||||||||||||
Current tax receivable presented as “Other current assets” on the Consolidated Balance Sheets were $35 million as of December 31, 2025 (Successor) and non-material as of December 31, 2024 (Successor). Current tax liabilities presented as “Other current liabilities” on the Consolidated Balance Sheets were non-material as of December 31, 2025 (Successor) and $53 million as of December 31, 2024 (Successor).
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Item 8. Table of Contents
Effective Tax Rate Reconciliations
The following table presents required disclosures pursuant to ASU 2023-09 and reconciles the U.S. federal statutory tax amount and rate to our effective tax amount and rate for the year ended December 31, 2025 (Successor):
| Successor | ||||||||||||||
| Year Ended December 31, 2025 | ||||||||||||||
| Federal income tax at statutory tax rate | $ | |||||||||||||
State income taxes, net of federal benefit (a) | ||||||||||||||
| Nontaxable or nondeductible items: | ||||||||||||||
| Stock-based compensation | ( | ( | ||||||||||||
| Nuclear PTC | ( | ( | ||||||||||||
| Other permanent differences | ( | ( | ||||||||||||
| Changes in valuation allowances | ( | ( | ||||||||||||
| Other adjustments: | ||||||||||||||
| Return to provision | ||||||||||||||
| Tax on NDT | ( | ( | ||||||||||||
| Income tax benefit (expense) | $ | ( | ( | |||||||||||
__________________
(a)Pennsylvania state income taxes comprised the majority of the tax effect in this category.
The following table presents the required disclosures prior to our adoption of ASU 2023-09 and reconciles the income tax benefit (expense) at our statutory rate to the income tax benefit (expense) at our effective rate for the following periods:
| Successor | Predecessor | ||||||||||||||||||||||
| Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||
Income tax benefit (expense) computed at the federal income tax statutory tax rate of | $ | ( | $ | ( | $ | ( | |||||||||||||||||
| Income tax increase (decrease) due to: | |||||||||||||||||||||||
| Change in valuation allowance | ( | ||||||||||||||||||||||
| State income taxes, net of federal benefit | ( | ( | |||||||||||||||||||||
| Nuclear PTC | |||||||||||||||||||||||
| Nuclear decommissioning trust taxes | ( | ( | ( | ||||||||||||||||||||
| Reorganization adjustments | ( | ||||||||||||||||||||||
| Return to provision | |||||||||||||||||||||||
| Permanent differences | ( | ||||||||||||||||||||||
| Other | ( | ||||||||||||||||||||||
| Income tax benefit (expense) | $ | ( | $ | ( | $ | ( | |||||||||||||||||
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Item 8. Table of Contents
Deferred Taxes
The components of deferred tax liabilities and deferred tax assets were:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Property, plant and equipment, net | $ | $ | ||||||||||||
| Nuclear decommissioning trust | ||||||||||||||
| Unrealized gain on qualifying derivatives | ||||||||||||||
| Other | ||||||||||||||
| Deferred tax liabilities | ||||||||||||||
| Less: | ||||||||||||||
| Federal net operating loss carryforwards | ||||||||||||||
| Interest limitation carryforward | ||||||||||||||
Acquired fuel supply contract liabilities (a) | ||||||||||||||
| Accrued liabilities | ||||||||||||||
| Accrued pension costs | ||||||||||||||
| State net operating loss carryforwards | ||||||||||||||
| Unrealized loss on qualifying derivatives | ||||||||||||||
| Other | ||||||||||||||
| Deferred tax assets | ||||||||||||||
| Valuation allowance | ( | |||||||||||||
| Deferred tax liabilities, net | $ | $ | ||||||||||||
__________________
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
Federal, indefinite expiration, limited to annual utilization of 80% | $ | $ | ||||||||||||
| State, expirations 2026 - 2041 | ||||||||||||||
See “Emergence from Restructuring” below for information on limitations on our NOLs.
Income Taxes Paid Net of Refunds
The amounts of income taxes paid, net of refunds, were:
| Successor | ||||||||
| Year Ended December 31, 2025 | ||||||||
| US Federal - Corporate | $ | |||||||
| US Federal - NDT | ||||||||
| Total federal tax | ||||||||
| Pennsylvania | ||||||||
Other states (a) | ||||||||
| Total state tax | ||||||||
Total | $ | |||||||
__________________
(a)Consists primarily of New Jersey, Maryland, and Texas.
Unrecognized Tax Benefits
Unrecognized tax benefits as of December 31, 2025 (Successor) and 2024 (Successor) were a non-material amount. All tax returns filed for years December 31, 2022 and forward are open to examination by the relevant taxing authorities.
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Item 8. Table of Contents
Emergence from Restructuring
The Company evaluated, including the change in control resulting from its Emergence from bankruptcy, the tax impact of its Restructuring as described in Note 19. As part of the Restructuring, a substantial portion of the Company’s prepetition debt was extinguished, resulting in cancellation of debt income (“CODI”). A taxpayer emerging from bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount of CODI realized. The Company realized CODI of $1.2 billion, which resulted in a partial reduction in tax basis in PP&E assets.
Upon Emergence, the Company experienced an ownership change under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”). The Code’s Sections 382 and 383 impose limitations on the ability of a company to utilize tax attributes after experiencing an ownership change. States generally have similar tax attribute limitation rules following an ownership change. The Company also applied fresh start accounting. As a result, deferred tax assets and liabilities were adjusted based on the Successor GAAP financial statements. See Note 20 for additional information on fresh start accounting.
Valuation Allowance
Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit the use of existing deferred tax assets. Negative evidence in the form of cumulative losses are no longer present as the Company has returned to profitability. The existence of objective positive evidence allows for consideration of other subjective evidence, including (but not limited to) Talen’s projections for future income which would allow for utilization of all net operating losses and interest limitation carryforwards.
As a result of the assessment, it was determined that it is more likely than not that all federal and most state deferred tax assets will be fully utilized by future taxable income. As of December 31, 2025 (Successor), the Company’s valuation allowance was non-material.
As of December 31, 2024 (Successor), it was more likely than not that federal and state deferred tax assets would be fully utilized by future taxable income. The entire federal and state valuation allowances were released, resulting in a $128 million tax benefit. For the period from May 18 through December 31, 2023 (Successor), a $43 million tax expense was recognized for the increase in federal and state valuation allowances based on the realizability of deferred tax assets. For the period from January 1 through May 17, 2023 (Predecessor), a $129 million benefit was recognized for the reduction in federal and state valuation allowances. The change in valuation allowance estimates was the result of tax attribute reduction from the cancellation of debt income that was realized upon Emergence.
Sale of Nuclear Production Tax Credits
In September 2025, Nuclear PTCs with an aggregate carrying value of $202 million were sold to an unaffiliated third party for cash consideration of $191 million. The $11 million difference between the carrying value and the sales price resulted in loss presented in “Other operating income (expense), net” on the Consolidated Statements of Operations. The Company’s Nuclear PTCs remaining after the sale were utilized in reducing federal income taxes payable.
One Big Beautiful Bill Act
5. Inventory
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Coal | $ | $ | ||||||||||||
| Oil products | ||||||||||||||
| Fuel inventory for electric generation | ||||||||||||||
| Materials and supplies, net | ||||||||||||||
| Environmental products | ||||||||||||||
| Inventory, net | $ | $ | ||||||||||||
Inventory net realizable value and obsolescence charges on coal and fuel oil inventories are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. Such non-cash charges were non-material for the year ended December 31, 2025 (Successor), the year ended December 31, 2024 (Successor), the period from May 18 through December 31, 2023 (Successor), and $37 million for the period from January 1 through May 17, 2023 (Predecessor).
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During the period from January 1 through May 17, 2023 (Predecessor), $24 million of adjustments were related to Brandon Shores coal and materials and supplies inventories. See Note 7 for additional information on the Brandon Shores recoverability assessment.
6. Nuclear Decommissioning Trust Funds
| Successor | ||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | |||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | — | $ | — | $ | $ | $ | — | $ | — | $ | ||||||||||||||||||||||||||||||||||||||
| Equity securities | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
| NDT Funds | $ | $ | $ | ( | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||
See Note 11 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of December 31, 2025 (Successor) and 2024 (Successor).
As of December 31, 2025 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate fair value of available-for-sale debt securities with unrealized losses as of December 31, 2025 (Successor) was:
| Fair Value | Unrealized Losses | |||||||||||||
| Corporate debt securities | $ | $ | ( | |||||||||||
| Municipal debt securities | ( | |||||||||||||
| U.S. Government debt securities | ( | |||||||||||||
| Debt securities in unrealized loss position | $ | $ | ( | |||||||||||
As of December 31, 2025 (Successor), the aggregate fair value of debt securities in a loss position for a duration of one year or longer were $101 million and the unrealized losses were non-material.
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Maturities within one year | $ | $ | ||||||||||||
| Maturities within two to five years | ||||||||||||||
| Maturities thereafter | ||||||||||||||
| Debt securities, fair value | $ | $ | ||||||||||||
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
Sales proceeds of NDT funds investments (a) | $ | $ | $ | $ | |||||||||||||||||||||||||
| Gross realized gains | |||||||||||||||||||||||||||||
| Gross realized losses | ( | ( | ( | ( | |||||||||||||||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.
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Item 8. Table of Contents
The net unrealized gains and losses recognized associated with equity securities still held at the end of the reporting periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Equity securities, unrealized gains (losses) | $ | $ | $ | $ | |||||||||||||||||||||||||
7. Property, Plant and Equipment
| Successor | ||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (years) | Gross Value | Accumulated Depreciation | Carrying Value | Gross Value | Accumulated Depreciation | Carrying Value | ||||||||||||||||||||||||||||||||||||||
| Electric generation | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
| Nuclear fuel | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Other property and equipment | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Capitalized software | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Construction work in progress | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
Depreciation expense (a) | $ | $ | $ | $ | |||||||||||||||||||||||||
Amortization expense (b) | |||||||||||||||||||||||||||||
Accretion expense (c) | |||||||||||||||||||||||||||||
| Other | ( | ||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | $ | $ | $ | $ | |||||||||||||||||||||||||
__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 8 for additional information.
The cost of nuclear fuel and the amortization of nuclear fuel intangible assets are presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Amortization expense related to nuclear fuel contract intangible assets was non-material for the year ended December 31, 2025 (Successor), $33 million for the year ended December 31, 2024 (Successor), and $53 million for the period from May 18 through December 31, 2023 (Successor). The carrying value of nuclear fuel contract intangible assets was non-material as of December 31, 2025 (Successor) and 2024 (Successor).
Jointly Owned Facilities
Certain of Talen's subsidiaries own undivided interests in jointly owned electric generation facilities and related assets. These generation facilities and other assets are maintained and operated pursuant to their joint ownership participation and operating agreements. Under such arrangements, each participant is responsible for funding its proportionate share of costs and is entitled to its proportionate share of electric generation and (or) other attributes of the relevant jointly owned facilities. Talen's proportionate share of revenues and expenses for its undivided interests is presented within the Consolidated Statements of Operations.
Talen owns undivided interest of 90 % in Susquehanna, 22.22 % in Conemaugh, and 12.34 % in Keystone. See below for information regarding the ownership of Colstrip in Montana. The carrying values of Colstrip, Conemaugh, and Keystone were non-material as of December 31, 2025 (Successor) and 2024 (Successor).
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The proportionate share of “Property, plant and equipment, net” related to Susquehanna presented on the Consolidated Balance Sheets was:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Ownership interest | ||||||||||||||
| Electric generation | $ | $ | ||||||||||||
| Nuclear fuel | ||||||||||||||
| Other property and equipment | ||||||||||||||
| Capitalized software | ||||||||||||||
| Construction work in progress | ||||||||||||||
| Proportionate property, plant and equipment, cost | ||||||||||||||
| Less: accumulated depreciation and amortization | ||||||||||||||
| Proportionate property, plant and equipment, net | $ | $ | ||||||||||||
Talen Montana. Talen Montana owns 30 % of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in a joint-owner sharing agreement which governs each party’s responsibilities and rights whereby Talen Montana is responsible for 15 % of the total operating costs and expenditures of Colstrip Unit 3 and 15 % of Colstrip Unit 4. Accordingly, it is entitled to 15 % of the available generation from each of these units. In January 2020, Talen Montana and the other co-owner of Colstrip Units 1 and 2 permanently retired the units. Talen Montana is responsible for 50
Equity Method Investments
Talen holds equity interests in Conemaugh Fuels and Keystone Fuels equal to its respective undivided ownership interests in Conemaugh and Keystone. Conemaugh Fuels and Keystone Fuels were formed to purchase coal and sell it to Conemaugh and Keystone. Additionally, they may sell coal to any entity that manufactures or produces synthetic fuel from coal for resale to Conemaugh and Keystone. The aggregate affiliated fuel purchases by Talen from Conemaugh Fuels and Keystone Fuels is presented as “Fuel and energy purchases” on the Consolidated Statements of Operations. Talen’s aggregate fuel purchases for Conemaugh and Keystone Fuels were $48 million for the year ended December 31, 2025 (Successor), $35 million for the year ended December 31, 2024 (Successor), $23 million for the period from May 18 through December 31, 2023 (Successor) and $14 million for the period from January 1 through May 17, 2023 (Predecessor).
Nautilus Derecognition
In connection with the revisions to the AWS PPA (i) in June 2025, the Company agreed to cease use of the Nautilus facility, and (ii) in September 2025, the facility lease between the Company and AWS, and the related submetering and supply agreements, were terminated and AWS took possession of the existing facility structures. Accordingly, during the year ended December 31, 2025 (Successor), the Company derecognized approximately: (i) $15 million of structures and buildings presented as “Property, plant and equipment, net;” (ii) an aggregate $44 million of contract intangible assets and lease right-of-use assets presented as “Other noncurrent assets;” (iii) $10 million of lease liabilities presented as “Other current liabilities;” and (iv) an aggregate $57 million contractual obligations and lease obligations presented as “Other noncurrent liabilities.” The resulting net gain of $8 million is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
Brandon Shores Impairment
Brandon Shores Asset Group. In the first quarter 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group.
The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its PP&E to its estimated fair value. The estimated fair value of the asset group was determined by a discounted cash flow technique that utilized significant unobservable inputs including an 11 % discount rate. We believe that the utilized discount rate and other discounted cash flow assumptions are consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for the Brandon Shores asset group, including but not limited to estimated available future generation volumes and useful lives, capacity prices, energy prices, operating costs, capital expenditures, and environmental costs. Accordingly, for the period from January 1 through May 17, 2023 (Predecessor), a $361 million non-cash pre-tax impairment charge on the asset group’s undepreciated PP&E is presented as “Impairments” on the Consolidated Statements of Operations.
In May 2025, Brandon Shores and H.A. Wagner consummated RMR agreements which requires the facilities to operate until certain third-party transmission upgrades are placed into service. See Note 3 for additional information on the Brandon Shores and H.A. Wagner RMR agreements.
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Item 8. Table of Contents
8. Asset Retirement Obligations and Accrued Environmental Costs
Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation. Most of these obligations, except remediation of some ash impoundments, are not expected to be paid until several years, or decades, in the future. The Company’s most significant obligations are associated with the: (i) decommissioning of Susquehanna, which the NDT is expected to fund; and (ii) coal ash disposal units of legacy coal-fired generation facilities which, for certain obligations, the Company has posted surety bonds (some of which have been collateralized with LCs). The carrying value of these AROs include assumptions of estimated future retirement and remediation cash expenditures, cost escalation rates, probabilistic cash flow models, and discount rates.
The Company may be required to revise or recognize new AROs as a result of regulatory changes by the NRC, EPA, Montana Department of Environmental Quality (the “MDEQ”) or other regulatory entities. Additionally, revisions may result from scope of work amendments to remediation activities as well as changes to remediation costs and other assumptions. If the assumptions underlying any ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated.
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Asset retirement obligations | $ | $ | ||||||||||||
| Accrued environmental costs | ||||||||||||||
| Total asset retirement obligations and accrued environmental costs | ||||||||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | ||||||||||||||
| Asset retirement obligations and accrued environmental costs due after one year | $ | $ | ||||||||||||
__________________
(a)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
The changes of the ARO carrying value during the period were:
| Successor | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Carrying value January 1, | $ | $ | ||||||||||||
| Obligations settled | ( | ( | ||||||||||||
| Accretion expense | ||||||||||||||
| Changes in estimates and (or) settlement dates | ( | ( | ||||||||||||
| Obligations incurred | ||||||||||||||
| Carrying value, December 31, | $ | $ | ||||||||||||
The disaggregation of ARO carrying values on the Consolidated Balance Sheets was:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
Nuclear (a) | $ | $ | ||||||||||||
Non-nuclear (b) | ||||||||||||||
| Carrying value | $ | $ | ||||||||||||
__________________
(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 6 for additional information on the NDT.
(b)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with LCs; or (ii) partially prefunded under phased installment agreements.
Nuclear AROs
Each joint owner of Susquehanna is obligated to fund their proportionate share of Susquehanna's ARO. Talen’s proportionate share of decommissioning activities will be funded from the NDT when decommissioning commences in connection with the expiration of Susquehanna’s licenses. The licenses for Susquehanna Unit 1 and Unit 2 expire in 2042 and 2044, respectively, and can be extended subject to NRC approval. The NRC has jurisdiction over the decommissioning of nuclear power generation facilities and requires minimum decommissioning funding based upon a formula. Under the most recent calculation in 2024, the NDT exceeds the NRC's minimum funding requirements. Each joint owner of Susquehanna is obligated to fund their proportionate decommissioning costs if their respective nuclear decommissioning trusts do not contain sufficient funds. We believe the NDT will be adequate to fund the Company’s proportionate share of decommissioning costs. As of December 31, 2025 (Successor), the fair value of the NDT was $1.9 billion and the carrying value the Company’s proportionate share of the Susquehanna ARO, which is discounted under a present value technique, was $272 million. See Note 1 for additional information on the measurement of AROs.
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Non-nuclear AROs
Non-nuclear AROs are primarily comprised of remediation activities associated with legacy coal-fired generation facilities, particularly Colstrip, Brunner Island, and Montour and includes activities, among others, such as remediation of coal piles, wastewater basins, and ash impoundments and structure removal.
Talen Montana. Talen Montana’s has significant AROs associated with its proportionate share of remediation, closure and decommissioning costs for coal ash impoundments at Colstrip. Due to the expected timing and scope of anticipated remediation activities, actual cash expenditures associated with these obligations are expected to be material over the next several years and then at a reduced spending level for several decades. Talen Montana, along with the other co-owners of Colstrip, periodically work with the MDEQ to update the scope of required remediation, the scope of closure and decommissioning activities, and the associated estimate of the costs, including the amount of necessary financial assurance necessary to backstop these obligations. Talen Montana's decommissioning and environmental remediation is expected to be paid by funds available to Talen Montana at the time of decommissioning.
Future adjustments may be required to the Talen Montana ARO estimates due to the ongoing remediation requirements under MDEQ obligations and the EPA CCR Rule. See Note 9 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip. Talen Montana's estimate of its proportionate share of the AROs, discounted using a credit adjusted risk-free rate, was $90 million and $98 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.
Conditional AROs. As of December 31, 2025 (Successor), the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined. See Note 9 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work.
Certain subsidiaries of the Company have legal retirement obligations associated with the removal, disposal, and (or) monitoring of asbestos-containing material at certain generation facilities. Given that the ultimate volume of asbestos-containing material is not yet known, the fair value of these obligations cannot be reasonably estimated. These obligations will be recognized upon a change in economic events or other circumstances which enables the fair value to be estimable.
Accrued Environmental Costs
Under the Pennsylvania Clean Streams Law, a Talen subsidiary is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent acid mine drainage at this site. Liabilities related to the remediation were $20 million and $21 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively, and were presented as “” and “Asset retirement obligations and accrued environmental costs” on the Consolidated Balance Sheets. Such liabilities were discounted based on a credit adjusted risk-free rate that was in existence at the time of initial liability recognition of 8.4 %. The undiscounted amount of the liabilities was $30 million and $32 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively.
9. Commitments and Contingencies
Legal, Regulatory, and Environmental Matters
We are regularly subject to various legal, regulatory, and environmental matters in connection with our business. While we believe we have meritorious positions and will continue to vigorously defend our positions in these matters, we may not be successful in our efforts, and we cannot predict the effect of an adverse outcome of any such matter. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal, regulatory, and environmental matters and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding any matter specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial. Unless otherwise disclosed below, we are unable to predict the outcome of any matter discussed below or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that the outcome of any such matter, including market modifications, could materially impact our business, financial condition, results of operations, cash flows, and (or) liquidity.
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.
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Brunner Island CCR Litigation. In April 2025, the Center for Biological Diversity (the “CBD”) filed a citizen suit in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, have failed to comply with groundwater monitoring and corrective action requirements at Brunner Island’s Ash Basin 5 and have therefore violated the RCRA and the EPA CCR Rule. The complaint seeks declaratory and injunctive relief. Talen believes the alleged claims are without merit and that the CBD’s factual and legal conclusions are incorrect. Talen filed a motion to dismiss the lawsuit which was followed by an amicus brief from the Utility Solid Waste Activities Group in support of Talen’s motion; briefing on the motion to dismiss was completed on June 30, 2025. No assurance can be provided as to the outcome of the litigation or its impacts on Talen’s operations.
ERCOT Weather Event (Winter Storm Uri) Lawsuits. In connection with the ERCOT Sale, the Company retained certain potential liabilities relating to claims filed from 2021 onward against its former Texas subsidiaries seeking unspecified damages for alleged losses caused by the defendants’ failure to provide sufficient power to the grid during Winter Storm Uri. The claims also allege similar liability against numerous other ERCOT power market participants. In December 2023, five multi-district litigation (“MDL”) bellwether lawsuits, which were selected by the MDL court as representative of all 58 cases filed in the Uri litigation, were dismissed by the MDL court, a ruling subsequently upheld by the Texas First Court of Appeals. In January and February 2025, the plaintiffs (in two
Spent Nuclear Fuel Litigation. Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel (“SNF”), but the government has not yet done so. Until May 2014, the DOE required nuclear generation facility operators to contribute to a fund intended to pay for the transportation and disposal of SNF, and Talen cannot predict if or when the government will reinstate any such fee in the future. In May 2023, an existing settlement agreement between Susquehanna and the U.S. government was extended through the end of 2025. The settlement agreement requires the government to reimburse Susquehanna for certain SNF storage costs through 2025 and requires Susquehanna to waive certain claims against the government relating to temporary SNF storage. In July 2025, the Company reached an agreement with the DOE for a reimbursement of $14 million (reflecting Talen’s 90 % share) related to the 2023-2024 period and received the reimbursement in August 2025.
Regulatory Matters
We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to the FERC; the DOE; 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. 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. Accordingly, we are subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules.
PJM Capacity Market Reform. In June 2023, the FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order for PJM to propose market reforms. PJM filed its market reform proposals with the FERC in October 2023. In early 2024, the FERC accepted portions of PJM’s proposed market changes and PJM scheduled certain PJM BRAs on a delayed basis. In September 2024, the Sierra Club and other organizations filed a complaint at the FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by RMR resources. In October 2024, PJM announced it had concerns about the FERC considering the Sierra Club’s complaints about RMR resources in isolation and therefore intended to file a Section 205 proceeding under the Federal Power Act seeking the FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatment of RMR resources. As a result, in October 2024, PJM formally requested, which the FERC approved, six-month delays to the scheduled PJM BRAs for the 2028/2029, and 2029/2030 PJM Capacity Years to June 2026, and December 2026, respectively. Currently, the auction for the 2030/2031 PJM Capacity Year in May 2027 is scheduled on a non-delayed basis. Talen can provide no assurance that these or any scheduled PJM BRAs will be held on such dates or at all.
A series of filings aimed at reforming the PJM capacity market were filed at the FERC. In November 2024, the Joint Consumer Advocates, comprised of consumer advocacy groups and government entities from Illinois, Maryland, New Jersey, Ohio, and the District of Columbia filed a complaint against PJM asking the FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and to issue an order requiring certain short-term and longer-term changes to PJM’s capacity market rules.
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In response, PJM made two FERC filings in December 2024 to address what they perceive as capacity market design issues (the “PJM Capacity Market 205 Proceeding”). PJM proposed to retain the dual fuel combustion turbine as the reference resource and to implement a uniform non-performance charge throughout the RTO for the 2026/2027 and 2027/2028 PJM Capacity Years, and to administratively include RMR units that meet certain criteria as price takers in the capacity auctions for the next delivery years and will not assess penalties or pay bonuses to these RMR units. PJM’s filing also clarifies that being excused from being required to offer into the capacity market is no defense to exercising market power by electing not to offer. Further, PJM proposed to make changes to the capacity market mitigation rules. This proposal will eliminate the must-offer exception for intermittent and limited duration resources that are eligible to participate in the capacity market and will allow market sellers to incorporate a risk component in their capacity market offers. In February 2025, the FERC accepted PJM’s proposals in the PJM Capacity Market 205 Proceeding and as a result, the changes to the PJM BRA parameters described above as part of that proceeding were adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.
In December 2024, the Pennsylvania Governor filed a complaint against PJM at the FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 PJM Capacity Years and proposed, among other things, a lower capacity price cap. As a result of a subsequent agreement between the State of Pennsylvania and PJM that resolved the Governor’s complaint, the Governor withdrew the complaint in February 2025. In April 2025, the FERC accepted PJM’s proposals reflecting its agreement with the Commonwealth of Pennsylvania. As a result, the PJM BRA imposed a price collar with an approximate minimum and maximum price of $175 /MWd and $325 /MWd, respectively, which was effective for the 2026/2027 PJM BRA in July 2025 and for the 2027/2028 PJM BRA in December 2025. It is uncertain whether price collars will be in effect for future PJM BRAs.
In February 2025, the FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings taking place in June 2025. The Company has intervened in the new technical conference docket and is closely monitoring those proceedings.
Interconnection of Large Loads. In October 2025, DOE directed the FERC to consider reforms to expedite and facilitate how large loads interconnect to the interstate transmission system. DOE stated that the Federal Power Act permits the FERC to exert jurisdiction over load interconnections even though it has not historically done so. DOE provided a draft advance notice of proposed rulemaking (“ANOPR”) and directed the FERC to initiate rulemaking procedures. In November 2025, the FERC requested public comment on the ANOPR, and the Company provided comments. DOE directed the FERC to take final action by the end of April 2026.
In August 2025, PJM began an accelerated process known as a Critical Issue Fast Path (“CIFP”) process with stakeholders to address how to integrate large load customers quickly and reliably. The CIFP stakeholders represented a wide range of views about resource allocations, costs, and how the addition of large loads like data centers to PJM should be managed in the context of the capacity market. The Company was an active participant in the CIFP process and submitted a joint proposal amongst itself, Constellation, Calpine, Amazon, Microsoft, and Google representing the group’s collective views on the best approach to large load additions. Neither the joint proposal nor any of the other proposals submitted received broad stakeholder support during voting. Nevertheless, PJM had planned to make a filing at the FERC in January 2026 containing PJM’s ultimate proposal to be in place for the 2028/2029 PJM BRA.
In December 2025, however, the FERC issued an order in a show cause proceeding on large loads co-located with generation. The FERC directed PJM to submit an informational report containing, among other items, all of the CIFP proposals. The FERC also found that the PJM tariff was unjust and unreasonable as to the interconnection of co-located loads. The FERC requested tariff revisions be submitted over the next 30-60 days and established a hearing schedule, which begins in February 2026, to establish rates, terms, and conditions of several new transmission services.
In January 2026, the National Energy Dominance Council (“NEDC”) and the Governors from each of the 13 states in PJM issued a “Statement of Principles” for PJM. Among other things, the statement calls for PJM to conduct a reliability backstop auction for new baseload capacity with 15-year contracts by September 2026. It also urges PJM to extend the existing price collar for the next two BRAs. Hours after the NEDC/Governors’ principles were released, the PJM Board of Managers issued a Board Decisional Letter — the final step in the Large Load Addition CIFP process. The Board’s Decisional Letter adopted specific elements of various proposals, including load forecasting improvements, voluntary bring your own generation paired with an expedited interconnection track, a holistic review in the coming year of investment incentives in PJM’s markets, and immediate initiation of a reliability backstop procurement. PJM also requested feedback on an extension of the price collar for the next two BRAs.
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Environmental Matters
Extensive federal, state, and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, hazardous substances, and solid waste management. From time to time, in the ordinary course of our business, Talen may be: (i) subject to environmental remediation work at its facilities; (ii) involved in other environmental matters; or (iii) become subject to other, new or revised environmental statutes, regulations, or requirements. It may be necessary for us to modify, curtail, replace, or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations, and other requirements imposed by regulatory bodies, courts, or environmental groups. We may incur significant costs to comply with these requirements, including increased capital expenditures or operation and maintenance expenses, monetary fines, remediation costs, penalties, or other restrictions. Legal challenges to environmental rules or permits add to the uncertainty of estimating future compliance 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, in March 2025, the EPA announced that it will reconsider and potentially roll back 31 regulations and policies, many of which directly impact Talen, and various executive actions were taken in April 2025 to further encourage deregulation. The EPA’s reconsiderations for many of these regulations and policies remain ongoing, and certain executive orders have subsequently been challenged by states and individual plaintiffs. Future provisions, implementation, and enforcement of these executive actions and the environmental rules continue to be uncertain. Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed in other ways.
EPA CSAPR and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA revised the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”). This action triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (the “Good Neighbor Plan”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey were subject to the new rule; however, the entire rule was challenged by multiple parties, and subsequently the Good Neighbor Plan was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the D.C. Circuit Court of Appeals. In November 2024, the EPA issued an interim final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive Revised CSAPR Update Rule until the Good Neighbor Plan matter is resolved. After initially denying the EPA’s request in February 2025, the D.C. Circuit Court of Appeals in April 2025, granted the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance pending the EPA’s review of the stayed rule and further orders by the court. As a result, future implementation and enforcement of the Good Neighbor Plan has continued to be uncertain.
In January 2026, the EPA proposed Phase 1 of its reconsideration of the Good Neighbor Plan. In its proposal, the EPA proposes to approve state implementation plan submissions governing interstate emissions from eight states (Alabama, Arizona, Kentucky, Minnesota, Mississippi, Nevada, New Mexico, and Tennessee). If finalized, these states would no longer be subject to Good Neighbor Plan requirements. Although Talen does not operate in any of the states identified in the proposed rule, EPA in its proposal states that it intends to undertake a separate action to address interstate transport obligations for the remaining states covered under the Good Neighbor Plan.
EPA MATS Rule. In May 2024, the EPA published a rule that requires coal-fired generation facilities to reduce particulate matter emissions by the middle of 2027 (or 2028, if an extension is approved) (the “2024 EPA MATS Rule”). In February 2026, however, the EPA issued a subsequent final rule repealing the lower particulate matter standards set in the 2024 amendments and reverting to particulate matter standards promulgated in the 2012 EPA MATS Rule (the “MATS Repeal Rule”). Challenges to the 2024 EPA MATS Rule were filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. The appeal on the merits of the 2024 rule remains pending in the D.C. Circuit Court of Appeals, but the litigation has been held in abeyance since February 2025, while the EPA reconsidered the rule. As a result of the EPA’s MATS Repeal Rule, the litigation over the 2024 EPA MATS Rule will likely be deemed moot. However, challenges to the MATS Repeal Rule are expected. No assurance can be provided as to whether the MATS Repeal Rule will survive judicial challenge and when such challenges will be resolved. Colstrip was not expected to meet the 2024 particulate matter standard without substantial upgrades to its control equipment. As a result, if the MATS Repeal Rule is vacated by a court or reconsidered by the EPA in the future, Talen Montana and the other Colstrip co-owners will face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility. Such a decision must be evaluated in conjunction with other compliance requirements.
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In March 2025, the EPA formally announced that it was reconsidering the 2024 EPA MATS Rule as part of its deregulation agenda. Concurrently, the Trump administration announced it was considering a two-year exemption from compliance obligations via Section 112(i)(4) of the Clean Air Act for affected power plants while the EPA reconsidered the rule. Talen applied for the exemption, which was granted in April 2025. This authorization affords more time for the Colstrip owners to consider the operational future of Colstrip. Environmental groups filed separate lawsuits in the D.C. Circuit Court of Appeals and the U.S. District Court for D.C., challenging the presidential exemptions issued to Colstrip and other fossil fuel-fired power plants. On August 5, 2025, the EPA filed a motion in each case requesting the courts hold the litigation in abeyance for six months pending the EPA’s efforts to repeal the 2024 EPA MATS Rule. Talen filed motions to intervene in both cases on August 8, 2025. On September 3, 2025, the U.S. District Court for D.C. granted the EPA’s motion to hold the case in abeyance for six months and also granted Talen’s motion to intervene. Plaintiffs filed a motion asking the court to reconsider its decision to hold the case in abeyance. The U.S. District Court for D.C. denied that motion in November 2025. The D.C. Circuit Court of Appeals granted the EPA’s motion for an abeyance and Talen’s motion to intervene in October 2025. The litigation may be deemed moot as a result of the EPA’s MATS Repeal Rule, but no assurance can be provided as to the outcome of this litigation at this time. The Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on legal challenges regarding the MATS Repeal Rule and the presidential exemption litigation.
EPA GHG Rule. In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and greenhouse gas (“GHG”) guidelines for certain existing EGUs. Under the guidelines, if existing coal-fired EGUs operate beyond 2031, GHG reductions, such as those achieved by the addition of carbon capture and sequestration (“CCS”), are required to be implemented by the end of 2031. Colstrip is not expected to meet the new rules without substantial technology upgrades and pipeline infrastructure build-out. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive controls (e.g., CCS technology) or retire the Colstrip facility by the end of 2031. Such a decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule. Petitions have been filed in the D.C. Circuit Court of Appeals, including by coalitions representing 27 states and an ad hoc coalition of power producers of which Talen is a member, requesting a review of the EPA GHG Rule. Stay motions were denied by the D.C. Circuit Court of Appeals in July 2024 and the U.S. Supreme Court in October 2024. Appeals of the EPA GHG Rule remain pending in the D.C. Circuit Court of Appeals.
The D.C. Circuit Court of Appeals has held the litigation in abeyance since February 2025 to allow the EPA to reconsider the rule. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. In June 2025, the EPA released a proposed rule to repeal all GHG emission standards for fossil fuel-fired power plants. As an alternative, the EPA is proposing a narrow repeal of GHG standards, which would eliminate all emissions guidelines and standards for existing power plants and the Phase 2 GHG emissions standards that would apply to new combustion turbines beginning in 2032. Under the alternative proposal, Phase 1 GHG emissions standards applicable to new and reconstructed baseload fossil fuel-fired stationary combustion turbines would be retained. The public comment period on the proposal expired on August 7, 2025. No assurance can be provided as to whether the rule will be finalized and whether a final rule will survive judicial challenge. The EPA has also in the past stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed, and no recent statements have been made. Operating decisions about the future of Colstrip are highly dependent on the fate of the EPA GHG Rule as well as the EPA MATS Rule. Given the legal and regulatory uncertainties with both rules, it is possible the Company will be required to make decisions about Colstrip’s future before it has clarity about the outcome of litigation and (or) the EPA’s regulations.
GHG Endangerment Finding. In February 2026, the EPA issued a final rule rescinding its 2009 finding that GHG emissions endanger public health and welfare and repealing all GHG emissions standards for light-, medium-, and heavy-duty vehicles and engines. The EPA made the 2009 endangerment finding in order to promulgate GHG emission standards for new motor vehicles under Section 202(a) of the Clean Air Act and has subsequently relied on this finding as a basis to regulate other sources of GHGs. In the final rule, EPA states it must rescind the endangerment finding because it lacks the statutory authority to regulate GHG emissions from vehicles in response to global climate changes concerns. The EPA does not explicitly state how the rescission impacts its authority to regulate GHG emissions from stationary sources. However, the final rule acknowledges that EPA has relied on the endangerment finding “to extend the GHG regulatory program to new and existing stationary source performance standards and guidelines for power plants under CAA section 111.” Citizen groups have challenged the final rule in the D.C. Circuit Court of Appeals. No assurance can be provided as to whether the rule will survive judicial challenge.
Pennsylvania RGGI. In October 2019, the then-Governor of Pennsylvania signed an executive order directing the Pennsylvania Department of Environmental Protection (the “PADEP”) to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, in November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PADEP appealed this decision to the Pennsylvania Supreme Court and filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups to intervene in the case. Oral argument in the case took place in May 2025. In November 2025, the Pennsylvania legislature passed a budget that included provisions requiring Pennsylvania to withdraw from RGGI. As a result, the PADEP filed an application to the Pennsylvania Supreme Court requesting to discontinue its appeal. The Pennsylvania Supreme Court granted the application and dismissed the case on January 6, 2026.
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EPA ELG Rule. In November 2015, the EPA revised the effluent limitation guidelines (“ELGs”) for certain power generation facilities, which imposed more stringent standards for wastewater streams as facility discharge permits are renewed. In 2020, the EPA issued changes that would exempt coal generation facility operators from meeting certain wastewater standards if the facility would commit to cease coal-fired generation by the end of 2028, which Talen elected for its wholly owned coal operations. In May 2024, the EPA published revisions to the EPA ELG Rule, which imposed additional requirements for legacy wastewater and combustion residual leachate. These revisions impact Talen’s active generation facilities that have both CCR units and hold National Pollutant Discharge Elimination System (“NPDES”) discharge permits. These sites include Brandon Shores, Brunner Island, Montour, and potentially Martins Creek. Talen is evaluating what: (i) potential discharge limits may apply; (ii) treatment may be required; and (iii) the implementation timeline may be. Obligations for installing any new wastewater treatment equipment, if necessary, will not be known until each applicable state where the active generation facilities operate makes its own determination with respect to NPDES permit renewals with new limits and associated timing. As a result of the future permit conditions, additional capital expenditures and (or) AROs may be required, which may have a material impact on Talen’s operations and (or) financial condition.
Multiple challenges, including stay requests, to the EPA ELG Rule have been filed in various U.S. Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group (“UWAG”), of which Talen is a member. The appeals have been consolidated in the U.S. Court of Appeals for the Eighth Circuit, which denied requests to stay the rule in October 2024. At the EPA’s request, the Eighth Circuit has held the consolidated challenges in abeyance since February 2025 to allow the EPA to reconsider the rule. In March 2025, the EPA announced that it will revise the EPA ELG Rule as part of its deregulation agenda while considering immediate relief from some of the existing leachate requirements. In June 2025, the EPA announced that it will issue a proposal in 2025 to extend compliance deadlines under the 2024 EPA ELG Rule and seek information to potentially inform further rulemaking. In September 2025, the EPA issued a direct final rule extending a short-term deadline and a companion proposal extending many compliance deadlines for the 2024 EPA ELG Rule and providing some flexibility relating to some deadlines in the 2020 ELG Rule. In November 2025, the EPA issued a notice withdrawing the direct final rule due to the receipt of adverse comments. The EPA finalized its proposal in December 2025. Among other things, the final rule extends zero-discharge compliance deadlines established in the 2024 EPA ELG Rule by five years from December 31, 2029 to December 31, 2034. The extension rule has been legally challenged by environmental groups. These challenges have been consolidated in the U.S. Court of Appeals for the Second Circuit. UWAG has filed a motion to intervene in the consolidated litigation. In the final rule, the EPA also stated it is considering further rulemaking to revise the regulatory standards in the 2024 EPA ELG Rule. No assurance can be provided as to whether the EPA’s final rule will be challenged, when the challenges to the EPA ELG Rule merits will be resolved, or whether such changes and challenges will be resolved in the Company’s favor.
EPA CCR Rule. In April 2015, the EPA established regulations under the RCRA to identify CCRs as nonhazardous solid waste and provided CCR management and siting requirements. The 2015 rule was modified in 2020 after a 2018 D.C. Circuit Court of Appeals ruling found that, among other things, the EPA did not adequately regulate unlined impoundments. In its 2020 rulemaking, the EPA specified procedures for owners to extend the operating timeline of certain unlined impoundments. Talen submitted an extension request under this process for an unlined impoundment at Montour, which was withdrawn in December 2024, following the end of basin operations and the initiation of basin closure. The 2018 D.C. Circuit Court of Appeals ruling also found that the EPA did not properly address legacy surface impoundments in the 2015 CCR rule. As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations effective in November 2024 (the “Legacy CCR Rule”), which provided new requirements for legacy CCR surface impoundments and new requirements for other CCR disposal and management areas at active power plants (“CCR Management Units” or “CCRMUs”). This rule has been challenged in the D.C. Circuit Court of Appeals by multiple parties, including two industry groups of which Talen is a member. In December 2024, the U.S. Supreme Court denied a requested stay of the Legacy CCR Rule. At the EPA’s request, the D.C. Circuit Court of Appeals has held the case in abeyance since February 2025 to allow the EPA to reconsider the rule. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs.
In March 2025, the EPA announced that it will prioritize the coal ash program by expediting state permit reviews. The EPA has also announced it will reform the federal CCR Rule and provided in the Legacy CCR Rule litigation proceeding that CCR Rule reforms will be completed in 2026. As an initial reform step, in February 2026, the EPA issued a final rule extending compliance deadlines for elements in the Legacy CCR Rule, including required applicability assessments, the initiation of new groundwater monitoring detection, and the initiation of unit closure. No assurance can be provided as to when and how federal CCR regulations will change further, when the legal challenges to the Legacy CCR Rule, how the EPA’s interpretations or further CCR Rule reforms will be resolved, or whether such challenges will be decided in the Company’s favor.
Talen continues to review the Legacy CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional CCR Rule reforms. As a result of the EPA’s February 2026 CCRMU Extension Rule, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are now due in February 2027. Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2028. The Company has initiated reviews under the facility evaluation report requirements at locations with ash impoundments that have long since ceased coal operations as well as at locations with current coal operations to meet these deadlines. No assurance can be provided as to whether any specific ash impoundments owned by the Company may or may not be within scope of the updated Legacy CCR Rule until the Company completes its assessments within the regulatory timeframe.
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As of December 31, 2025 (Successor), the Company has recognized cost estimates in complying with the Legacy CCR Rule’s initial compliance requirements and deadlines, including the initial groundwater monitoring requirements. The Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on Talen’s operations and (or) financial condition.
In April 2025, a citizen suit was filed in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, are in violation of RCRA and the EPA CCR Rule. See the “Legal Matters” section above for additional information.
Certain Resolved Matters
PPL/Talen Montana Litigation. In December 2023, a settlement was reached in litigation between Talen and PPL regarding Talen’s claim that a $733 million distribution paid to PPL in 2014 left Talen Montana insolvent. Under the terms of the settlement, PPL paid Talen Montana $115 million in exchange for a full release of claims, with $11 million of that amount remitted to the general unsecured creditors trust established under the Plan of Reorganization. As a result, a $104 million net gain is presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the period May 18 through December 31, 2023 (Successor).
Guarantees and Other Assurances
In the normal course of business, the Company enters into agreements to provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the stand-alone creditworthiness attributed to a subsidiary or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs, and (or) surety bonds. Additionally, they may include customary indemnifications to third parties related to asset sales and other transactions. The probability of expected material payment and (or) performance for these assurance agreements is believed to be remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations including but not limited to environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers. As of December 31, 2025 (Successor) and 2024 (Successor), the aggregate amount of surety bonds outstanding was $228 million and $234 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below.
Talen Montana Financial Assurance. Pursuant to the Colstrip Administrative Order on Consent (the “Colstrip AOC”), Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (the “MDEQ”) on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities was $114 million and $125 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions, and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements are expected to decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed. See Note 8 for additional information on Colstrip AROs.
Other Commitments and Contingencies
Nuclear Insurance. The Price-Anderson Act is a federal law that governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2025 (Successor), the liability limit per incident is $16.3 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers ($500 million in coverage), with the remainder covered by an industry retrospective assessment program.
As of December 31, 2025 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $332 million per incident, payable at a maximum of $49 million per year.
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Additionally, Susquehanna purchases property insurance programs from Nuclear Electric Insurance Limited (“NEIL”), an industry mutual insurance company of which Susquehanna is a member. As of December 31, 2025 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $2 billion and non-nuclear property damage losses up to $1 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $50 million as of December 31, 2025 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Talen Montana Fuel Supply. Talen Montana purchases coal from a mine owned by Westmoreland Rosebud Mining, LLC (the “Rosebud Mine”) for its interest in Colstrip Units 3 and 4 under a full requirements contract with the mine operator. Several lawsuits have been brought against the Rosebud Mine challenging permits and approvals to expand its operations. Talen Montana is not party to these lawsuits but is monitoring the progress of each to assess the impact to its operations. In the first lawsuit, the Montana Supreme Court in 2023 affirmed a lower court’s ruling to vacate a mining permit and require the Montana Board of Environmental Review to perform an additional review of the permit. In the second lawsuit, the Montana Federal District Court ordered a branch of the U.S. Department of the Interior to complete an updated Environmental Impact Statement (“EIS”) for a separate expansion project. In August 2025, the U.S. Department of Interior issued a supplemental EIS and approved an expansion of operations to authorize the mining of federal coal through 2039. In the third lawsuit, plaintiffs challenged a water pollution permit authorizing a separate expansion to the mine in 2023. In September 2025, a Montana State District Court upheld the permit. Plaintiffs appealed that ruling to the Montana Supreme Court in November 2025. At this time, Talen cannot predict the effect that an adverse outcome of these lawsuits to Rosebud Mine would have on: (i) Talen Montana’s ability to source fuel for its share of Colstrip operations; or (ii) Talen Montana’s operations, results of operations, or liquidity.
10. Long-Term Debt and Other Credit Facilities
TES is the borrower/issuer under all the Company’s debt and credit facilities. As of December 31, 2025 (Successor), TES was not in default under any of its debt or credit agreements.
Long-Term Debt
| Successor | ||||||||||||||||||||
Interest Rate (a) | December 31, 2025 | December 31, 2024 | ||||||||||||||||||
TLB-1 | $ | $ | ||||||||||||||||||
| TLB-2 | ||||||||||||||||||||
| TLB-3 | ||||||||||||||||||||
| Secured Notes | ||||||||||||||||||||
| 2034 Unsecured Notes | ||||||||||||||||||||
| 2036 Unsecured Notes | ||||||||||||||||||||
PEDFA 2009B Bonds | ||||||||||||||||||||
PEDFA 2009C Bonds | ||||||||||||||||||||
| Total principal | ||||||||||||||||||||
| Unamortized deferred financing costs and original issuance discounts | ( | ( | ||||||||||||||||||
| Total carrying value | ||||||||||||||||||||
| Less: long-term debt, due within one year | ||||||||||||||||||||
| Long-term debt | $ | $ | ||||||||||||||||||
__________________
(a)Computed interest rate as of December 31, 2025 (Successor).
Long-term debt maturities as of December 31, 2025 (Successor) were:
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||
| Principal debt maturities | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||
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Revolving Credit and Other Facilities
| Successor | ||||||||||||||||||||||||||||||||
| December 31, 2025 | ||||||||||||||||||||||||||||||||
| Maturity | Committed Capacity (a) | Direct Cash Borrowings | LCs Issued | Unused Capacity | ||||||||||||||||||||||||||||
RCF | December 2029 | $ | $ | $ | $ | |||||||||||||||||||||||||||
| LCF | December 2027 | — | ||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | ||||||||||||||||||||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs. Direct cash borrowings are not permitted under the LCF, which can only be used for LCs.
Long-Term Debt, Revolving Credit, and Other Facilities
Certain key terms of our indebtedness include:
| Maturity: | Index: | Rate, Applicable Margin, and Amortization: | Prepayment Penalty: | |||||||||||
| Secured Notes | June 2030 | None | No applicable margin No amortization | Prior to June 1, 2026: Redeemable at par plus a customary “make-whole” premium. On or after June 1 of the following years: 2026: | ||||||||||
| 2034 Unsecured Notes | February 2034 | None | No applicable margin No amortization | Prior to October 15, 2028: Redeemable at par plus a customary “make-whole” premium. On or after October 15 of the following years: 2028: | ||||||||||
| 2036 Unsecured Notes | February 2036 | None | No applicable margin No amortization | Prior to October 15, 2030: Redeemable at par plus a customary “make-whole” premium. On or after October 15 of the following years: 2030: | ||||||||||
| TLB-1 | May 2030 | Term SOFR | Amortization | Currently none | ||||||||||
| TLB-2 | December 2031 | Term SOFR | Same as TLB-1 | Currently none | ||||||||||
| TLB-3 | November 2032 | Term SOFR | Amortization | |||||||||||
| RCF | December 2029 | Term SOFR | Cash borrowings: LCs: LC fee equal to applicable margin above + fronting fee of Unused commitments: No amortization | None | ||||||||||
| LCF | December 2027 | None | LCs: Same as RCF Unused commitments: Same as RCF | None | ||||||||||
| PEDFA Bonds | 2009B: December 2038 2009C: December 2037 | None | No applicable margin No amortization | Prior to June 1, 2026: Par plus a customary “make-whole” premium On or after June 1, 2026: Par | ||||||||||
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Credit Agreement. The Credit Agreement governs the RCF, TLB-1, TLB-2, TLB-3, and LCF. The Credit Agreement contains customary negative covenants including but not limited to limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and asset sales. The Credit Agreement also contains customary affirmative covenants. Solely with respect to the RCF and LCF, and solely during a compliance period (i.e., when RCF cash borrowings exceed 50 % of revolving commitments on the last day of a fiscal quarter), the Credit Agreement requires TES’s consolidated first lien net leverage ratio not to exceed 4.25 x. This financial covenant does not apply to the TLB-1, TLB-2, or TLB-3. The Credit Agreement also contains customary representations and warranties, events of default, and remedies (including acceleration of amounts due and (or) termination of commitments).
Secured Notes. Interest on the Secured Notes is payable semi-annually on June 1 and December 1 of each year and at maturity. The Secured Notes are subject to customary negative covenants for secured notes, including but not limited to certain limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and transactions involving the Susquehanna assets, but do not contain any financial covenants. The Secured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration).
Unsecured Notes. Interest on the Unsecured Notes is payable semi-annually on February 1 and August 1 of each year and at maturity. The Unsecured Notes are subject to customary negative covenants for unsecured notes, including but not limited to certain limitations on incurrence of liens and transactions involving the Susquehanna assets, but do not contain any financial covenants. The Unsecured Notes also contain customary affirmative covenants, events of default, and remedies (including acceleration).
PEDFA Bonds. The PEDFA 2009B and 2009C Bonds were issued by the PEDFA on behalf of TES, and TES then received the proceeds under corresponding back-to-back exempt facilities loan agreements with the PEDFA. Corresponding TES unsecured promissory notes for each series contain the applicable principal, interest, and prepayment provisions. The PEDFA Bonds bear interest at a fixed rate until the end of the current term rate period on June 1, 2027, at which time they are subject to mandatory remarketing during which TES may elect a different interest rate mode. Aside from principal amount and final maturity, the terms of the PEDFA 2009B Bonds and 2009C Bonds are substantially identical. The PEDFA Bonds are subject to customary affirmative and negative covenants appropriate for such tax-exempt facilities, including but not limited to limitations on incurrence of liens (but not unsecured indebtedness), and asset sales. The PEDFA Bonds are also subject customary events of default and remedies (including acceleration).
Secured ISDAs. Talen Energy Marketing is party to certain Secured ISDAs, under which TES and the Subsidiary Guarantors provide the applicable counterparties with a first priority lien on and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. The secured obligations under the Secured ISDAs were $269 million as of December 31, 2025 (Successor).
Security Interests, Guarantees, Cross-Defaults, and Restrictions on Dividends
Secured Obligations. The obligations under the Credit Facilities, Secured Notes, and Secured ISDAs are secured by a first-priority lien on and security interest in substantially all of the assets of TES and the Subsidiary Guarantors. The Subsidiary Guarantors guarantee TES’s obligations under the Credit Facilities and the Secured Notes. TES and the Subsidiary Guarantors guarantee Talen Energy Marketing’s obligations under the Secured ISDAs. The amount for which TES and the Subsidiary Guarantors may be liable is equal to the amount of obligations outstanding under such agreements and may also include unpaid interest, premiums, penalties, and (or) other fees and expenses. An event of default under the Credit Facilities, Secured Notes, or Secured ISDAs, if not cured or waived, may result in a cross acceleration of amounts due and (or) cross termination across all these agreements.
Restrictions on Dividends. 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 from June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components.
As of December 31, 2025 (Successor), substantially all net assets of TES and the Subsidiary Guarantors were subject to restrictions on dividends.
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Unsecured Obligations. The Unsecured Notes and the PEDFA Bonds are senior unsecured obligations of TES that are effectively subordinated to TES’s secured obligations, including the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations. The Subsidiary Guarantors guarantee TES’s obligations under the Unsecured Notes and certain of the Subsidiary Guarantors also guarantee TES’s obligations under the PEDFA Bonds. These guarantees are the general unsecured obligations of such Subsidiary Guarantors, rank equally with all of their other senior unsecured indebtedness, and are effectively subordinated to their secured obligations, including guarantees under the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing those obligations.
2025 Financing Transactions
Freedom and Guernsey Acquisitions Financing. In October and November 2025, TES completed several financing transactions and used the proceeds from the Unsecured Notes and the TLB-3 to finance the Freedom and Guernsey Acquisitions.
•Unsecured Notes. Issued: (i) $1.4 billion in aggregate principal amount of the 2034 Unsecured Notes and (ii) $1.3 billion in aggregate principal amount of the 2036 Unsecured Notes.
•TLB-3. Drew in full the $1.2 billion senior secured term loan B credit facility (the TLB-3), which constitutes a new tranche of term loans separate from TLB-1 and TLB-2.
•RCF. Increased its existing RCF (including its revolving LC capacity) from $700 million to $900 million.
•LCF. Increased its existing $900 million LCF to $1.1 billion and extended the maturity from December 2026 to December 2027.
Additionally, in November 2025, in connection with the closing of the Freedom and Guernsey Acquisitions, the Company entered into the Fifth Supplemental Indenture to the Secured Notes Indenture and First Supplemental Indentures to each of the Unsecured Notes Indentures to add certain entities as Subsidiary Guarantors of the Secured Notes and Unsecured Notes, respectively.
See Note 17 for additional information on the Freedom and Guernsey Acquisitions.
2024 Financing Transactions
Credit Facilities. In December 2024, TES completed several refinancing transactions:
•TLB-2. Issued a new $850 million TLB-2, the proceeds of which were used, together with cash on hand, to repurchase shares of our outstanding common stock from Rubric.
•TLB-1. Repriced the existing $857 million TLB-1 to reduce the current interest rate margin by 100 basis points (to SOFR plus 250 basis points, with further leverage-based step downs available) to align pricing with the new TLB-2.
•RCF. Repriced the existing $700 million RCF to reduce the current interest rate margin by 100 basis points (to SOFR plus 200 basis points, with further leverage-based step downs available), increased revolving LC capacity from $475 million to $700 million, and extended the maturity from May 2028 to December 2029.
•LCF. Issued a new $900 million standalone secured LCF to transition LCs from the TLC LCF and Bilateral LCF. LCs issued under the LCF are subject to an LC fee of 2.00 % per annum (with leverage-based step downs available) plus a fronting fee of 0.125 % per annum.
•TLC/TLC LCF. Repaid in full the $470 million TLC utilizing the restricted cash collateralizing the TLC LCF, and terminated the TLC and associated $470 million TLC LCF.
•Bilateral LCF. Terminated the $75 million Bilateral LCF.
In connection with these transactions, the requisite lenders under the Credit Agreement also consented to certain amendments, among other things, increasing the Company’s flexibility for restricted payments, investments, and dispositions under the Credit Facilities. As a result of these transactions, the Company derecognized the carrying value of the extinguished TLC and presents the carrying value of the newly issued TLB-2 on the Consolidated Balance Sheet.
In May 2024, TES repriced the TLB-1 and TLC, and the lenders, as part of these debt modifications, agreed to waive mandatory prepayment obligations related to the ERCOT Sale. See Note 17 for additional information on the ERCOT Sale. Additionally, the lenders under the TLB-1, TLC, and RCF consented to certain other covenant improvements.
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PEDFA Bonds. In June 2024, TES completed the remarketing of its outstanding $50 million in PEDFA 2009B Bonds and $81 million in PEDFA 2009C Bonds. As part of the remarketing, (i) the PEDFA Bonds were transitioned from a variable daily interest rate to a fixed term rate of 5.25 133 million of TES LCs that had previously supported the PEDFA Bonds were terminated; (iii) mandatory repurchase and optional redemption provisions were modified; and (iv) certain covenants relating to changes of control, incurrence of liens, and asset sales were amended and became operative. The remarketing transaction is excluded from the Consolidated Statements of Cash Flows as a non-cash item.
Cumulus Digital TLF Repayment. In connection with the AWS Data Campus Sale, the Cumulus Digital TLF was paid in full in March 2024, together with all accrued interest and other outstanding amounts, and related liens, guarantees, and LCs were released and terminated. See Note 17 for additional information on the AWS Data Campus Sale.
11. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT. See Note 1 for additional descriptions on fair value levels.
The classifications of recurring fair value measurements within the fair value hierarchy were:
| Successor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Netting (a) | Total | Level 1 | Level 2 | NAV | Netting (a) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | — | $ | $ | $ | $ | $ | — | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
Equity securities (b) | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. government debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NDT funds | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b)Includes fixed income funds and real estate investment trusts.
(c)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
There were no recurring fair value measurements classified as Level 3 as of December 31, 2025 (Successor) and 2024 (Successor).
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Nonrecurring Fair Value Measurements
See Note 7 for nonrecurring fair value measurements during the year ended December 31, 2025 that are associated with the derecognition of certain Nautilus assets and liabilities. There were no material fair value measurements related to impairments of long-lived assets during the year ended December 31, 2024 (Successor), and for the period from May 18 through December 31, 2023 (Successor) See Note 7 for information on the nonrecurring fair value measurement of Brandon Shores and Note 20 for information on the nonrecurring fair value measurements resulting in the application of fresh start accounting during the period from January 1 through May 17, 2023 (Predecessor).
Reported Fair Value
The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents,” “Restricted cash and cash equivalents,” “Accounts receivable,” and “Accounts payable and other accrued liabilities” approximate fair value.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| Successor | ||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||||||
Long-term debt (a) | $ | $ | $ | $ | ||||||||||||||||||||||
__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
12. Postretirement Benefit Obligations
TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and a defined contribution plan.
Pension and Other Postretirement Defined Benefit Plans
Obligations under the defined benefit pension and other postretirement plans are generally based on factors, among others, such as age of the participants, years of service, and compensation. The pension and other postretirement plans are closed to new participants. Effective December 31, 2018, all participants ceased accruing additional benefits in the TERP, the Company’s largest defined benefit pension plan.
Funded Status. The net fair value of underfunded defined benefit pension and other postretirement plans are presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets. The Talen Montana sponsored defined benefit pension plan was overfunded by a non-material amount as of December 31, 2025 (Successor). Certain other postretirement plans were overfunded by $39 million and $36 million as of December 31, 2025 (Successor) and 2024 (Successor), respectively. Overfunded balances are presented as “Other noncurrent assets” on the Consolidated Balance Sheets. The current portion of certain unfunded postretirement obligations were non-material.
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The aggregate funded status and the weighted average assumptions for the periods were:
| Pension Benefits | ||||||||||||||
| Successor | ||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | |||||||||||||
| Change in benefit obligation | ||||||||||||||
| Benefit obligation beginning balance | $ | $ | ||||||||||||
| Service cost | ||||||||||||||
| Interest cost | ||||||||||||||
| Actuarial (gain) loss | ( | |||||||||||||
| Actual benefits paid | ( | ( | ||||||||||||
| Resolved litigation settlement and other charges | ||||||||||||||
| Benefit obligation ending balance | $ | $ | ||||||||||||
| Change in plan assets | ||||||||||||||
| Plan assets fair value beginning balance | ||||||||||||||
| Actual return on plan assets | ( | |||||||||||||
| Employer contributions | ||||||||||||||
| Actual benefits paid | ( | ( | ||||||||||||
| Plan assets fair value ending balance | $ | $ | ||||||||||||
| Funded status | $ | ( | $ | ( | ||||||||||
| Accumulated benefit obligation | $ | $ | ||||||||||||
| Aggregate amounts of underfunded plans | ||||||||||||||
| Benefit obligation/Accumulated benefit obligation | $ | $ | ||||||||||||
| Fair value of plan assets | ||||||||||||||
| Amounts recognized in accumulated other comprehensive income | ||||||||||||||
| Net (gain) loss | ||||||||||||||
| Total accumulated other comprehensive income | $ | $ | ||||||||||||
| Assumptions | ||||||||||||||
| Discount rate | % | % | ||||||||||||
| Interest crediting rate | % | % | ||||||||||||
| Rate of compensation increase | % | % | ||||||||||||
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During the year ended December 31, 2025 (Successor), the decrease in postretirement benefit obligations was primarily attributable to employer contributions and actual returns being higher than expected returns on plan assets.
| Other Postretirement Benefits | ||||||||||||||
| Successor | ||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | |||||||||||||
| Change in benefit obligation | ||||||||||||||
| Benefit obligation beginning balance | $ | $ | ||||||||||||
| Service cost | ||||||||||||||
| Interest cost | ||||||||||||||
| Plan amendments | ( | ( | ||||||||||||
| Actuarial (gain) loss | ( | |||||||||||||
| Plan participant contributions | ||||||||||||||
| Actual benefits paid | ( | ( | ||||||||||||
| Benefit obligation ending balance | $ | $ | ||||||||||||
| Change in plan assets | ||||||||||||||
| Plan assets fair value beginning balance | ||||||||||||||
| Actual return on plan assets | ||||||||||||||
| Employer contributions | ||||||||||||||
| Plan participant contributions | ||||||||||||||
| Actual benefits paid | ( | ( | ||||||||||||
| Plan assets fair value ending balance | $ | $ | ||||||||||||
| Funded status | $ | $ | ||||||||||||
| Aggregate amounts of underfunded plans | ||||||||||||||
| Benefit obligation / Accumulated benefit obligation | $ | $ | ||||||||||||
| Fair value of plan assets | ||||||||||||||
| Amounts recognized in accumulated other comprehensive income | ||||||||||||||
| Net (gain) loss | ( | ( | ||||||||||||
| Prior service cost (credit) | ( | ( | ||||||||||||
| Total accumulated other comprehensive income | $ | ( | $ | ( | ||||||||||
| Assumptions | ||||||||||||||
| Discount rate | % | % | ||||||||||||
| Rate of compensation increase | % | % | ||||||||||||
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Net Periodic Benefit Cost and Amounts Recognized in OCI. The components of net periodic benefit cost (credit), the amounts recognized in OCI and the associated weighted average assumptions for pension and other postretirement plans for the periods were:
| Pension Benefits | |||||||||||||||||||||||||||||
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Net periodic benefit costs (credits): | |||||||||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||||||||
| Interest cost | |||||||||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | |||||||||||||||||||||||||
| Amortization of net (gain) loss | |||||||||||||||||||||||||||||
| Resolved litigation settlement and other charges | |||||||||||||||||||||||||||||
| Net periodic defined benefit cost (credit) | ( | ( | |||||||||||||||||||||||||||
| Net actuarial (gain) loss | ( | ( | |||||||||||||||||||||||||||
| Reclassifications due to settlement and (or) curtailment: | |||||||||||||||||||||||||||||
| Amortization of net (gain) loss | |||||||||||||||||||||||||||||
| Total recognized in OCI | $ | ( | $ | ( | $ | $ | |||||||||||||||||||||||
| Total recognized in net periodic costs and OCI | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Assumptions | |||||||||||||||||||||||||||||
| Discount rate | % | % | % | % | |||||||||||||||||||||||||
| Rate of compensation increase | % | % | % | % | |||||||||||||||||||||||||
| Expected return on plan assets | % | % | % | % | |||||||||||||||||||||||||
| Other Postretirement Benefits | |||||||||||||||||||||||||||||
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Net periodic benefit costs (credits): | |||||||||||||||||||||||||||||
| Service cost | $ | $ | $ | $ | |||||||||||||||||||||||||
| Interest cost | |||||||||||||||||||||||||||||
| Expected return on plan assets | ( | ( | ( | ( | |||||||||||||||||||||||||
| Amortization of prior service cost (credit) | ( | ( | |||||||||||||||||||||||||||
| Amortization of net (gain) loss | ( | ||||||||||||||||||||||||||||
| Net periodic defined benefit cost (credit) | ( | ( | |||||||||||||||||||||||||||
| Net actuarial (gain) loss | ( | ( | |||||||||||||||||||||||||||
| Prior service credit | ( | ( | |||||||||||||||||||||||||||
| Reclassifications due to settlement and (or) curtailment: | |||||||||||||||||||||||||||||
| Amortization of prior service cost (credit) | |||||||||||||||||||||||||||||
| Amortization of net (gain) loss | |||||||||||||||||||||||||||||
| Total recognized in OCI | $ | $ | ( | $ | ( | $ | |||||||||||||||||||||||
| Total recognized in net periodic costs and OCI | $ | ( | $ | ( | $ | $ | |||||||||||||||||||||||
| Assumptions | |||||||||||||||||||||||||||||
| Discount rate | % | % | % | % | |||||||||||||||||||||||||
| Rate of compensation increase | % | % | % | % | |||||||||||||||||||||||||
| Expected return on plan assets | % | % | % | % | |||||||||||||||||||||||||
Health care grading trend rates (a) | |||||||||||||||||||||||||||||
(a)Trend rates based on a 7 year grading period.
In September 2024, the Company approved a plan amendment for certain other postretirement benefit plans, resulting in the recognition of prior service credits of $21 million and presented as “Postretirement benefit prior service (credits) costs, net” on the Consolidated Statements of Comprehensive Income (Loss).
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The expected long-term rates of return for pension and other postretirement plans are based on management's projections using a best-estimate of expected returns, volatilities, and correlations for each asset class. Each plan’s specific current and expected asset allocations are also considered in developing a reasonable return assumption.
Contributions and Payments. TES contributed $62 million and $43 million to the TES sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively. Talen Montana contributed $8 million and $10 million of discretionary contributions to the Talen Montana sponsored pension plan during the years ended December 31, 2025 (Successor) and 2024 (Successor), respectively.
TES expects to contribute $26 million to the TES sponsored pension plan in 2026. Talen Montana expects to contribute a non material amount to the Talen Montana sponsored pension plan in 2026.
The aggregate benefits paid to pension and other postretirement plan participants was $102 million for year ended December 31, 2025 (Successor) and $114 million for the year ended December 31, 2024 (Successor).
The forecasted undiscounted benefit payments to plan participants as of December 31, 2025 (Successor) were:
| 2026 | 2027 | 2028 | 2029 | 2030 | 2031-2035 | |||||||||||||||||||||||||||||||||
| Pension plans | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
| Other postretirement plans | ||||||||||||||||||||||||||||||||||||||
Pension plan assets. Pension plan assets are held in external trusts, including a master trust, which includes a 401(h) account that is restricted for certain other postretirement benefit obligations of Talen Energy Supply. The plans’ investment policies outline investment objectives.
The risk management framework categorizes the plan assets within three sub-portfolios: growth, immunizing, and liquidity. The trust investments within these portfolios are routinely monitored to seek a risk-adjusted return on a mix of assets that, in combination with our funding policy, will provide sufficient assets to provide long-term growth and liquidity for benefit payments, match asset duration with the expected liability duration, and mitigate concentrations of risk with asset diversification.
The weighted-average target asset allocations for the pension plan assets as of December 31, 2025 (Successor) were:
| Equity securities | % | |||||||
| Debt securities | % | |||||||
| Other | % | |||||||
| Growth portfolio | % | |||||||
| Debt securities | % | |||||||
| Other | % | |||||||
| Immunizing portfolio | % | |||||||
| Liquidity portfolio | % | |||||||
| Total | % | |||||||
See Note 1 for additional descriptions on fair value levels. The classifications of pension plan asset fair value measurements within the fair value hierarchy were:
| Successor | ||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||
| Level 1 | NAV | Total | Level 1 | NAV | Total | |||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||
| Commingled equity securities | ||||||||||||||||||||||||||
| Commingled debt securities | ||||||||||||||||||||||||||
| Alternative and other investments | ( | ( | ||||||||||||||||||||||||
Receivables (payables), net (a) | — | — | ||||||||||||||||||||||||
| Total plan assets | $ | ( | $ | $ | $ | ( | $ | $ | ||||||||||||||||||
__________________
(a) Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
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Other postretirement benefit plan assets. The investment strategy with respect to most of the other postretirement benefit obligations is to fund VEBA or similar trusts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes.
The target asset allocations for other postretirement benefit assets were:
Successor | ||||||||
| December 31, 2025 | ||||||||
| Cash and cash equivalents | % | |||||||
| Equity securities | % | |||||||
| Debt securities | % | |||||||
| Total | % | |||||||
See Note 1 for additional descriptions on fair value levels. The classifications of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were:
| Successor | ||||||||||||||||||||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Total | Level 1 | Level 2 | NAV | Total | |||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
| Commingled equity securities | ||||||||||||||||||||||||||||||||
| U.S. Government debt securities | ||||||||||||||||||||||||||||||||
| Corporate debt securities | ||||||||||||||||||||||||||||||||
| Commingled debt securities | — | — | — | — | ||||||||||||||||||||||||||||
| Total plan assets | $ | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||
Defined Contribution Plan
Substantially all Company employees are eligible to participate in the Company’s 401(k) deferred savings plans. Employer contributions to the plans were $29 million for the year ended December 31, 2025 (Successor), $25 million for the year ended December 31, 2024 (Successor), $9 million for the period from May 18 through December 31, 2023 (Successor), and $10 million for the period from January 1 through May 17, 2023 (Predecessor).
13. Stock-Based Compensation
In June 2023, TEC began granting performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors under the Company’s 2023 Equity Incentive Plan (the “Equity Plan”). The aggregate number of shares authorized for issuance under the Equity Plan is 7,083,461 shares of common stock.
Equity to Liability Modification
In December 2025, certain executive officers executed agreements providing for certain PSU and RSU awards that are scheduled to vest in 2026 to be partially settled in cash. Generally, the cash settlement amount will be equal up to 60 % of the net after-tax value on the vesting date of each such award. However, the cash settlement amount is subject to a cap. Additionally, all non-employee directors are expected to be offered the ability to net-settle (to account for income taxes) all of their PSUs and RSUs. Accordingly, the portion of each participant’s applicable awards that are expected to be settled in cash and all non-employee director awards were reclassified from equity to liability. As a result of the modification, a $501 million liability was recognized and presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets and was measured based on the closing share price of Talen’s common stock of $374.84 as of December 31, 2025 (Successor).
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Performance Stock Units
PSUs have three-year or two-year cliff vesting schedules or vest upon consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs.
Changes in non-vested PSUs during the year ended December 31, 2025 (Successor) were:
| Liability-Classified PSUs | Equity-Classified PSUs | Total PSUs | Weighted-Average Grant Date Fair Value per Unit | |||||||||||||||||||||||
| Non-vested as of December 31, 2024 (Successor) | $ | |||||||||||||||||||||||||
Granted (a) | ||||||||||||||||||||||||||
| Forfeited | ( | ( | ||||||||||||||||||||||||
Equity to liability modification (b) | ( | |||||||||||||||||||||||||
Non-vested as of December 31, 2025 (Successor) (c) | $ | |||||||||||||||||||||||||
_____________
(a)The weighted-average grant date fair value per unit was $96.00 and $54.35 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.
(b)See description of December 2025 equity to liability modification above.
(c)Represents the target number of PSUs. Subject to the PSU award agreements, the actual amount of PSUs earned by participants at vesting can range from 0 % to 200 % of the target number of PSUs based on the Company’s stock price performance. In addition, certain of the PSUs are eligible to earn an additional amount of Talen shares based on the incremental Company stock price performance in excess of the PSU targets. Assuming all non-vested PSUs vested on December 31, 2025 (Successor) at the then current share price of the Company’s common stock the aggregate non-vested PSUs would be 1,268,275 .
| Successor | ||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | ||||||||||||||||||
Volatility (a) | % | % | ||||||||||||||||||
| Expected term (in years) | ||||||||||||||||||||
Risk-free rate (b) | % | |||||||||||||||||||
(a) Derived from an option pricing method based on the average asset volatility of peer companies and the Company’s leverage ratio.
(b) Based on the U.S. constant maturity treasury rate with a term matching the expected time to the end of the performance measurement period.
Restricted Stock Units
RSUs have three-year ratable or two-year cliff vesting schedules beginning on the grant date, with restrictions on transferring settled shares prior to the final scheduled vesting date for the three-year awards. The fair value of RSUs granted is based on the closing price of TEC common stock on the grant date.
Changes in non-vested RSUs during the year ended December 31, 2025 (Successor) were:
Liability-Classified RSUs | Equity-Classified RSUs | Total RSUs | Weighted-Average Grant Date Fair Value per Unit | |||||||||||||||||||||||
| Non-vested as of December 31, 2024 (Successor) | $ | |||||||||||||||||||||||||
Granted (a) | ||||||||||||||||||||||||||
| Forfeited | ( | ( | ||||||||||||||||||||||||
| Vested | ( | ( | ||||||||||||||||||||||||
Equity to liability modification (b) | ( | |||||||||||||||||||||||||
Non-vested as of December 31, 2025 (Successor) | $ | |||||||||||||||||||||||||
(a)The weighted-average grant date fair value per unit was $121.89 and $48.46 for the year ended December 31, 2024 (Successor) and for the period May 18 through December 31, 2023 (Successor), respectively.
(b)See description of December 2025 equity to liability modification above.
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Stock-based Compensation Expense
Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations was:
| Successor | ||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | ||||||||||||||||||
| Stock-based compensation expense, liability-classified awards | $ | $ | $ | |||||||||||||||||
| Stock-based compensation expense, equity-classified awards | ||||||||||||||||||||
| Income tax benefit | ( | ( | ( | |||||||||||||||||
| After-tax stock-based compensation expense | $ | $ | $ | |||||||||||||||||
Unrecognized stock-based compensation expense and related periods of recognition as of December 31, 2025 (Successor) were:
PSUs | RSUs | |||||||||||||||||||||||||
Equity-Classified | Liability-Classified | Equity-Classified | Liability-Classified | |||||||||||||||||||||||
Unrecognized stock-based compensation expense (a) | $ | $ | $ | $ | ||||||||||||||||||||||
| Weighted-average period of recognition (in years) | ||||||||||||||||||||||||||
__________________
(a) Stock-based compensation expense related to liability-classified awards is subject to variability due to changes in their value through the settlement date.
14. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Numerator: (Millions of Dollars) | |||||||||||||||||||||||||||||
| Net Income (Loss) | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Less: | |||||||||||||||||||||||||||||
| Net income (loss) attributable to noncontrolling interest | ( | ||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
| Denominator: (Thousands) | |||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic | |||||||||||||||||||||||||||||
| Warrants | |||||||||||||||||||||||||||||
| Restricted stock units | |||||||||||||||||||||||||||||
| Performance stock units | |||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted | |||||||||||||||||||||||||||||
| Earnings per Share - Basic | $ | ( | $ | $ | N/A | ||||||||||||||||||||||||
| Earnings per Share - Diluted | ( | N/A | |||||||||||||||||||||||||||
There were 151,505 RSUs and 1,631,614 PSUs excluded from dilutive EPS for the year ended December 31, 2025 (Successor) because the Company generated a net loss. No 134,798 PSUs were excluded from diluted EPS for the period from May 18 through December 31, 2023 (Successor) due to their anti-dilutive nature. These awards are excluded from the calculation of EPS because the performance conditions have not been met during the reporting period.
For the period from January 1 through May 17, 2023 (Predecessor), there were no outstanding shares of common stock.
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15. Stockholders’ Equity
Share Repurchase Program
In September 2025, the Board of Directors approved an increase in the existing capacity of the Company’s SRP from $995 million to $2 billion and extended the expiration date from December 31, 2026 to December 31, 2028. These changes to the SRP became effective in November 2025 upon the completion of the Freedom and Guernsey Acquisitions. The remaining capacity under the SRP as of December 31, 2025 (Successor) was $2 billion.
As of December 31, 2025 (Successor), the Company had repurchased approximately 23 % of its outstanding shares of common stock for a total of approximately $2 billion, exclusive of transaction costs and excise taxes.
Summary of activity under the SRP:
| Successor | ||||||||||||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | |||||||||||||||||||||||||||||||||||||
| Number of Shares | Share Price (a) | Total Amount | Number of Shares (b)(c) | Share Price (a) | Total Amount | |||||||||||||||||||||||||||||||||
| Share repurchases | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Share retirements | ||||||||||||||||||||||||||||||||||||||
(a)Weighted average price per share, including transaction costs and excise taxes.
(b)Includes 7,307,300 shares repurchased from affiliates of Rubric in July 2024 and December 2024 at a weighted average price of $177.16 per share. Of the total shares repurchased by the Company, $850 million purchased from affiliates of Rubric were not under the SRP.
(c)Includes 5,275,862 shares repurchased as result of a tender offer in June 2024 at a weighted average price of $117.16 per share.
As of December 31, 2025 (Successor), all repurchased shares have been retired. See Note 1 for the accounting policy related to treasury stock and retirement of treasury stock.
Noncontrolling Interests
Purchase of Equity in Nautilus. In October 2024, the Company acquired TeraWulf’s 25 % equity interest in Nautilus in exchange for $85 million and the distribution by Nautilus of its Bitcoin mining equipment to TeraWulf. As a result of the transaction, the Company owns 100 % of the equity of Nautilus. In conjunction with the transaction, we suspended Bitcoin mining operations at the facility.
Purchase of Equity in Cumulus Digital. In March 2024, TES acquired all of the equity of Cumulus Digital held by affiliates of Orion Energy Partners and two former members of Talen senior management in exchange for an aggregate of $39 million in cash. Following these transactions, TES owns 100 % of the equity of Cumulus Digital.
Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Beginning balance | $ | ( | $ | ( | $ | $ | ( | ||||||||||||||||||||||
Gains (losses) arising during the period | ( | ||||||||||||||||||||||||||||
Reclassifications to Consolidated Statements of Operations | ( | ||||||||||||||||||||||||||||
| Income tax benefit (expense) | ( | ( | ( | ||||||||||||||||||||||||||
| Other comprehensive income (loss) | ( | ||||||||||||||||||||||||||||
| Cancellation of equity at Emergence | |||||||||||||||||||||||||||||
| Accumulated other comprehensive income (loss) | $ | ( | $ | ( | $ | ( | $ | ||||||||||||||||||||||
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The components of AOCI, net of tax, as of December 31, were:
| Successor | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | $ | ( | |||||||||||
| Postretirement benefit prior service credits (costs), net | ||||||||||||||
| Postretirement benefit actuarial gain (loss), net | ( | ( | ||||||||||||
| Accumulated other comprehensive income (loss) | $ | ( | $ | ( | ||||||||||
Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the years ended December 31, 2025 (Successor) and 2024 (Successor).
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 12 for additional information.
16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| Cash paid during the period | |||||||||||||||||||||||||||||
Interest and other finance charges, net of capitalized interest (a) | $ | $ | $ | $ | |||||||||||||||||||||||||
| Income taxes | |||||||||||||||||||||||||||||
| Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows | |||||||||||||||||||||||||||||
| Commodity contracts | $ | $ | ( | $ | ( | $ | |||||||||||||||||||||||
| Interest rate swap contracts (interest expense) | ( | ||||||||||||||||||||||||||||
| Unrealized (gain) loss on derivative instruments | $ | $ | ( | $ | ( | $ | |||||||||||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Cash Flows | |||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | $ | $ | $ | $ | |||||||||||||||||||||||||
| Other | ( | ( | |||||||||||||||||||||||||||
| Depreciation, amortization and accretion | $ | $ | $ | $ | |||||||||||||||||||||||||
| Reconciliation of other non-cash operating activities | |||||||||||||||||||||||||||||
| Derivative option premium amortization | $ | $ | $ | $ | |||||||||||||||||||||||||
| Bitcoin revenue | ( | ( | ( | ||||||||||||||||||||||||||
| Fair value adjustment on distribution of miners | |||||||||||||||||||||||||||||
| Other | |||||||||||||||||||||||||||||
Total | $ | $ | ( | $ | ( | $ | |||||||||||||||||||||||
| Non-cash investing activities | |||||||||||||||||||||||||||||
| Accrued PP&E additions not paid at period end | $ | $ | $ | $ | |||||||||||||||||||||||||
| Non-cash financing activities | |||||||||||||||||||||||||||||
| Non-cash increase to PP&E and decrease to other current assets for contribution of Bitcoin miners to Nautilus | $ | $ | $ | $ | |||||||||||||||||||||||||
| Non-cash decrease to PP&E and decrease to noncontrolling interest for distribution of Bitcoin miners to TeraWulf | |||||||||||||||||||||||||||||
| Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf | |||||||||||||||||||||||||||||
(a)Capitalized interest was $4 million for the year ended December 31, 2025 (Successor), $5 million for the year ended December 31, 2024 (Successor), $10 for the period from May 18 through December 31, 2023 (Successor), and $12 for the period from January 1 through May 17, 2023 (Predecessor).
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Cash and Restricted Cash
The following table provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Balance Sheets to such amounts shown on the Consolidated Statements of Cash Flows:
| Successor | ||||||||||||||
| December 31, 2025 | December 31, 2024 | |||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
Restricted cash and cash equivalents (a) | ||||||||||||||
Total | $ | $ | ||||||||||||
__________________
(a)Comprised of commodity exchange margin deposits.
17. Acquisitions and Divestitures
2026 Pending Acquisitions
Cornerstone Acquisition. On January 15, 2026, the Company entered into the Cornerstone Merger Agreement with affiliates of Energy Capital Partners to purchase (i) the Lawrenceburg Power Plant, a 1,120 MW natural gas fired combined cycle generation located in Lawrenceburg, Indiana, (ii) the Waterford Energy Center, a 875 MW natural gas fired combined cycle generation plant located in Waterford Township, Ohio; and (iii) the Darby Generating Station, a 456 MW natural gas combustion turbine plant located in Mount Sterling, Ohio, for a price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $900 million at the time of entry into the Cornerstone Merger Agreement. The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness. The acquisition will substantially expand Talen’s presence in the western PJM market and add additional efficient baseload generation assets to its fleet.
The transaction is expected to close early in the second half of 2026 and is subject to the satisfaction of customary closing conditions, including the expiration or termination of the waiting period pursuant to the Hart-Scott-Rodino Act of 1976, and regulatory approvals from the Federal Energy Regulatory Commission, Indiana Utility Regulatory Commission and other regulatory agencies.
2025 Acquisitions
Freedom and Guernsey Acquisitions. On November 25, 2025, the Company purchased all the ownership interests of Freedom and Guernsey, which increases the Company’s generating capacity by approximately 2.8 GW and provides efficient baseload generation and cash flow diversification. TES paid an aggregate purchase price of $3.8 billion in cash, paid transaction costs of $43 million presented as “Other operating income (expense), net” on the Consolidated Statements of Operations, and incurred deferred finance costs and original issuance discounts of $64 million presented as “Long-term debt” on the Consolidated Balance Sheets. See Note 10 for information on recent financing transactions related to the Freedom and Guernsey Acquisitions.
As the acquisition is a business combination, provisional fair value measurements were allocated to acquired assets and assumed liabilities with no resulting goodwill or bargain purchase adjustments. As such fair value measurements are provisional, revisions may occur up to one year from the date of acquisition as new information is obtained. The following table summarizes the provisional purchase price allocation for the identifiable assets acquired and liabilities assumed:
| November 25, 2025 | ||||||||
Cash and cash equivalents | $ | |||||||
| Accounts receivable | ||||||||
Other assets | ||||||||
Property, plant, and equipment | ||||||||
Fair value of assets acquired | $ | |||||||
| Accounts payable and other accrued liabilities | $ | |||||||
Derivative instruments | ||||||||
Other liabilities | ||||||||
Acquired fuel supply contract liabilities | ||||||||
Fair value of liabilities assumed | $ | |||||||
Aggregate purchase price | $ | |||||||
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The fair values allocated to property, plant, and equipment were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be generated by Freedom and Guernsey over their remaining economic lives utilizing market participant discount rates. Significant assumptions included the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates.
Freedom and Guernsey are each party to long-term natural gas purchase agreements with third parties. Under the terms of the arrangements, the suppliers each provide a significant amount of the natural gas required to generate power at the facilities and expire in July 2028 for Freedom and February 2033 for Guernsey. The price paid for natural gas under each contract is variable based on changes to their respective market prices earned for electric generation. Accordingly, as the wholesale price of power at each facility increases or decreases, the prices paid for fuel under the long-term contracts result in corresponding changes. As the acquired fuel supply arrangements meet executory contract accounting requirements, their acquisition fair values were measured as of the acquisition date and presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets. Such liabilities are expected to amortize as reductions to “Fuel and energy purchases” on the Consolidated Statement of Operations through expiry.
The fair values allocated to acquired fuel supply contracts were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be paid under the long-term fuel contracts through their expiration dates utilizing market participant discount rates. Significant assumptions included the forecasted prices for wholesale power and natural gas, volumetric assumptions, and discount rates.
Impact of Freedom and Guernsey Acquisitions. The following table presents revenues and earnings included in the Consolidated Statements of Operations for Freedom and Guernsey since the acquisition date (November 25, 2025) through December 31, 2025 (Successor):
| Year ended December 31, 2025 | ||||||||
| Operating Revenues | $ | |||||||
| Net Income (Loss) Attributable to Stockholders | ||||||||
Pro Forma Financial Information. The following unaudited pro forma financial information for the years ended December 31, 2025 (Successor) and 2024 (Successor) assumes the Freedom and Guernsey Acquisitions occurred on January 1, 2024. The unaudited pro forma financial information is provided for information purposes only and is not necessarily indicative of the results of operations that would have occurred had the Freedom and Guernsey Acquisitions been completed on January 1, 2024, nor is the unaudited pro forma financial information indicative of future results of operations.
| Year ended December 31, 2025 | Year ended December 31, 2024 | |||||||||||||
| Operating Revenues | $ | $ | ||||||||||||
| Net Income (Loss) Attributable to Stockholders | ( | |||||||||||||
Amortization of Acquired Fuel Supply Contracts. The acquisition fair value of natural gas fuel supply contracts presented as “Acquired fuel supply contract liabilities” on the Consolidated Balance Sheets is subject to periodic amortization. Amortization associated with these contracts was $6 million for the year ended December 31, 2025 (Successor) and presented as a reduction to “Fuel and energy purchases.”
The estimated future amortization as of December 31, 2025 (Successor) is:
| 2026 | 2027 | 2028 | 2029 | 2030 | Thereafter (a) | Total | |||||||||||||||||||||||||||||||||||
Estimated amortization of acquired fuel supply contract liabilities | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
__________________
(a)Contracts expire in 2028 and 2033.
2025 Divestitures
Camden and Dartmouth Sales. In September 2025, we sold the Camden and Dartmouth generation facilities to an unaffiliated party for a combined as-adjusted purchase price of $25 million in cash, subject to further post-closing adjustments. A gain on sale of $22 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2025 (Successor).
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2024 Divestitures
ERCOT Sale. In May 2024, we sold our 1,710 MW Texas generation portfolio to CPS Energy for $785 million, subject to customary net working capital adjustments. A gain on sale of $564 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the year ended December 31, 2024 (Successor).
AWS Data Campus Sale. In March 2024, AWS purchased substantially all the assets related to the AWS Data Campus and certain other assets for gross proceeds of $650 million, of which $350 million were received at closing with the remaining $300 million held in escrow until August 2024. For the year ended December 31, 2024 (Successor), a $324 million gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. In connection with the AWS Data Campus Sale, the Company entered into the initial AWS PPA. In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of “front-of-the-meter” power through 2042. The transition to the revised AWS PPA is expected to occur in Spring 2026.
2023 Divestitures
Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to the transportation of natural gas in the southwestern United States for $15 million. For the period from January 1 through May 17, 2023 (Predecessor), a $15 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. For the period from January 1 through May 17, 2023 (Predecessor), a $29 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
18. Segments
Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our Chief Executive Officer, who is the chief operating decision maker (the “CODM”), reviews results. Adjusted EBITDA is the key profit metric used by the CODM to review segment performance and allocate resources as it provides a clearer view of segment profitability by focusing on operational performance. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker.
“PJM” is engaged in electricity generation, marketing activities, and commodity risk and fuel management within the PJM market and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities in PJM.
“Other” represents an operating segment that includes the operating and marketing activities of Talen Montana’s proportionate share of Colstrip in the WECC market and other non-material operating and development activities. “Other” also includes the operating activities of Nautilus until Bitcoin mining operations were suspended in October 2024 and the operating activities of our Texas power generation facilities in the ERCOT market prior to their disposition in May 2024. We have determined it appropriate to aggregate results of Talen’s remaining non-reportable segments and other operating activities.
“Corporate and Eliminations” represents a non-reportable segment that includes: (i) general and administrative expenses incurred by our corporate function; (ii) interest expense and other corporate activities not allocated to our operating segments; and (iii) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
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| PJM | Other | Corporate and Eliminations | Total | |||||||||||||||||||||||
| Year Ended December 31, 2025 (Successor) | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
Operation, maintenance and development expenses (a) | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
Other segment items (b) | ||||||||||||||||||||||||||
Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
| Year Ended December 31, 2024 (Successor) | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
Operation, maintenance and development expenses (a) | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
Other segment items (b) | ||||||||||||||||||||||||||
Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
| May 18 through December 31, 2023 (Successor) | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
Operation, maintenance and development expenses (a) | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
Other segment items (b) | ||||||||||||||||||||||||||
Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
| January 1 through May 17, 2023 (Predecessor) | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
Operation, maintenance and development expenses (a) | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
Other segment items (b) | ||||||||||||||||||||||||||
Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
__________________
(a)This significant segment expense category aligns with the segment-level information that is regularly provided to the CODM.
(b)Other segment items are primarily comprised of fuel and energy purchases.
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Reconciliation of segment Adjusted EBITDA to Income (Loss) Before Income Taxes:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||
| PJM Segment Adjusted EBITDA | $ | $ | $ | $ | |||||||||||||||||||||||||
| Reconciling Items: | |||||||||||||||||||||||||||||
| Interest expense and other finance charges | $ | ( | $ | ( | $ | ( | $ | ( | |||||||||||||||||||||
Depreciation, amortization and accretion (a) | ( | ( | ( | ( | |||||||||||||||||||||||||
Nuclear fuel amortization (a) | ( | ( | ( | ( | |||||||||||||||||||||||||
Reorganization income (expense), net (Note 20) (b) | |||||||||||||||||||||||||||||
| Unrealized gain (loss) on commodity derivative contracts | ( | ( | |||||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | |||||||||||||||||||||||||||||
Stock-based and other long-term incentive compensation expense (Note 13) (b) | ( | ( | ( | ||||||||||||||||||||||||||
Gain (loss) on asset sales, net (Note 17) (b) | |||||||||||||||||||||||||||||
Non-cash impairments and other charges (c) | ( | ( | ( | ( | |||||||||||||||||||||||||
Legal settlements and litigation costs | ( | ( | ( | ||||||||||||||||||||||||||
Acquisition and divestiture activities (d) | ( | ( | |||||||||||||||||||||||||||
Operational and other restructuring activities (e) | ( | ( | ( | ( | |||||||||||||||||||||||||
| "Other" operating segment | |||||||||||||||||||||||||||||
| Noncontrolling interest | |||||||||||||||||||||||||||||
| Corporate and Eliminations | ( | ( | ( | ( | |||||||||||||||||||||||||
| Other items | ( | ( | ( | ( | |||||||||||||||||||||||||
| Income (Loss) Before Income Taxes | $ | ( | $ | $ | $ | ||||||||||||||||||||||||
__________________
(a)Includes the periodic amortization of fair value adjustments associated with acquired executory contracts and intangible assets.
(b)See the corresponding Note to the Annual Financial Statements for additional information.
(c)Includes impairments, net realizable value adjustments and other write-offs. See Note 7 for additional information associated with the Brandon Shores impairment group recognized during the period of January 1 through May 17, 2023 (Predecessor).
(d)Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.
(e)Non-recurring severance and retention costs and strategic initiative costs.
19. Emergence from Restructuring
Voluntary Reorganization Under Chapter 11 of the U.S. Bankruptcy Code
In May 2022, TES and 71 of its subsidiaries voluntarily commenced the Restructuring under Chapter 11 of the U.S. Bankruptcy Code. TEC joined the Restructuring in December 2022. The Plan of Reorganization was approved by the requisite parties and confirmed by the bankruptcy court in late 2022, and was consummated and became effective in May 2023, when TEC, TES, and the other debtors emerged from the Restructuring.
Prior to and during the Restructuring, TES and its debtor subsidiaries reached a number of settlements with various stakeholders (including certain holders of claims under TES’s prepetition indebtedness, certain affiliates Riverstone Holdings, LLC (“Riverstone”) (which then held all of the equity in TEC), TEC, and the Official Committee of Unsecured Creditors), the terms of which were incorporated into the Plan of Reorganization. Under the settlements, the Company agreed to conduct a common equity rights offering, which certain holders of prepetition unsecured notes agreed to backstop in exchange for subscription rights to purchase 30 % of the new equity issued plus a backstop premium payment in the form of cash and (or) new equity.
Restructuring Transactions and Emergence
The Restructuring transactions were completed, and the Company emerged from the Restructuring, on May 17, 2023. Pursuant to the Plan of Reorganization, among other things:
•Claims against TEC were paid in full in cash or reinstated. All existing equity interests in TEC were extinguished, and new equity interests in TEC were issued as follows:
•Holders of unsecured claims under TES’s prepetition indebtedness (including the backstopping holders) received: (i) TEC equity; and (ii) subscription rights to purchase additional TEC equity in the equity rights offering.
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•The equity rights offering was consummated, resulting in $1.4 billion in net cash proceeds to the Company. The backstopping holders (i) fully exercised their subscription rights; (ii) were required to purchase additional unsubscribed-for TEC equity; and (iii) were paid the remaining portion of the backstop premium in the form of TEC equity.
•Riverstone received: (i) 1 % of the equity in TEC; (ii) a contingent right to receive additional TEC equity or cash upon certain conditions following Emergence; and (iii) warrants to purchase additional TEC equity. In the third quarter 2023, Riverstone surrendered the warrants and waived its contingent right to additional TEC equity or cash in exchange for $40 million in cash.
•The existing intercompany ownership structure of the debtors remained in place and intercompany claims were extinguished.
•The Company consummated its exit financings, comprised of the RCF, TLB-1, TLC, TLC LCF, Bilateral LCF, and Secured Notes. The PEDFA 2009B and 2009C Bonds remained outstanding following the Restructuring.
•The proceeds of the equity rights offering and the exit financings, together with cash on hand, were used to fully repay the Company’s debtor-in-possession credit facilities and to pay $3.1 billion relating to other secured claims.
•Holders of other unsecured claims received interests in a designated $26 million pool of cash, to which Talen Montana subsequently contributed an additional $11 million from proceeds of the PPL/Talen Montana settlement. See Note 9 for additional information on the PPL/Talen Montana settlement.
20. Fresh Start Accounting
At Emergence, TES adopted fresh start accounting as: (i) the holders of existing voting shares before the consummation of the Plan of Reorganization received less than 50 % of the voting shares of the Successor; and (ii) the reorganization value of TES’s assets immediately prior to confirmation of the Plan of Reorganization of $7.8 billion was less than the total of post-petition liabilities and allowed claims of $9.8 billion. Accordingly, TES allocated its reorganization value to its individual assets based on their estimated fair values.
Reorganization Value
Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and member’s equity. As negotiated in the Plan of Reorganization and related disclosure statement approved by the Bankruptcy Court, the enterprise value as of Emergence was $4.5 billion. Management engaged third-party valuation advisors to assist in estimating the enterprise value and allocating the enterprise value to the assets and liabilities for financial reporting purposes as of Emergence. Enterprise value assumptions incorporated: (i) economic and industry information relevant to the business; (ii) internal financial information and operating data; (iii) historical financial information; and (iv) financial projections and other applicable assumptions. The valuation techniques used to estimate the enterprise value as of Emergence included the income approach, market approach, and cost approach, with consideration of the exit market and nature of the applicable asset or liability subject to valuation.
The Company’s principal assets are generation facilities whose values were determined by a discounted cash flow analysis based on management’s latest outlook of the business through the end of their expected useful lives. The forward-looking projections considered: (i) company-specific factors, such as unit characteristics, plant dispatch, operating expenses, capital expenditures and estimated economic useful lives; and (ii) macroeconomic factors, such as capacity prices, energy prices, fuel prices, market supply and demand factors, inflation factors, and environmental regulations. Commodity prices used to estimate future cash flows in observable periods were primarily based on adjusted exchange prices, prices provided by brokers, or prices provided by price service companies that are corroborated by market data. Commodity prices for future unobservable periods used third party pricing services that incorporate industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, inflation assumptions, and other relevant economic measures. Future estimates for capital expenditures and operating expenses, such as major maintenance and employee compensation were estimated considering unit operating experience, recent historical financial information, and expected operating performance. The expected useful lives of the generation facilities were estimated through 2050 and incorporated expectations regarding the economic prospects of each unit, permitting and licensing, regulatory requirements, and (or) other considerations. The cash flow estimates incorporated a federal effective tax rate of 21% and the applicable state tax rate based on the location of each generation facility. The present value of expected future cash flows utilized a weighted average cost of capital discount rate that ranged from 8.5 % to 46.5 %. The discount rate utilized for nuclear generation was 8.5 % and certain natural gas generation facilities were estimated near the low end of the range. Certain coal and natural gas generation units were estimated near the high end of the range. Discount rates for each generation facility considered, among other things, unit characteristics, fuel type, and market location.
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The assumptions used to estimate the reorganization value considered all available evidence as of Emergence and are believed to be consistent with those used by the principal market participants and outlook for each generation facility and represent management’s best estimate of reorganization value. However, such assumptions are inherently uncertain and require judgment. Accordingly, changes to sensitive assumptions, which primarily include commodity prices and discount rates, would have a reasonable possibility of significantly affecting the measurement of the reorganization value. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities.
Upon the application of fresh start accounting, the Company preliminarily allocated the reorganization value to its individual assets based on their estimated fair values. The following table reconciles the Company’s enterprise value to the estimated reorganization value at Emergence:
| May 17, 2023 | ||||||||
Enterprise value (a) | $ | |||||||
Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) | ||||||||
| Plus: Current liabilities excluding long-term debt due within one year | ||||||||
| Plus: Non-current liabilities excluding long-term debt and liability-classified warrants | ||||||||
| Plus: Fair value of noncontrolling interest | ||||||||
| Reorganization value to be allocated | $ | |||||||
__________________
(a)Excludes any value associated with noncontrolling interest.
(b)Excludes $52 million for payment of professional fees.
The following table reconciles TES’s enterprise value to the estimated fair value at Emergence:
| May 17, 2023 | ||||||||
Enterprise value (a) | $ | |||||||
Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) | ||||||||
| Less: Fair value of debt | ( | |||||||
| Less: Liability-classified warrants | ( | |||||||
Fair value of member’s equity (c) | ||||||||
| Plus: Fair value of noncontrolling interest | ||||||||
| Fair value of equity | $ | |||||||
__________________
(a)Excludes any value associated with noncontrolling interest.
(b)Excludes $52 million for payment of professional fees.
(c)Issued in accordance with the Plan of Reorganization. Includes 59,028,843 shares of TEC common stock and $8 million of equity-classified warrants.
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Consolidated Balance Sheet
The “Reorganization Adjustments” on the fresh start Consolidated Balance Sheet as of Emergence present the aggregate effect of the transactions contemplated by the Plan of Reorganization. The “Fresh Start Adjustments” present the preliminary fair value and other required adjustments as a result of applying fresh start accounting. The explanatory notes provide additional information related to the adjustments, the methods used to determine fair values, and significant assumptions.
| May 17, 2023 | ||||||||||||||||||||||||||
| Assets | Predecessor | Reorganization Adjustments (a) | Fresh Start Adjustments | Successor | ||||||||||||||||||||||
| Cash and cash equivalents | $ | $ | ( | (b) | $ | $ | ||||||||||||||||||||
| Restricted cash and cash equivalents | (c) | ( | (q) | |||||||||||||||||||||||
| Accounts receivable, net | ( | (d) | ||||||||||||||||||||||||
| Inventory, net | ( | (r) | ||||||||||||||||||||||||
| Derivative instruments | ( | (q) | ||||||||||||||||||||||||
| Other current assets | ( | (s) | ||||||||||||||||||||||||
| Total current assets | ( | ( | ||||||||||||||||||||||||
| Property, plant and equipment, net | ( | (t) | ||||||||||||||||||||||||
| Nuclear decommissioning trust funds | ||||||||||||||||||||||||||
| Derivative instruments | ( | (q) | ||||||||||||||||||||||||
| Other noncurrent assets | ( | (e) | (u) | |||||||||||||||||||||||
| Total Assets | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||
| Liabilities and Equity | ||||||||||||||||||||||||||
| Revolving credit facilities | $ | $ | ( | (f) | $ | $ | ||||||||||||||||||||
| Long-term debt, due within one year | ( | (g) | ||||||||||||||||||||||||
| Accrued interest | ( | (h) | ||||||||||||||||||||||||
| Accounts payable and other accrued liabilities | (i) | |||||||||||||||||||||||||
| Derivative instruments | ( | (q) | ||||||||||||||||||||||||
| Other current liabilities | ( | (j) | (v) | |||||||||||||||||||||||
| Total current liabilities | ( | ( | ||||||||||||||||||||||||
| Long-term debt | (k) | (w) | ||||||||||||||||||||||||
| Liabilities subject to compromise | ( | (l) | ||||||||||||||||||||||||
| Derivative instruments | ( | (q) | ||||||||||||||||||||||||
| Postretirement benefit obligations | ( | (m) | (x) | |||||||||||||||||||||||
| Asset retirement obligations and accrued environmental costs | (m) | ( | (y) | |||||||||||||||||||||||
| Deferred income taxes | (n) | ( | (z) | |||||||||||||||||||||||
| Other noncurrent liabilities | (o) | (aa) | ||||||||||||||||||||||||
| Total Liabilities | ( | ( | ||||||||||||||||||||||||
| Member’s equity | ( | (p) | ( | (bb) | ||||||||||||||||||||||
| Noncontrolling interests | ( | (cc) | ||||||||||||||||||||||||
| Total Equity | ( | ( | ||||||||||||||||||||||||
| Total Liabilities and Equity | $ | $ | ( | $ | ( | $ | ||||||||||||||||||||
Reorganization Adjustments
The reorganization adjustments required in connection with the application of fresh start accounting and the allocation of the enterprise value were:
(a)Emergence adjustments for the implementation of the Plan of Reorganization. Such adjustments include: (i) settlement of prepetition liabilities subject to compromise; (ii) payment of certain prepetition indebtedness; (iii) issuances of member’s equity; (iv) recognition of new indebtedness and related restricted cash; and (v) other items.
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Item 8. Table of Contents
(b)The uses of “Cash and cash equivalents” at Emergence resulting from the implementation of the Plan of Reorganization were:
| Proceeds from rights offering | $ | |||||||
| Proceeds from TLB-1 and TLC | ||||||||
| Proceeds from Secured Notes | ||||||||
| Release of restricted cash | ||||||||
| Payment of claims under prepetition senior secured revolving credit facility | ( | |||||||
| Payment of claims under other prepetition secured indebtedness | ( | |||||||
| Payment of debtor-in-possession term loan | ( | |||||||
| Restriction of cash relating to TLC LCF | ( | |||||||
| Payment of debt issuance costs on exit financing (TLB-1, TLC, and Secured Notes) | ( | |||||||
| Funding of professional fees escrow account | ( | |||||||
| Payment of hedge rejections | ( | |||||||
| Payment to general unsecured creditors trust | ( | |||||||
| Payment of professional fees | ( | |||||||
Other (a) | ||||||||
| Total uses of Cash and cash equivalents | $ | ( | ||||||
__________________
(a)Includes $1 million of proceeds from Riverstone for payment to general unsecured creditors trust.
(c)“Restricted cash and cash equivalents” net change:
| Restriction of cash relating to TLC LCF | $ | |||||||
| Funding of professional fees escrow account | ||||||||
| Release of restricted cash | ( | |||||||
| Payment of professional fees | ( | |||||||
| Net change in Restricted cash and cash equivalents | $ | |||||||
(d)“Accounts receivable, net” net change related to settlement of affiliate receivables.
(e)“Other noncurrent assets” net change:
| Write-off of debt issuance costs associated with prepetition senior secured revolving credit facility | $ | ( | ||||||
| Reclassification of previously capitalized debt issuance costs to Long-term debt | ( | |||||||
| Capitalization of debt issuance costs | ||||||||
| Net change in Other noncurrent assets | $ | ( | ||||||
(f)Payment of principal amounts owed under prepetition senior secured revolving credit facility.
(g)Repayment of debtor-in-possession credit facilities.
(h)“Accrued interest” net change:
| Payment of accrued interest on prepetition senior secured revolving credit facility | $ | ( | ||||||
| Payment of accrued interest on other prepetition secured indebtedness | ( | |||||||
| Payment of accrued interest on debtor-in-possession credit facilities | ( | |||||||
| Net change in Accrued interest | $ | ( | ||||||
(i)“Accounts payable and other accrued liabilities” net change:
| Payment of hedge contract rejections | $ | ( | ||||||
| Payment of professional fees | ( | |||||||
| Reinstatement of liabilities subject to compromise | ||||||||
| Accrual for professional fees incurred at Emergence | ||||||||
| Net change in Accounts payable and other accrued liabilities | $ | |||||||
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Item 8. Table of Contents
(j)“Other current liabilities” net change:
| Issuance of equity for backstop premium | $ | ( | ||||||
| Reinstatement of liabilities subject to compromise | ||||||||
| Net change in Other current liabilities | $ | ( | ||||||
(k)“Long-term debt” net change:
| Payment of claims under prepetition secured indebtedness | $ | ( | ||||||
Borrowings of $ | ||||||||
Borrowings of $ | ||||||||
Borrowings of $ | ||||||||
Reinstatement of PEDFA 2009B Bonds and PEDFA 2009C Bonds (d) | ||||||||
| Write-off of prepetition secured indebtedness issuance costs | ||||||||
| Net change in Long-term debt | $ | |||||||
______________
(a)Net of an aggregate initial purchaser discount and debt issuance costs of $21 million.
(b)Net of an aggregate original issue discount and debt issuance costs of $32 million.
(c)Net of an aggregate original issue discount and debt issuance costs of $24 million.
(d)Includes recognition of $4 million of interest expense.
(l)“Liabilities subject to compromise” settled or reinstated at Emergence in accordance with the Plan of Reorganization:
| Liabilities subject to compromise prior to Emergence | ||||||||
| Debt | $ | |||||||
| Termination of retail contracts | ||||||||
| Postretirement benefit obligations | ||||||||
| Asset retirement obligations and accrued environmental costs | ||||||||
| Other liabilities | ||||||||
| Deferred tax liabilities | ||||||||
| Accounts payable and accrued liabilities | ||||||||
| Accrued interest | ||||||||
| Total | ||||||||
| Reinstatement and settlements of certain Liabilities subject to compromise | ||||||||
Reinstatement of liabilities subject to compromise (a) | ( | |||||||
| Excess fair value ascribed to lenders participating in rights offering | ( | |||||||
| Issuance of member’s equity to holders of claims under prepetition unsecured notes and PEDFA 2009A Bonds | ( | |||||||
| Payment to general unsecured creditors trust | ( | |||||||
| Total | ( | |||||||
Gain on derecognition of certain Liabilities subject to compromise (b) | $ | |||||||
______________
(a)Primarily includes postretirement benefit obligations, AROs, and deferred income taxes.
(b)Represents liabilities subject to compromise that were discharged in accordance with the Plan of Reorganization.
(m)Reinstatement of “Liabilities subject to compromise.”
(n)“Deferred income taxes” net change:
| Increase in deferred tax liabilities primarily due to estimated tax attribute reduction from the recognition of cancellation of debt income, partially offset by change in valuation allowance | $ | |||||||
| Reinstatement of liabilities subject to compromise | ||||||||
| Net change in Deferred income taxes | $ | |||||||
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Item 8. Table of Contents
(o)“Other noncurrent liabilities” net change:
| Issuance of liability-classified warrants | $ | |||||||
| Reinstatement of liabilities subject to compromise | ||||||||
| Net change in Other noncurrent liabilities | $ | |||||||
The estimated fair value of liability-classified warrants was determined using a Black-Scholes Option Pricing Model with the following assumptions at Emergence:
| Expected volatility | % | |||||||
| Expected term (years) | ||||||||
| Expected dividend yield | % | |||||||
| Risk-free interest rate | % | |||||||
| Strike price per share | $ | |||||||
| Fair value per share | $ | |||||||
(p)“Member’s equity” net change:
| Gain on settlement of liabilities subject to compromise | $ | |||||||
| Other losses attributable to gain on debt discharge | ( | |||||||
| Gain on debt discharge | ||||||||
| Write-off of deferred financing cost | ( | |||||||
| Professional fees expensed at Emergence | ( | |||||||
| Restructuring-related compensation expense | ( | |||||||
| Total reorganization items from reorganization adjustments | ||||||||
| Interest expense incurred at Emergence | ( | |||||||
| Income from reorganization adjustments before income taxes | ||||||||
| Income tax expense | ( | |||||||
| Net income from reorganization adjustments | ||||||||
| Issuance of member’s equity in connection with rights offering | ||||||||
| Issuance of member’s equity for backstop premium | ||||||||
| Issuance of member’s equity to holders of claims under prepetition unsecured notes and PEDFA 2009A Bonds | ||||||||
| Issuance of equity-classified warrants | ||||||||
| Issuance of liability-classified warrants | ( | |||||||
Other (a) | ( | |||||||
| Net change in Member’s equity | $ | |||||||
______________
(a)Includes $1 million of proceeds from Riverstone for payment to general unsecured creditors trust.
Fresh Start Adjustments
(q)Net presentation of derivatives on the Consolidated Balance Sheets. See Note 1 for additional information on the related accounting policy.
(r)“Inventory, net” fair value adjustments:
| Coal | $ | ( | ||||||
| Oil products | ||||||||
| Materials and supplies | ( | |||||||
| Environmental products | ||||||||
| Total adjustment to Inventory, net | $ | ( | ||||||
The fair values for oil, coal and environmental products were estimated using current market prices. The fair values of materials and supplies were estimated using an indirect cost approach. The cost approach estimates fair value by considering the amount required to construct or purchase a new asset of equal utility at current prices, with adjustments for asset function, age, physical deterioration, and obsolescence.
(s)“Other current assets” primarily represents miscellaneous fair value adjustments.
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Item 8. Table of Contents
(t)“Property, plant and equipment, net” fair value adjustments:
| Electric generation | $ | ( | ||||||
| Other property and equipment | ( | |||||||
| Intangible assets | ( | |||||||
| Capitalized software | ( | |||||||
| Construction work in progress | ||||||||
| Total adjustment to Property, plant and equipment, net | $ | ( | ||||||
The fair value of “Property, plant and equipment, net” was estimated using the income approach, market approach and cost approach, as applicable. The fair value of land was estimated utilizing the market approach, which considered comparable market-based transactions within a defined area based on size, use and utility.
(u)“Other noncurrent assets” fair value adjustments:
Favorable supply contracts (a) | $ | |||||||
| Fair value adjustment to equity method investments | ||||||||
| Eliminate debt issuance costs associated with debtor-in-possession credit facilities | ( | |||||||
| Fair value reduction to other miscellaneous assets | ( | |||||||
| Total adjustment to Other noncurrent assets | $ | |||||||
__________________
(a)The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and a current market benchmark.
(v)“Other current liabilities” fair value adjustments, primarily related to short-term AROs.
(w)“Long-term debt” fair value adjustments:
| Eliminate debt issuance costs associated with prepetition secured notes, prepetition TLB and LMBE-MC TLB | $ | |||||||
| Fair value adjustment to Cumulus Digital TLF | ||||||||
| Fair value adjustment to LMBE-MC TLB | ( | |||||||
| Total adjustment to Long-term debt | $ | |||||||
Fair value adjustments to “Long-term debt” were determined using a lattice model, given that the debt can be prepaid by the borrower prior to the maturity date.
(x)Change in accounting policy for discount rates used to estimate postretirement obligations from a bond-matching model to yield curve approach.
(y)Adjustment to present at fair value AROs using assumptions as of Emergence, including an inflation factor of 2 %-3 % and an estimated 5 - to 20 -year credit-adjusted risk-free rate of 8 %-12 % based on timing of cash flows for each underlying obligation.
(z)Adjustment to “Deferred income taxes” for the change in financial reporting basis of assets and liabilities as a result of the adoption of fresh start accounting.
(aa)Fair value adjustments primarily related to unfavorable supply contracts of $13 million and the recognition of unfavorable lease liabilities. The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and current market benchmarks.
(bb)Cumulative impact of fresh start accounting adjustments presented herein.
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Item 8. Table of Contents
Liabilities Subject to Compromise
As of December 31, 2022 (Predecessor), prepetition liabilities and obligations whose treatment and satisfaction were dependent on the outcome of the Restructuring were presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. The carrying value of prepetition liabilities that were subject to compromise are presented at the best estimate of the claim amount permitted by the Bankruptcy Court. Such amounts presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets were subject to adjustments depending on bankruptcy court actions, developments with respect to disputed claims, determination of secured status of certain claims, the determination as to the value of any collateral securing claims, proof of claims and (or) other events.
| Predecessor | ||||||||
| December 31, 2022 | ||||||||
Debt (a) | $ | |||||||
| Termination of retail power and other contracts | ||||||||
Postretirement benefit obligations (a) | ||||||||
Asset retirement obligations and accrued environmental costs (a) | ||||||||
Other liabilities (a) | ||||||||
| Deferred tax liabilities | ||||||||
| Accounts payable and accrued liabilities | ||||||||
| Accrued interest | ||||||||
Derivatives (a) | ||||||||
| Liabilities Subject to Compromise | $ | |||||||
__________________
(a)Includes both current and noncurrent amounts.
Reorganization Income (Expense), net
“Reorganization income (expense), net” for the relevant periods were:
| Predecessor | ||||||||||||||
| January 1 through May 17, 2023 | Year Ended December 31, 2022 | |||||||||||||
| Backstop premium | $ | ( | $ | ( | ||||||||||
| Gain (loss) on debt discharge | ||||||||||||||
| Gain (loss) on revaluation adjustments | ( | |||||||||||||
| Professional fees | ( | ( | ||||||||||||
| Make-whole premiums and accrued interest on certain indebtedness | ( | ( | ||||||||||||
| Professional fees incurred to obtain the debtor-in-possession credit facilities | ( | |||||||||||||
| Write-off of deferred financing cost and original issue discount | ( | ( | ||||||||||||
| Other | ( | ( | ||||||||||||
| Reorganization Income (Expense), net | $ | $ | ( | |||||||||||
In the preceding table, make-whole premiums and accrued interest on certain indebtedness primarily represents charges recognized by the debtors for estimates related to make-whole premiums and accrued interest, where applicable, on the prepetition senior secured revolving credit facility and certain other prepetition secured indebtedness. As of the bankruptcy petition date, the debtors ceased recognizing interest expense on certain outstanding unsecured or under-secured prepetition indebtedness. Contractual interest expense represented amounts due under the terms of outstanding prepetition indebtedness. The charges are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations and included in “Accrued interest” on the Consolidated Balance Sheets.
Cash paid for certain reorganization expenses was $308 million for the period from January 1 through May 17, 2023 (Predecessor)
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
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ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
We have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2025.
Changes in Internal Control Over Financial Reporting
During the three months ended December 31, 2025, management was in the process of integrating the internal controls of recently-acquired entities, Freedom and Guernsey, into the Company's existing operations. Other than additional controls associated with the Freedom and Guernsey Acquisitions, there were no changes in our internal control over financial reporting that occurred during the three months ended December 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
The management of Talen Energy Corporation is responsible for establishing and maintaining adequate internal control over financial reporting, as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act, for the Company. Internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in condition or the deterioration of compliance with procedures or policies.
The management of Talen Energy Corporation performed an evaluation of the effectiveness of the Company's internal control over financial reporting as of December 31, 2025 based on the criteria described in Committee of Sponsoring Organizations of the Treadway Commission's (COSO's) Internal Control - Integrated Framework (2013). Based on the evaluation performed, management concluded that as of December 31, 2025, Talen Energy Corporation's internal control over financial reporting was effective.
As permitted by SEC Staff Guidance, management’s assessment of the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the Freedom and Guernsey Acquisitions on November 25, 2025. The Freedom and Guernsey entities are wholly-owned subsidiaries whose total assets and total revenues excluded from management’s assessment of internal control over financial reporting represented 20% of the Company's total assets as of December 31, 2025 and 6% of the Company's total revenues for the year ended December 31, 2025.
The effectiveness of our internal control over financial reporting as of December 31, 2025 has been audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report included in “Item 8. Financial Statements and Supplementary Data”.
ITEM 9B. OTHER INFORMATION
During the three months ended December 31, 2025 (Successor), none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted terminated
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS
Not applicable.
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Form 10-K Table of Contents
PART III.
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS, AND CORPORATE GOVERNANCE
Code of Business Conduct and Ethics
We have adopted a code of ethics called the “Talen Energy Corporation Code of Business Conduct and Ethics” that applies to all of our directors, officers, and employees, including our principal executive officer, principal financial officer, principal accounting officer, and persons performing similar functions. It can be accessed under the “Governance” tab on the “Investor Relations” section of our website at https://ir.talenenergy.com. A copy will also be made available in print to any stockholder who requests it. We also intend to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding any amendment to, or waiver from, a provision of our code of ethics applicable to those individuals by posting such information on our website. We will disclose the required information within four business days, and such information will remain available on our website for at least a 12-month period. There have not been any waivers granted to any of our officers or employees to date. 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 SEC.
Insider Trading Policy
We have adopted an Insider Trading Policy governing the purchase, sale and other dispositions of the Company’s securities that applies to the Company and its directors, officers and employees. We believe that the Insider Trading Policy is reasonably designed to promote compliance with insider trading laws, rules and regulations, and listing standards applicable to the Company. A copy of the Insider Trading Policy is filed as Exhibit 19.1 to this Report.
The other information required pursuant to this item is incorporated by reference into our 2026 Proxy Statement to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.
ITEM 11. EXECUTIVE COMPENSATION
The information required pursuant to this item is incorporated by reference into our 2026 Proxy Statement to be filed within 120 days of the fiscal year ended December 31, 2025.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
Equity Compensation Plan Information
The following table presents information as of December 31, 2025 with respect to compensation plans under which shares of our common stock may be issued. Such equity compensation plans include our Equity Plan and additional securities that are subject to the ESPP.
| Plan Category | (a) Number of Securities to be Issued upon Exercise of Outstanding Options, Warrants and Rights | (b) Weighted-Average Exercise Price of Outstanding Options, Warrants and Rights | (c) Number of Securities Remaining Available for Future Issuance Under Equity Compensation Plans (Excluding Securities Reflected in Column (a)) | ||||||||||||||||||||||||||
| Plans Approved by Our Security Holders | — | — | 3,486,513 | ||||||||||||||||||||||||||
Plans Not Approved by Our Security Holders (1) | 2,457,321 | (2) | — | (3) | 4,461,579 | ||||||||||||||||||||||||
| Total | 2,457,321 | — | 7,948,092 | (4) | |||||||||||||||||||||||||
__________________
(1) The formation of our Equity Plan was approved by the United States Bankruptcy Court for the Southern District of Texas (Houston Division) as part of the Joint Chapter 11 Plan of Reorganization upon our emergence from restructuring.
(2) Includes 340,653 RSUs and 2,116,668 PSUs outstanding under the Equity Plan as of December 31, 2025 (assuming all awards are issued 100% in equity). The number of PSUs included represents the maximum level of performance (or 200%).
(3) No options were outstanding as of December 31, 2025, and neither RSUs nor PSUs have an exercise price.
(4) Includes 3,486,513 shares of common stock remaining available under the ESPP and 4,461,579 shares available under the Equity Plan as of December 31, 2025.
The other information required pursuant to this item is incorporated by reference into our 2026 Proxy Statement to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required pursuant to this item in incorporated by reference into our 2026 Proxy Statement to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
The information required pursuant to this item in incorporated by reference into our 2026 Proxy Statement to be filed with the SEC within 120 days of the fiscal year ended December 31, 2025.
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PART IV.
ITEM 15. EXHIBITS AND FINANCIAL STATEMENT SCHEDULES
(a) The following documents are filed as a part of this Report:
(1) Financial Statements: The Annual Financial Statements are included with a separate index in “Item 8. Financial Statements and Supplementary Data” of this Report.
(2) Financial Statement Schedules: Schedule I—Condensed Financial Information of Registrant for the year ended December 31, 2025 (Successor) and the year ended December 31, 2024 (Successor) is included below in subsection (c) of this “Item 15. Exhibits and Financial Statement Schedules.” All other schedules are omitted because they are not applicable or because the required information is already contained in the Annual Financial Statements.
(3) Exhibits:
Incorporated by Reference | ||||||||||||||||||||||||||||||||
| Exhibit No. | Description | Form | File Number | Date of Filing | Exhibit Number | |||||||||||||||||||||||||||
2.1#^* | Agreement and Plan of Merger, dated as of January 15, 2026, by and among Talen Energy Corporation, Cornerstone Generation Holdings, LP, ECP Cornerstone Generation Holdings GP, LLC, ECP V-B (AG IP) Blocker Corp, ECP V-C (AG IP) Blocker Corp, ECP V-D (AG IP) Blocker Corp, ECP V-D, as a holder representative, and solely for the limited purposes set forth therein, ECP GP V, LP. | — | — | — | — | |||||||||||||||||||||||||||
2.2#^ | Purchase and Sale Agreement, dated as of July 17, 2025, by and between Caithness Energy, L.L.C., as seller, and Talen Generation, LLC, as buyer. | 10-Q | 001-37388 | August 7, 2025 | 2.1 | |||||||||||||||||||||||||||
2.3#^ | Purchase and Sale Agreement, dated as of July 17, 2025, by and among Caithness Energy, L.L.C., as seller, Caithness Apex Guernsey, LLC, as subsidiary seller, and Talen Generation, LLC, as buyer. | 10-Q | 001-37388 | August 7, 2025 | 2.2 | |||||||||||||||||||||||||||
| 3.1 | Third Amended and Restated Certificate of Incorporation of Talen Energy Corporation. | S-1 | 333-280341 | June 20, 2024 | 3.1 | |||||||||||||||||||||||||||
| 3.2 | Second Amended and Restated Bylaws of Talen Energy Corporation. | S-1 | 333-280341 | June 20, 2024 | 3.2 | |||||||||||||||||||||||||||
| 4.1 | Description of Capital Stock. | 10-K | 001-37388 | February 28, 2025 | 4.1 | |||||||||||||||||||||||||||
4.2# | Stockholders Agreement, dated as of May 17, 2023, by and among Talen Energy Corporation and the parties identified therein. | S-1 | 333-280341 | June 20, 2024 | 4.2 | |||||||||||||||||||||||||||
4.3# | Registration Rights Agreement, dated as of May 17, 2023, by and among Talen Energy Corporation and the holders party thereto. | S-1 | 333-280341 | June 20, 2024 | 4.1 | |||||||||||||||||||||||||||
| 4.4 | Indenture, dated as of May 12, 2023, between Talen Energy Supply, LLC and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | S-1 | 333-280341 | June 20, 2024 | 10.5 | |||||||||||||||||||||||||||
| 4.5 | First Supplemental Indenture, dated as of May 17, 2023, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | S-1 | 333-280341 | June 20, 2024 | 10.6 | |||||||||||||||||||||||||||
| 4.6 | Second Supplemental Indenture, dated as of October 6, 2023, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | S-1 | 333-280341 | June 20, 2024 | 10.7 | |||||||||||||||||||||||||||
| 4.7 | Third Supplemental Indenture, dated as of June 22, 2024, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | 10-K | 001-37388 | February 28, 2025 | 4.7 | |||||||||||||||||||||||||||
| 4.8 | Fourth Supplemental Indenture, dated as of January 13, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | 8-K | 001-37388 | January 14, 2025 | 4.1 | |||||||||||||||||||||||||||
| 4.9 | Fifth Supplemental Indenture, dated as of November 25, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as trustee (relating to the 8.625% Senior Notes due 2030). | 8-K | 001-37388 | November 25, 2025 | 4.3 | |||||||||||||||||||||||||||
| 4.10 | Indenture, dated as of October 27, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto, and Citibank, N.A., as trustee (relating to the 6.250% Senior Notes due 2034). | 8-K | 001-37388 | October 27, 2025 | 4.1 | |||||||||||||||||||||||||||
| 4.11 | Form of 6.250% Senior Notes due 2034 (included as Exhibit A to Exhibit 4.10 hereto). | 8-K | 001-37388 | October 27, 2025 | 4.2 | |||||||||||||||||||||||||||
| 4.12 | First Supplemental Indenture, dated as of November 25, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Citibank, N.A., as trustee (relating to the 6.250% Senior Notes due 2034). | 8-K | 001-37388 | November 25, 2025 | 4.2 | |||||||||||||||||||||||||||
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Incorporated by Reference | ||||||||||||||||||||||||||||||||
| Exhibit No. | Description | Form | File Number | Date of Filing | Exhibit Number | |||||||||||||||||||||||||||
| 4.13 | Indenture, dated as of October 27, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto, and Citibank, N.A., as trustee (relating to the 6.500% Senior Notes due 2036). | 8-K | 001-37388 | October 27, 2025 | 4.3 | |||||||||||||||||||||||||||
| 4.14 | Form of 6.500% Senior Notes due 2036 (included as Exhibit A to Exhibit 4.13 hereto). | 8-K | 001-37388 | October 27, 2025 | 4.4 | |||||||||||||||||||||||||||
| 4.15 | First Supplemental Indenture, dated as of November 25, 2025, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Citibank, N.A., as trustee (relating to the 6.500% Senior Notes due 2036). | 8-K | 001-37388 | November 25, 2025 | 4.2 | |||||||||||||||||||||||||||
4.16* | Form of Cornerstone Registration Rights Agreement. | — | — | — | — | |||||||||||||||||||||||||||
10.1# | Credit Agreement, dated as of May 17, 2023, by and among Talen Energy Supply, LLC, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and Citibank, N.A., BMO Capital Markets Corp., Deutsche Bank Securities Inc., Goldman Sachs Bank USA, RBC Capital Markets, LLC, MUFG Bank, Ltd., Credit Suisse Loan Funding LLC and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint bookrunners. | S-1 | 333-280341 | June 20, 2024 | 10.1 | |||||||||||||||||||||||||||
| 10.2 | Amendment No. 1 to Credit Agreement, dated as of August 9, 2023, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the persons identified on the signature pages thereto as a 2023-1 Incremental Term B Lender and Citibank, N.A., as administrative agent and as collateral agent. | S-1 | 333-280341 | June 20, 2024 | 10.2 | |||||||||||||||||||||||||||
10.3# | Amendment No. 2 and Waiver to Credit Agreement, dated as of May 8, 2024, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent, collateral agent, and replacement lender. | S-1 | 333-280341 | June 20, 2024 | 10.3 | |||||||||||||||||||||||||||
| 10.4 | Amendment No. 3 to Credit Agreement, dated as of December 13, 2024, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent. | 8-K | 001-37388 | December 13, 2024 | 10.1 | |||||||||||||||||||||||||||
| 10.5 | Amendment No. 4 to Credit Agreement, dated as of December 20, 2024, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank N.A., as administrative agent and collateral agent. | 8-K | 001-37388 | December 20, 2025 | 10.1 | |||||||||||||||||||||||||||
| 10.6 | Amendment No. 5 to Credit Agreement, dated as of November 25, 2025, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent. | 8-K | 001-37388 | November 25, 2025 | 10.1 | |||||||||||||||||||||||||||
10.7† | 2025 Employee Stock Purchase Plan of Talen Energy Corporation. | S-8 | 333-283230 | November 14, 2024 | 10.1 | |||||||||||||||||||||||||||
10.8† | Amended and Restated 2025 Employee Stock Purchase Plan. | 10-Q | 001-37388 | May 8, 2025 | 10.1 | |||||||||||||||||||||||||||
10.9† | 2023 Equity Incentive Plan of Talen Energy Corporation. | S-1 | 333-280341 | June 20, 2024 | 10.9 | |||||||||||||||||||||||||||
10.10† | 2023 Form of Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement (Executive Form). | S-1 | 333-280341 | June 20, 2024 | 10.12 | |||||||||||||||||||||||||||
10.11† | 2023 Form of Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement (Executive Form). | S-1 | 333-280341 | June 20, 2024 | 10.13 | |||||||||||||||||||||||||||
10.12† | 2023 Form of Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement (Non-Executive Chair Form). | S-1 | 333-280341 | June 20, 2024 | 10.14 | |||||||||||||||||||||||||||
10.13† | 2023 Form of Talen Energy Corporation Restricted Unit Award Notice and Award Agreement (Non-Employee Director Form). | S-1 | 333-280341 | June 20, 2024 | 10.15 | |||||||||||||||||||||||||||
10.14† | 2023 Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement, dated as of June 16, 2023, by and between Talen Energy Corporation and Mark A. McFarland. | S-1 | 333-280341 | June 20, 2024 | 10.10 | |||||||||||||||||||||||||||
10.15† | 2023 Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement, dated as of June 16, 2023, by and between Talen Energy Corporation and Mark A. McFarland. | S-1 | 333-280341 | June 20, 2024 | 10.11 | |||||||||||||||||||||||||||
10.16† | 2025 Form of Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement. | 10-Q | 001-37388 | May 8, 2025 | 10.2 | |||||||||||||||||||||||||||
10.17† | 2025 Form of Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement. | 10-Q | 001-37388 | May 8, 2025 | 10.3 | |||||||||||||||||||||||||||
10.18† | 2025 Form of Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement (Non-Employee Director Form). | 10-Q | 001-37388 | May 8, 2025 | 10.4 | |||||||||||||||||||||||||||
10.19† | Form of Indemnification Agreement between Talen Energy Corporation and each of its directors and officers. | S-1 | 333-280341 | June 20, 2024 | 10.8 | |||||||||||||||||||||||||||
10.20†^ | Employment Agreement, dated as of June 19, 2023, by and between Talen Energy Corporation and John Wander. | S-1 | 333-280341 | June 20, 2024 | 10.18 | |||||||||||||||||||||||||||
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Incorporated by Reference | ||||||||||||||||||||||||||||||||
| Exhibit No. | Description | Form | File Number | Date of Filing | Exhibit Number | |||||||||||||||||||||||||||
10.21†^ | Amended and Restated Employment Agreement, dated as of December 12, 2025, by and between Talen Energy Corporation and Mark A. McFarland. | 8-K | 001-37388 | December 15, 2025 | 10.1 | |||||||||||||||||||||||||||
10.22†^ | Amended and Restated Employment Agreement, dated as of December 12, 2025, by and between Talen Energy Corporation and Terry L. Nutt. | 8-K | 001-37388 | December 15, 2025 | 10.2 | |||||||||||||||||||||||||||
10.23†^ | Amended and Restated Employment Agreement, dated as of December 12, 2025, by and between Talen Energy Corporation and Cole Muller. | 8-K | 001-37388 | December 15, 2025 | 10.3 | |||||||||||||||||||||||||||
10.24†^ | Amended and Restated Employment Agreement, dated as of December 12, 2025, by and between Talen Energy Corporation and Brad Berryman. | 8-K | 001-37388 | December 15, 2025 | 10.4 | |||||||||||||||||||||||||||
10.25†* | Form of Amended and Restated Employment Agreement of Talen Energy Corporation and its executive officers. | — | — | — | — | |||||||||||||||||||||||||||
10.26†^ | Transition and Retirement Agreement and Release of Claims, dated as of December 12, 2025, by and between Talen Energy Corporation and John Wander. | 8-K | 001-37388 | December 15, 2025 | 10.5 | |||||||||||||||||||||||||||
| 10.27 | Purchase Agreement, dated July 1, 2024, by and among Talen Energy Corporation, Rubric Capital Management, LP, Rubric Capital PWR LLC and Rubric BSR Fund LLC. | 10-K | 001-37388 | February 28, 2025 | 10.23 | |||||||||||||||||||||||||||
| 19.1 | Talen Energy Corporation Insider Trading Policy. | 10-K | 001-37388 | February 28, 2025 | 19.1 | |||||||||||||||||||||||||||
21.1* | List of Subsidiaries of Talen Energy Corporation. | — | — | — | — | |||||||||||||||||||||||||||
23.1* | Consents of PricewaterhouseCoopers LLC, independent registered public accounting firm. | — | — | — | — | |||||||||||||||||||||||||||
24.1* | Power of Attorney (included on signature page hereto). | — | — | — | — | |||||||||||||||||||||||||||
| 31.1* | Certification of Principal Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | — | — | — | — | |||||||||||||||||||||||||||
| 31.2* | Certification of Principal Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. | — | — | — | — | |||||||||||||||||||||||||||
| 32.1** | Certification of Principal Executive Officer and Principal Financial Officer pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. | — | — | — | — | |||||||||||||||||||||||||||
| 97.1 | Talen Energy Corporation Clawback Policy. | 10-K | 001-37388 | February 28, 2025 | 97.1 | |||||||||||||||||||||||||||
| 101.INS* | Inline XBRL Instance Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 104* | Cover Page Interactive Data File (embedded within the Inline XBRL document). | — | — | — | — | |||||||||||||||||||||||||||
________________
* Filed herewith.
** Furnished herewith.
# Certain of the schedules and attachments to the exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or attachment will be furnished to the SEC upon request.
^ Certain private and immaterial portions of the exhibit have been redacted pursuant to Item 601(a)(6) of Regulation S-K.
† Management contract or compensatory plan or arrangement.
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(c) Schedule I—Condensed Financial Information of Registrant
TALEN ENERGY CORPORATION
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED UNCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED UNCONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
| Successor | ||||||||||||||||||||
| (Millions of Dollars, except share data) | Year Ended December 31, 2025 | Year Ended December 31, 2024 | May 18 through December 31, 2023 | |||||||||||||||||
| Operating Revenue | $ | $ | $ | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operating Income | ||||||||||||||||||||
| Equity in earnings of TES | ( | |||||||||||||||||||
| Income (Loss) Before Income Taxes | ( | |||||||||||||||||||
| Income tax benefit (expense) | ||||||||||||||||||||
| Net Income (Loss) | ( | |||||||||||||||||||
| Other comprehensive income (loss) | ( | |||||||||||||||||||
| Comprehensive Income (Loss) | $ | ( | $ | $ | ||||||||||||||||
| Earnings Per Share of Common Stock: | ||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | ( | $ | $ | ||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | $ | ( | $ | $ | ||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | ||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | ||||||||||||||||||||
The accompanying Notes to the Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
TALEN ENERGY CORPORATION
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED UNCONSOLIDATED BALANCE SHEETS
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED UNCONSOLIDATED BALANCE SHEETS
| Successor | ||||||||||||||
| (Millions of Dollars, except share data) | December 31, 2025 | December 31, 2024 | ||||||||||||
| Assets | ||||||||||||||
| Investment in TES | $ | $ | ||||||||||||
| Total Assets | $ | $ | ||||||||||||
| Total Liabilities | $ | $ | ||||||||||||
| Stockholders’ Equity | ||||||||||||||
Common stock ($ | $ | $ | ||||||||||||
| Additional paid-in capital | ||||||||||||||
| Accumulated retained earnings (deficit) | ( | ( | ||||||||||||
| Accumulated other comprehensive income (loss) | ( | ( | ||||||||||||
| Stockholders’ Equity | $ | $ | ||||||||||||
| Total Liabilities and Stockholders’ Equity | $ | $ | ||||||||||||
__________________
(a)Shares issued and outstanding were 45,687,828 45,961,910
The accompanying Notes to the Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF REGISTRANT
NOTES TO CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS
1. Basis of Presentation
Talen Energy Corporation is a holding company whose only material businesses and properties are held through its direct and wholly owned subsidiary, Talen Energy Supply. Certain of TES’s debt agreements include covenants that restrict the payment of dividends or other distributions to TEC, restricting in excess of 25 % of TEC’s consolidated net assets. Accordingly, these condensed unconsolidated financial statements and related footnotes have been prepared in accordance with Sections 5-04 and 12-04 of Regulation S-X. These statements are not the general-purpose financial statements of TEC and should be read in conjunction with the Annual Financial Statements.
In May 2023, TEC and the majority of its subsidiaries emerged from the Restructuring and adopted fresh start accounting. See Notes 1, 19, and 20 to the Annual Financial Statements for additional information regarding the Restructuring and related accounting. Unconsolidated financial results are presented for TEC for the Successor periods for the years ended December 31, 2025 and December 31, 2024, and for the period from May 18, 2023 through December 31, 2023. Because the results presented in the Annual Financial Statements for the Predecessor period (prior to May 18, 2023) represent the operating results TES, such results are not repeated here. TEC held no cash nor had any cash activity during the years ended December 31, 2025 and December 31, 2024, and for the period from May 18, 2023 through December 31, 2023; therefore, a statement of cash flows has not been included.
Pursuant to the Internal Revenue Code, TEC and TES are each taxable entities. TEC files a consolidated U.S. federal income tax return on behalf of all its subsidiaries. The provision for income taxes and the effect of any recognition and (or) remeasurement are recognized as if: (i) TES and its subsidiaries file a consolidated income tax return; and (ii) TEC files a standalone income tax return. Additionally, the Company has elected to present accrued excise tax liabilities as a result of the repurchase of TEC common stock on the TES consolidated balance sheets. Accordingly, substantially all income taxes are recognized at TES.
2. TEC Indebtedness
For a general description of the material terms of TES’s indebtedness, see Note 10 to the Annual Financial Statements.
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 from June 1, 2023 through the most recent fiscal quarter (subject to compliance with either (x) a pro forma consolidated total net leverage ratio of less than or equal to 3.75 to 1.0 or (y) a fixed charge coverage ratio greater than or equal to 2.0 to 1.0), (c) equity contributions to TES, and (d) other customary “builder basket” components.
TEC does not have any separate indebtedness, other long-term obligations, or mandatory dividend or redemption requirements of redeemable stocks.
As of December 31, 2025, no cash dividends have been paid to TEC in the last three fiscal years by any other entity.
3. Commitments and Contingencies
See Note 9 to the Annual Financial Statements for commitments and contingencies of TEC.
ITEM 16. FORM 10-K SUMMARY
None.
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GLOSSARY OF TERMS AND ABBREVIATIONS
Adjusted EBITDA. 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 Credit Agreement, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Annual Financial Statements. The audited consolidated balance sheets of TEC as of December 31, 2025 (Successor) and December 31, 2024 (Successor); the related audited consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the years ended December 31, 2025 (Successor) and December 31, 2024 (Successor), for the period from May 18, 2023 through December 31, 2023 (Successor), and for the period from January 1, 2023 through May 17, 2023 (Predecessor); and the related notes.
AOCI. Accumulated other comprehensive income or loss, which is a component of stockholders’ equity on the Consolidated Balance Sheets.
ARO. Asset retirement obligation.
AWS. Amazon Web Services, Inc. and its affiliates.
AWS Data Campus. The data center campus initially developed by a subsidiary of Cumulus Digital adjacent to Susquehanna. See Note 17 to the Annual Financial Statements for information on the AWS Data Campus Sale.
AWS Data Campus Sale. The Company’s sale of the AWS Data Campus to AWS in March 2024 to AWS for gross proceeds of $650 million. See Note 17 to the Annual Financial Statements for additional information.
AWS PPA. The March 2024 (as revised in June 2025) power purchase agreement between the Company and AWS pursuant to which, among other things, the Company agreed to supply up to 960 MW of long-term power to the AWS Data Campus from Susquehanna. In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of power in a “front-of-the-meter” model through 2042. The transition to the revised AWS PPA is expected to occur in spring 2026.
Bilateral LCF. The $75 million senior secured bilateral LC facility provided by Barclays Bank PLC. The Bilateral LCF was terminated in December 2024.
Board of Directors. The board of directors of Talen Energy Corporation.
Brandon Shores. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Brunner Island. A Talen-owned and operated generation facility in York Haven, Pennsylvania.
Capacity Performance. The sole class of capacity product that electricity providers within PJM can offer to satisfy PJM’s capacity obligation and thereby receive capacity payments from PJM. Auctions for this opportunity, generally referred to as capacity auctions, are scheduled by PJM periodically, up to three years in advance of the applicable PJM Capacity Year and in accordance with the terms of PJM’s Tariff and the FERC’s orders. Capacity Performance providers assume higher performance requirements during system emergencies and are subject to penalties for non-performance.
CCR. Coal Combustion Residuals, including but not limited to fly ash, bottom ash, and gypsum, that are produced from coal-fired electric generation facilities.
Colstrip. A generation facility comprised of four coal-fired generation units located in Colstrip, Montana. Talen Montana operates Colstrip, owns an undivided interest in Colstrip Unit 3, and has an economic interest in Colstrip Unit 4. Colstrip Units 1 and 2 were permanently retired in January 2020. See Note 7 to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in Colstrip.
Cornerstone Acquisition. Our pending acquisition of the 875 MW Waterford Energy Center and 456 MW Darby Generating Station in Ohio and the 1,120 MW Lawrenceburg Power Plant in Indiana from Energy Capital Partners. See Note 17 to the Annual Financial Statements for additional information.
Cornerstone Merger Agreement. Agreement and Plan of Merger, dated January 15, 2026, to acquire Energy Capital Partners’ 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana.
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Cornerstone RRA. A registration rights agreement that the Company intends to enter into with certain parties affiliated with Energy Capital Partners at the closing of the pending Cornerstone Acquisition in connection with the issuance of stock consideration.
Credit Agreement. The Credit Agreement, dated as of May 17, 2023, by and among TES, as borrower, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and the joint lead arrangers and joint bookrunners parties thereto, which governs the RCF, TLB-1, TLB-2, TLB-3, and LCF, as the same may be amended, amended and restated, supplemented, or otherwise modified from time-to-time.
Credit Facilities. Collectively, the RCF, TLB-1, TLB-2, TLB-3 and LCF.
Cumulus Digital. Cumulus Digital Holdings LLC, a subsidiary of TES that, through its subsidiaries, (i) initially developed the AWS Data Campus; and (ii) holds the Company’s interest in Nautilus.
Cumulus Digital TLF. The term loan facility under which a subsidiary of Cumulus Digital borrowed $175 million to support the development of Nautilus and the AWS Data Campus. The Cumulus Digital TLF was repaid in full and terminated in March 2024.
DOE. U.S. Department of Energy.
Emergence. May 17, 2023, the date that the Plan of Reorganization became effective in accordance with the terms thereof and TEC, TES, and the other debtors emerged from the Restructuring.
EPA. U.S. Environmental Protection Agency.
EPA CCR Rule. The national regulatory standards required by the EPA for the management of coal combustion residuals in landfills and surface impoundments.
EPA CSAPR. The Cross-State Air Pollution Rule, a federal program that aims to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. A cap-and-trade system for both annual and ozone season periods is used to reduce the target pollutants—sulfur dioxide and nitrogen oxides. CSAPR regulations have been changed over time, and different versions of the regulations have been referred to as the “CSAPR Update,” the “Revised CSAPR Update,” and the “Good Neighbor Plan.”
EPA ELG Rule. The effluent limitation guidelines, which are national regulatory standards required by the EPA for wastewater discharged from specific industrial categories, including but not limited to coal-fired electric generation facilities, to surface waters and municipal sewage treatment plants.
EPA GHG Rule. An EPA rule that establishes carbon dioxide limits for new electric generating units and GHG guidelines for certain existing electric generating units.
EPA MATS Rule. The Mercury and Air Toxics Standards, EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 MW.
EPS. Earnings per share.
ERCOT. The Electric Reliability Council of Texas, operator of the electricity transmission network and electricity energy market in most of Texas.
ERCOT Sale. The sale of our Texas fleet to CPS Energy in May 2024.
ESPP. Talen Energy Corporation 2025 Employee Stock Purchase Plan, which was amended and restated in 2025.
Exchange Act. The Securities Exchange Act of 1934, as amended.
FERC. U.S. Federal Energy Regulatory Commission.
Freedom. A Talen-owned and operated generation facility in Salem Township, Luzerne County, Pennsylvania.
Freedom and Guernsey Acquisitions. Our acquisitions of the Freedom Generating Station in Pennsylvania and the Guernsey Power Station in Ohio from affiliates of Caithness Energy, which closed in November 2025. See Note 17 to the Annual Financial Statements for additional information.
GAAP. Generally Accepted Accounting Principles in the United States.
Guernsey. A Talen-owned and operated generation facility in Byesville, Ohio.
GW. Gigawatt.
H.A. Wagner. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
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Inflation Reduction Act. The Inflation Reduction Act of 2022, which was signed into law in August 2022. The Inflation Reduction Act’s provisions included, among other things, amendments to the Internal Revenue Code of 1986, as amended, to create a nuclear production tax credit program.
ISA. Interconnection Service Agreement.
ISO. Independent System Operator.
LC. Letter of credit.
LCF. The $1.1 billion stand-alone letter of credit facility established under the Credit Agreement.
LMBE-MC TLB. The term loan B facility under which certain subsidiaries holding the Lower Mt. Bethel and Martins Creek facilities borrowed $290 million from affiliates of MUFG. The LMBE-MC TLB was repaid in full and terminated in August 2023.
Lower Mt. Bethel. A Talen-owned and operated generation facility in Bangor, Pennsylvania.
Martins Creek. A Talen-owned and operated generation facility in Bangor, Pennsylvania.
MMBtu. One million British Thermal Units.
Montour. A Talen-owned and operated generation facility in Washingtonville, Pennsylvania.
MW. Megawatt.
MWd. Megawatt-day.
MWh. Megawatt-hour.
Nautilus. Nautilus Cryptomine LLC, a cryptocurrency project that was previously a joint venture between the Company and TeraWulf. The Company purchased TeraWulf’s interest in October 2024 and owns 100% of Nautilus. In June 2025, the Company ceased use of the Nautilus facility and related assets and obligations were derecognized.
NAV. Net asset value.
NDT. Nuclear facility decommissioning trust that is expected to fund Talen’s proportionate costs associated with the future decommissioning activities of Susquehanna.
NERC. North American Electric Reliability Corporation.
NRC. U.S. Nuclear Regulatory Commission.
Nuclear PTC. The nuclear production tax credit under the Inflation Reduction Act.
PEDFA Bonds. The following series of Pennsylvania Economic Development Financing Authority (“PEDFA”) Exempt Facilities Revenue Refunding Bonds: Series 2009A, due December 2038 (“PEDFA 2009A Bonds”); Series 2009B, due December 2038 (“PEDFA 2009B Bonds”); and Series 2009C, due December 2037 (“PEDFA 2009C Bonds”). The PEDFA 2009A Bonds were extinguished at emergence from bankruptcy in 2023; the PEDFA 2009B Bonds and PEDFA 2009C Bonds remain outstanding and are guaranteed by certain of the Subsidiary Guarantors.
PJM. PJM Interconnection, L.L.C., the RTO that coordinates the movement of wholesale electricity in all or parts of Pennsylvania, New Jersey, Maryland, 10 other states, and the District of Columbia.
PJM BRA (or “BRA”). PJM Base Residual Auction, a component of PJM’s capacity market intended to secure power supply resources from market participants in advance of the PJM Capacity Year. It is usually held during the month of May three years prior to the start of the PJM Capacity Year. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.
PJM Capacity Year. PJM capacity revenues for each delivery year covering the period from June 1 to May 31.
PJM Reliability Pricing Model. PJM’s capacity market, or the Reliability Pricing Model, formed under PJM’s Open Access Transmission Tariff, which is intended to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted energy demand in the future. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.
Plan of Reorganization. The Joint Chapter 11 Plan of Reorganization of Talen Energy Supply, LLC and Its Affiliated Debtors (Docket No. 1206), as subsequently amended, supplemented, or otherwise modified, and any exhibits or schedules thereto.
PP&E. Property, plant and equipment.
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Predecessor. Relates to the financial position or results of operations of Talen Energy Supply for periods prior to Emergence, or May 17, 2023.
RCF. The senior secured revolving credit facility that provides $900 million in aggregate revolving loan and LC commitments under the Credit Agreement.
RCRA. The Resource Conservation and Recovery Act, a federal law enacted in 1976 giving the EPA authority to control hazardous and non-hazardous solid waste from its creation to its disposal.
Restructuring. The voluntary cases commenced by TEC, TES, and the other debtors under Chapter 11 of the U.S. Bankruptcy Code, together with the related financial restructuring of the existing debt, existing equity interests, and certain other obligations pursuant to the Plan of Reorganization.
RGGI. The Regional Greenhouse Gas Initiative, a mandatory market-based program among certain states, including Maryland, New Jersey and Massachusetts, to cap and reduce carbon dioxide emissions from the power sector. RGGI requires certain electric power generators to hold allowances equal to their carbon dioxide emissions over a three-year control period. Pennsylvania has proposed joining this program.
RMR. A generation unit that is otherwise slated to be retired but agrees with PJM to remain operational beyond its requested deactivation date as a reliability-must-run resource to mitigate reliability concerns until necessary upgrades can be established.
RTO. Regional Transmission Organization.
Secured ISDAs. Certain bilateral secured International Swaps and Derivatives Association (“ISDA”) agreements and Base Contracts for Sale and Purchase of Natural Gas as published by the North American Energy Standards Board (“NAESB”) of Talen.
Secured Notes. The 8.625% Senior Secured Notes, due 2030, issued by Talen Energy Supply.
Secured Notes Indenture. The Indenture, dated as of May 12, 2023, as supplemented by the First Supplemental Indenture, dated as of May 17, 2023, the Second Supplemental Indenture, dated as of October 6, 2023, the Third Supplemental Indenture, dated as of June 22, 2024, the Fourth Supplemental Indenture, dated as of January 13, 2025, and the Fifth Supplemental Indenture, dated as of November 25, 2025, each between TES, the Subsidiary Guarantors and Wilmington Savings Fund Society, FSB, as trustee, which governs the Secured Notes, as the same may be further amended, amended and restated, supplemented or otherwise modified from time-to-time.
SNF. Spent nuclear fuel.
SOFR. Secured Overnight Financing Rate, a broad measure of the cost of borrowing cash overnight collateralized by U.S. Treasury securities.
SRP. The share repurchase program, under which the Board of Directors has authorized the Company to repurchase shares of TEC’s outstanding common stock.
Subsidiary Guarantors. The subsidiaries of TES that guarantee: (i) the obligations of TES under the Credit Facilities, the Secured Notes, and the Unsecured Notes; and (ii) the obligations of Talen Energy Marketing under the Secured ISDAs.
Successor. Relates to the financial position or results of operations of Talen Energy Corporation for periods after Emergence, or May 18, 2023.
Susquehanna. A nuclear-powered generation facility located near Berwick, Pennsylvania. A subsidiary of Talen Energy Supply operates and owns a 90% undivided interest in Susquehanna.
Talen (or the “Company,” “we,” “us,” or “our”). (i) for periods after May 17, 2023, Talen Energy Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise; and (ii) for periods on or before May 17, 2023, Talen Energy Supply and its consolidated subsidiaries, unless the context clearly indicates otherwise.
Talen Energy Corporation (or “TEC”). Talen Energy Corporation, the parent company of Talen Energy Supply and its consolidated subsidiaries.
Talen Energy Marketing. Talen Energy Marketing, LLC, a direct subsidiary of Talen Energy Supply that provides energy management services to Talen-owned and operated generation facilities and engages in wholesale commodity marketing activities.
Talen Energy Supply (or “TES”). Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation that, thorough subsidiaries, indirectly holds all of Talen’s assets and operations.
Talen Montana. Talen Montana, LLC, a Talen subsidiary that operates Colstrip, owns an undivided interest in Colstrip Unit 3, and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
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TeraWulf. TeraWulf (Thales) LLC, a wholly owned subsidiary of TeraWulf Inc. and an unaffiliated third party.
TERP. The Talen Energy Retirement Plan, Talen’s principal defined-benefit pension plan.
TLB-1. The $580 million (subsequently increased to $870 million) senior secured term loan B facility, due May 2030, under the Credit Agreement.
TLB-2. The $850 million senior secured term loan B facility, due December 2031, under the Credit Agreement.
TLB-3. The $1.2 billion senior secured term loan B facility, due November 2032, under the Credit Agreement.
TLC. The $470 million senior secured term loan C facility under the Credit Agreement, the proceeds of which were used to cash collateralize TLC LCF. The TLC was repaid in full and terminated in December 2024.
TLC LCF. The $470 million cash collateralized LC facility under the Credit Agreement. The TLC LCF was terminated in December 2024.
TWh. Terawatt-hour.
Unsecured Notes. Collectively, TES’s 6.250% Senior Unsecured Notes due 2034, and 6.500% Senior Unsecured Notes due 2036.
Unsecured Notes Indenture. The indentures, each dated as of October 27, 2025, as each supplemented by the First Supplemental Indenture, dated as of December 15, 2025, each among TES, the Subsidiary Guarantors and Citibank, N.A., as Trustee, which govern the Unsecured Notes, as the same may be further amended, amended and restated, supplemented or otherwise modified from time-to-time.
WECC. The Western Electricity Coordinating Council, a non-profit corporation that assures 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.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned, thereunto duly authorized, on February 26, 2026.
| TALEN ENERGY CORPORATION | |||||
| By: | /s/ Mark A. McFarland | ||||
| Mark A. McFarland | |||||
Chief Executive Officer and Director | |||||
POWER OF ATTORNEY
KNOW ALL BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Mark A. McFarland and Terry L. Nutt and each of them, as his or her true and lawful agents, proxies, and attorneys-in-fact, with full power of substitution and re-substitution, for him or her and in his or her name, place, and stead, in any and all capacities, to act on, sign, and file with the Securities and Exchange Commission any and all documents relating to this Report, including any amendments, exhibits, and supplements hereto and other documents in connection herewith or therewith, granting to each of them full power and authority to take any and all actions which may be necessary or appropriate to be done, as fully for all intents and purposes as he might or could do in person, hereby approving, ratifying and confirming that each that such agent, proxy, and attorney-in-fact or any of his substitutes may lawfully do or cause to be done by virtue hereof.
Pursuant to the requirements of the Securities Exchange Act of 1934, this Report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on February 26, 2026.
| Signature | Title | |||||||
| /s/ Mark A. McFarland | Chief Executive Officer and Director (Principal Executive Officer) | |||||||
| Mark A. McFarland | ||||||||
| /s/ Terry L. Nutt | President (Principal Financial Officer) | |||||||
| Terry L. Nutt | ||||||||
| /s/ Tony Plagens | Chief Accounting Officer (Principal Accounting Officer) | |||||||
| Tony Plagens | ||||||||
| /s/ Stephen Schaefer | Chairperson of the Board and Director | |||||||
| Stephen Schaefer | ||||||||
| /s/ Gizman Abbas | Director | |||||||
| Gizman Abbas | ||||||||
| /s/ Anthony Horton | Director | |||||||
| Anthony Horton | ||||||||
| /s/ Karen Hyde | Director | |||||||
| Karen Hyde | ||||||||
| /s/ Joseph Nigro | Director | |||||||
| Joseph Nigro | ||||||||
| /s/ Christine Benson Schwartzstein | Director | |||||||
| Christine Benson Schwartzstein | ||||||||
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FAQ
What is Talen Energy (TLN) describing about its core power generation fleet?
Talen Energy reports owning about 13.1 GW of U.S. power capacity, including 2.2 GW of nuclear. Its core fleet features over 5.7 GW of low- and zero-carbon baseload generation and a large portfolio of natural gas, coal, and oil units concentrated mainly in the PJM region.
How does the AWS power purchase agreement affect Talen Energy (TLN)?
The amended AWS PPA commits Talen to deliver up to 1,920 MW of carbon-free nuclear power from Susquehanna through 2042. The contract ramps volumes over time with minimum commitments and anticipated premium pricing, creating long-term, fixed-price revenue and supporting the company’s data center-focused strategy.
What major acquisitions does Talen Energy (TLN) highlight in this report?
Talen completed the Freedom and Guernsey Acquisitions for about $3.8 billion, adding 2.8 GW of efficient gas baseload capacity. It also agreed to the $3.45 billion Cornerstone Acquisition, bringing roughly 2.5 GW of additional natural gas generation in Ohio and Indiana, pending regulatory approvals and customary closing conditions.
How is Talen Energy (TLN) financing its recent growth transactions?
Talen funded the Freedom and Guernsey deals partly with new debt, including $1.4 billion of 6.250% senior notes due 2034 and $1.3 billion of 6.500% senior notes due 2036. It expects to fund the $2.55 billion cash portion of the Cornerstone Acquisition with additional indebtedness, while issuing 2.4 million common shares.
What contracted revenue arrangements does Talen Energy (TLN) rely on?
Key contracted revenues include the AWS PPA for long-term nuclear power sales and reliability-must-run agreements for the Brandon Shores and H.A. Wagner plants. Starting June 2025, those RMR contracts pay $145 million and $35 million annually, plus variable cost reimbursement and performance-based holdbacks, through May 2029.
How significant is Talen Energy’s (TLN) presence in PJM markets?
Talen states that the substantial majority of its capacity is in PJM, with about 13 GW in MAAC, BGE, and AEP regions. In the 2027/2028 Base Residual Auction, it cleared 8,745 MW at $333.44 per MW-day, underscoring deep exposure to PJM capacity and energy markets.
What are the main risks Talen Energy (TLN) emphasizes in its business?
Talen highlights commodity price volatility, extreme weather, PJM market rule changes, nuclear operational risks, and extensive environmental regulation. It also notes potential Capacity Performance penalties, cyber threats, and the need to manage higher leverage from recent and pending acquisitions within its targeted long-term net leverage framework.
Talen Energy Corp