Document
Filed pursuant to Rule 424(b)(3)
Registration No. 333-280341

TALEN ENERGY CORPORATION
36,825,683 Shares of Common Stock
This prospectus relates to the registration of up to 36,825,683 shares of our common stock, par value $0.001 per share (our “common stock”), which may be offered for resale from time to time by the stockholders named under the heading “Principal and Selling Stockholders” (the “Selling Stockholders”). The shares of our common stock offered under this prospectus may be resold by the Selling Stockholders at fixed prices, prevailing market prices at the times of sale, prices related to such prevailing market prices, varying prices determined at the times of sale or negotiated prices, and, accordingly, we cannot determine the price or prices at which shares of our common stock may be resold. The shares of our common stock offered by this prospectus and any prospectus supplement may be resold by the Selling Stockholders directly to investors or to or through underwriters, dealers or other agents, as described in more detail in this prospectus. We do not know if, when or in what amounts a Selling Stockholder may offer shares of our common stock for resale. The Selling Stockholders may resell all, some or none of the shares of our common stock covered by this prospectus in one or multiple transactions. For more information, see the section titled “Plan of Distribution.”
We will not receive any proceeds from the resale of shares of common stock by the Selling Stockholders, but we have agreed to pay certain registration expenses.
Our common stock is quoted on the OTCQX U.S. Market under the symbol “TLNE.” On July 8, 2024, the closing price of our common stock as reported on the OTCQX U.S. Market was $118.99 per share. We have been approved to list our common stock on the Nasdaq Global Select Market (“Nasdaq”) under the symbol “TLN.” Our common stock will begin trading on Nasdaq on or about July 10, 2024.
Investing in our common stock involves risks. See the section titled “Risk Factors” beginning on page 19 to read about factors you should carefully consider before buying shares of our common stock.
Neither the Securities and Exchange Commission nor any other regulatory body has approved or disapproved of these securities or passed upon the accuracy or adequacy of this prospectus. Any representation to the contrary is a criminal offense.
Prospectus dated July 9, 2024.



TABLE OF CONTENTS
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ABOUT THIS PROSPECTUS
This prospectus is a part of a registration statement on Form S-1 that we filed with the Securities and Exchange Commission (the “SEC”), using a “shelf” registration or continuous offering process. Under this shelf process, the Selling Stockholders may, from time to time, sell the common stock covered by this prospectus in the manner described in the section titled “Plan of Distribution.” Additionally, we may provide a prospectus supplement to add information to, or update or change information contained in, this prospectus (except that any such additions, updates, or other changes to the section titled “Plan of Distribution” shall only be made pursuant to a post-effective amendment to the extent they are material). You may obtain this information without charge by following the instructions under the section titled “Where You Can Find Additional Information” appearing elsewhere in this prospectus. You should read carefully this prospectus and any prospectus supplement before deciding to invest in our common stock.
The Selling Stockholders may only offer to resell, and seek offers to buy, shares of our common stock in jurisdictions where offers and sales are permitted. You should rely only on the information contained in this prospectus and any accompanying prospectus supplement. Neither we, nor the Selling Stockholders, have authorized anyone to provide you with information other than that contained in this prospectus or any accompanying prospectus supplement, and if other information is provided to you, then you should not rely on it. Neither we, nor the Selling Stockholders, take any responsibility for, and can provide no assurance as to the accuracy or completeness of, any information that others may give you. Neither we, nor the Selling Stockholders, have authorized any other person to provide you with different or additional information. The information contained in this prospectus speaks only as of the date of this prospectus, regardless of the time of delivery of this prospectus or any sale of shares of our common stock hereunder. Our business, financial condition, cash flows, results of operations and prospects may have changed since the date on the front cover of this prospectus.
Neither we nor the Selling Stockholders are making an offer to sell the shares in any jurisdiction where the offer or sale is not permitted.
Basis of Presentation
Talen Energy Corporation (“TEC” or “Successor”) is a holding company whose only material businesses and properties are held through its direct and wholly owned subsidiary, Talen Energy Supply, LLC, (“TES” or the “Predecessor”). As used in this prospectus, and as further described below, for periods after May 17, 2023, the terms “Talen,” “Successor,” the “Company,” “we,” “us” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. For periods on or before May 17, 2023, the terms “Talen,” “Predecessor,” the “Company,” “we,” “us” and “our” refer TES and its consolidated subsidiaries (which does not include TEC), unless the context clearly indicates otherwise.
On May 9, 2022, TES and 71 of its subsidiaries each filed a voluntary petition for relief (the “Restructuring”) under Chapter 11 of the Bankruptcy Code (the “Bankruptcy Code”) in the United States Bankruptcy Court for the Southern District of Texas (Houston Division) (the “Bankruptcy Court”). While TEC’s management continued to operate TES and the other initial Debtors as debtors-in-possession during the pendency of the Restructuring, the activities that most significantly impacted TES’s and the other initial Debtors’ economic performance during this time required approval of the Bankruptcy Court. Accordingly, TEC deconsolidated TES for financial reporting purposes because TEC no longer controlled the activities of TES.
On December 12, 2022, TEC filed a petition to become a debtor in the Restructuring in order to facilitate the implementation of certain restructuring transactions contemplated under the Plan of Reorganization in the Restructuring (the “Plan of Reorganization”) and the Bankruptcy Court approved the joint administration of TEC’s voluntary petition for relief under Chapter 11 of the Bankruptcy Code with TES and the other initial Debtors. On December 20, 2022, the Bankruptcy Court confirmed the Plan of Reorganization.
On May 17, 2023, the Plan of Reorganization became effective and we emerged from the Restructuring (“Emergence”). Upon Emergence, TEC regained control of TES through a business combination that resulted in TEC again consolidating TES. The business combination was accounted for as a reverse acquisition based on the
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transaction’s economic substance, in which certain creditors of TES effectively equitized their claims against TES into the controlling equity interests of TES, which were then exchanged for the controlling equity interests of TEC.
Accordingly, the financial statements included elsewhere in this prospectus are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer. As a result, the consolidated financial statements of TEC after Emergence are not comparable to its consolidated financial statements prior to that date and have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
We completed the sale of our ERCOT fleet to CPS Energy in May 2024 (the “ERCOT Sale”). As a result, we have updated certain operational data presented in this prospectus to give effect to the ERCOT Sale. Our financial statements, segment information and related financial data as of and for the periods ending on or prior to March 31, 2024 include the results of operations from the ERCOT fleet. We intend to reevaluate our segment information for the first financial period after the ERCOT Sale, which is the quarter ending June 30, 2024.
All capitalized terms not defined herein have the meaning provided in the Glossary, unless otherwise expressly set forth herein.
Market and Industry Data
This prospectus includes estimates regarding market and industry data. Unless otherwise indicated, information concerning our industry and the markets in which we operate, including our general expectations, market position, market opportunity and market size, are based on our management’s knowledge and experience in the markets in which we operate, together with currently available information obtained from various sources, including publicly available information, industry reports and publications, surveys, our customers, trade and business organizations and other contacts in the markets in which we operate. Certain information is based on management estimates, which have been derived from third-party sources, as well as data from our internal research.
In presenting this information, we have made certain assumptions that we believe to be reasonable based on such data and other similar sources and on our knowledge of, and our experience to date in, the markets in which we operate. While we believe the estimated market and industry data included in this prospectus is generally reliable, such information is inherently uncertain and imprecise. Market and industry data is subject to change and may be limited by the availability of raw data, the voluntary nature of the data gathering process and other limitations inherent in any statistical survey of such data. In addition, projections, assumptions and estimates of the future performance of the markets in which we operate are necessarily subject to uncertainty and risk due to a variety of factors, including those described in “Risk Factors” and “Cautionary Note Regarding Forward-Looking Statements.” These and other factors could cause results to differ materially from those expressed in the estimates made by third parties and by us. Accordingly, you are cautioned not to place undue reliance on such market and industry data or any other such estimates.
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PROSPECTUS SUMMARY
This summary highlights selected information that is presented in greater detail elsewhere in this prospectus. This summary does not contain all of the information you should consider before investing in our common stock. You should read this entire prospectus carefully, including the sections titled “Risk Factors,” “Cautionary Note Regarding Forward-Looking Statements,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the consolidated financial statements and the related notes included elsewhere in this prospectus, before making an investment decision.
Our Business
Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity and ancillary services into wholesale power markets in the United States, primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic and Montana. We recently completed the sale of our ERCOT fleet (the “ERCOT Sale”). See “—Recent Developments—ERCOT Sale” for additional information. The majority of our generation is produced at zero-carbon nuclear and lower-carbon gas-fired facilities and we are continuing our decarbonization efforts. In addition, as part of our Cumulus digital infrastructure and energy transition platform, we developed, and recently sold (the “Cumulus Data Campus Sale”) to an affiliate of Amazon Web Services, Inc. (together with its affiliates, “AWS”), the infrastructure for a hyperscale data center campus (the “Cumulus Data Campus”) adjacent to our zero-carbon Susquehanna nuclear facility (“Susquehanna”) that will utilize carbon-free, low-cost energy provided directly from the plant, providing both an attractive source of demand for the plant and a new source of incremental revenues for us. See “—Recent Developments—Cumulus Data Campus Sale” for additional information. In 2023, we generated enough power for over 3 million average American homes (based on the U.S. Energy Information Administration’s 2022 estimate of 10,791 KWh per home). In the first three months of 2024, Talen generated $319 million of net income and approximately $289 million of Adjusted EBITDA. “Summary Historical and Unaudited Pro Forma Condensed Consolidated Financial Information—Non-GAAP Financial Measures” contains a description of Adjusted EBITDA and a reconciliation to the most directly comparable GAAP measure.
Our generation portfolio is anchored by our approximately 2.2 GW interest in the Susquehanna nuclear facility, which enabled us to produce over half of our generation carbon-free in 2023. As part of the Cumulus Data Campus Sale, we entered into agreements (the “Cumulus Data Campus PPA”) to supply long-term, zero-carbon power directly from Susquehanna to the Cumulus Data Campus through fixed-price power commitments, providing cash flow stability for an initial term of at least 10 years, in addition to various extension options that could extend through the life of the plant (including additional life from license renewals). For additional information about the Cumulus Data Campus PPA, see “—Recent Developments—Cumulus Data Campus Sale.” We also believe Susquehanna may further benefit from the nuclear production tax credit under the Inflation Reduction Act of 2022 (the “Nuclear PTC”), providing additional cash flow stability through 2032. Our 6.3 GW natural gas and oil fleet (of which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after conversion, as discussed below) is reliable and dispatchable, and we believe these assets will become increasingly important for grid stabilization in the face of growing intermittent sources of generation in our core markets. These plants generate material annual capacity revenues and a seasoned operating team leads the monetization of seasonal commodity volatility. We have already completed the conversion of approximately 3.2 GW of our legacy coal fleet to natural gas or fuel oil, significantly reducing the carbon intensity of our fleet while extending the useful lives of certain assets.
In addition to our strong generation fleet, we are developing the Cumulus digital infrastructure and energy transition platform to explore growth opportunities complementary to our existing asset base. For instance, we developed the Cumulus Data Campus, the world’s first 24x7 carbon-free, direct-connect data center campus, to provide digital infrastructure powered by “behind-the-meter” generation directly from Susquehanna. Through both the direct proceeds of the Cumulus Data Campus Sale and entry into the related Cumulus Data Campus PPA, we are now realizing the value of our prior investments in the campus in a value accretive way. While maintaining capital discipline, Cumulus is evaluating additional ways to leverage the value of our existing sites and interconnections for potential renewable energy generation or battery storage projects. We believe our existing footprint, which includes zero-carbon sources of power, access to the power grid and significant land holdings, provides us with unique opportunities for growth.
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We believe that we are well positioned to benefit from strong cash flows generated by our Susquehanna facility, meaningful capacity revenues and commodity upside from our natural gas, oil and peaking fleet, organic growth from additional power sales to the Cumulus Data Campus under the Cumulus Data Campus PPA, and potential additional upside from our development pipeline, all with an incredibly low carbon footprint. With a focus on the safe, efficient physical and financial operation of our core assets, together with disciplined financial policy and capital allocation, our experienced management team intends to unlock the significant value that we believe is embedded in our platform, enabling us to realize meaningful shareholder returns.
Our Platform
The following discussion provides a brief overview of the key building blocks of our platform. For additional detail regarding each of our facilities, please see “Business—Our Properties.”
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Note: Fleet as of 3/31/2024, pro forma for the ERCOT Sale.
1.Brunner Island: Coal-to-dual fuel conversion completed in 2016; coal-fired generation is restricted during the EPA Ozone Season (May 1 to September 30 of each year) and will cease by year-end 2028, with the option of earlier coal retirement at the Company’s discretion.
Montour: Coal-to-gas conversion completed in 2023; coal-fired generation is required to cease by year-end 2025, with the option of earlier coal retirement at the Company’s discretion.
2.Wagner and Brandon Shores: Coal-to-oil conversion of Wagner Unit 3 completed in late 2023. However, we have provided notice to PJM of deactivation of Wagner and Brandon Shores, effective June 1, 2025. PJM subsequently notified Talen that these facilities are needed for reliability. Both facilities have filed cost-of-service rate schedules for continued Reliability-Must-Run operations through 2028. Please see Note 8 to the Interim Financial Statements for additional information.
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3.Keystone and Conemaugh: Coal-fired electric generation is required to cease by year-end 2028.
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Zero-carbon Susquehanna nuclear facility. We own a 90% interest in and operate the 2.5 GW Susquehanna facility, the sixth largest nuclear-powered generation facility in the U.S. Susquehanna typically comprises 50% or more of our annual generation.
In 2023, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a top-quartile low all-in cost of under $24 per MWh while maintaining leading safety performance. Susquehanna has historically generated revenues primarily from energy sales into the PJM wholesale market, PJM capacity revenues and strategic hedging. The co-located Cumulus Data Campus, initially under development by Cumulus Data and recently sold to AWS, now provides Susquehanna with additional contracted cash flows through the Cumulus Data Campus PPA. See “—Recent Developments—Cumulus Data Campus Sale” for additional information. We also believe the facility is now also poised to benefit substantially from the Nuclear PTC enacted under the Inflation Reduction Act, which would provide meaningful downside protection when annual revenues from nuclear generation are below $43.75 per MWh (indexed each year for inflation) while maintaining upside optionality in periods of higher pricing.
Susquehanna’s efficient cost structure is supported in part by a portfolio of supply contracts for all stages of the nuclear fuel cycle. Our nuclear fuel cycle is 100% contracted through the 2025 fuel load and at least 85% contracted through 2028. We have no ongoing fuel exposure to any Russian-affiliated counterparties.
We believe that nuclear generation is integral to the grid and the energy transition, particularly as we move toward a lower-carbon world. An increasingly positive public sentiment toward nuclear generation, bolstered by government support in the form of the Nuclear PTC, has resulted in improved market appetite for nuclear assets, as demonstrated by the recent resurgence in nuclear M&A transactions. Susquehanna’s two units are long-lived, with current licenses through 2042 and 2044 (and up to 20-year extensions possible with regulatory approval), and its dual-unit design contributes to maintenance, operational and other efficiencies, making Susquehanna an attractive asset in this space.
Natural gas and oil intermediate and peaking units. Our generation portfolio includes 7 technologically diverse natural gas and oil generation facilities across the generation stack (including intermediate and peaking dispatch), with certain units capable of utilizing multiple fuel sources. Our assets benefit from both a wholesale and a capacity market. Lower Mt. Bethel operates at a high Capacity Factor, enabled by advantaged gas supply. Neighboring Martins Creek, our largest non-nuclear facility, earns significant capacity revenues while keeping fixed costs relatively low, and its units are capable of cycling daily to capture peak energy prices. We recently refinanced a legacy project financing at these two high-quality assets, freeing their cash flows for broader utilization within our business. We have also recently converted some of our PJM assets to lower-carbon fuels, which extends their useful
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lives and enables us to maintain both the associated capacity revenues and the additional commodity upside potential.
Our Cumulus platform opportunities. We believe our geographical footprint, supply of lower- and zero-carbon power, interconnection access and abundance of land all provide us with potential opportunities to extend the life and increase the value of our legacy assets through strategic development of growth projects where appropriate. With the majority of our planned capital expenditures for these projects having already been spent, we will continue to evaluate ways to find the highest and best use of our assets and capital, which may include advancing additional growth projects if justified by economics. These additional growth projects include our Cumulus renewables and battery storage initiatives, which are focused on the opportunity to leverage our substantial existing asset base in the development of future projects primarily through partnerships. The renewables and battery projects currently under evaluation require only modest incremental spend to maintain interconnection optionality. Nautilus, Cumulus Coin’s digital currency joint venture with TeraWulf, is now operational adjacent to Susquehanna and the Cumulus Data Campus. Although we do not view digital currency as core to our long-term business, the 150 gross MW Nautilus facility currently generates positive cash flows from operations in addition to being a firm purchaser of power generated by Susquehanna. We plan to evaluate a variety of structural alternatives to progress our currently identified opportunities in keeping with our commitment to appropriate leverage levels and to a thoughtful capital allocation framework.
Carbon deleveraging. We have committed to cease burning coal at all of our wholly-owned coal facilities by the end of 2028, either through conversions or retirements. We have recently completed the conversion of approximately 3.2 GW of our legacy coal fleet to lower-carbon fuels. The conversion of our Brunner Island facility to dual-fuel (natural gas and coal) capability was completed in 2016; the plant currently burns coal only outside of Ozone Season and has committed to cease burning coal completely by the end of 2028. The conversion of our Montour facility to natural gas was completed in 2023, with both converted units now fully operational on gas. Together, these two facilities represent nearly 25% of our total generation capacity. The conversion of our legacy coal facilities to alternative fuels meaningfully extends the life of certain assets, while also lowering the carbon profile of our fossil fleet, mitigating uncertainties associated with coal supply and improving system reliability. These transitions enable us to maintain the capacity revenues generated by the assets while providing additional commodity upside optionality.
In addition, the conversion of Wagner Unit 3 from coal to fuel oil was completed in 2023; however, for economic reasons, we have requested deactivation of Wagner in mid-2025. Our wholly-owned 1.3 GW Brandon Shores facility is required by both environmental permits and settlements to stop combusting coal by the end of 2025, and we have requested deactivation of Brandon Shores in mid-2025. However, PJM subsequently notified us that both Wagner and Brandon Shores are needed for reliability reasons. Both facilities have filed cost-of-service rate schedules, currently pending with FERC, for continued Reliability-Must-Run operations through 2028. For additional information, see Note 8 in Notes to the Interim Financial Statements.
We also own minority interests, totaling approximately 800 MW, in three coal-fired generation facilities in PJM and WECC. We are exploring ways to maximize the value of these assets in the context of our broader carbon deleveraging goals, and our key debt agreements provide us the ability to separate our minority-owned coal assets if we decide to do so.
Our Competitive Strengths
We believe the following strengths leave us well positioned to maximize the value of our business:
Stable cash flows from Susquehanna. Susquehanna is one of the largest baseload, carbon-free nuclear generation facilities in the United States. Susquehanna provides multiple paths to cash flow generation and value creation, including through the PJM wholesale and capacity markets. Historically, we sold our power via a combination of spot sales and hedging transactions. The Cumulus Data Campus now creates additional incremental value for Susquehanna, providing future cash flows through direct sales of power to a highly-rated counterparty at fixed prices under the long-term Cumulus Data Campus PPA. See “—Recent Developments—Cumulus Data Campus Sale” for additional information. When measured by the operational and safety standards adopted by the
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nuclear industry, Susquehanna is one of the top performers in the United States. In 2023, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a low all-in cost of less than $24 per MWh while maintaining leading safety performance.
Going forward, our commercial strategy at Susquehanna may also benefit from the Nuclear PTC, which provides for an up to $15 per MWh tax credit (indexed to inflation) related to energy produced at nuclear facilities through 2032. The Nuclear PTC provides meaningful downside protection when annual revenues fall below $43.75 per MWh (indexed to inflation) while maintaining upside optionality on Susquehanna’s generation for higher prices. Based on the latest guidance, we can use the Nuclear PTC to offset up to 75% of our federal cash taxes and may be able to monetize remaining credits through the sale to an eligible taxpayer.
Flexible and highly dispatchable natural gas and oil fleet provides the ability to capture significant incremental revenue and benefit from shifting market dynamics. Our 6.3 GW natural gas and oil generation fleet (of which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after their recent conversions from coal) is comprised of diverse and strategically located assets, including significant generation in attractive wholesale markets, leaving our fleet well suited to benefit from varying market dynamics while also generating predictable capacity revenues. Our seasoned operating teams lead the monetization of commodity volatility. Our natural gas and oil generation fleet provides meaningful operational flexibility, enabling us to respond to pricing signals to capture upside from power price dynamics. We believe this capability will become increasingly valuable as a source of reliability in markets with increasing levels of intermittent generation assets. We believe that gas assets will be a core component of the power markets and grid reliability for the coming years, and we believe our natural gas and oil generation fleet is also poised to benefit from potential regulatory reforms and shifting market dynamics.
Strong balance sheet underpinned by robust liquidity, ample cash generation and modest leverage. We emerged from the Restructuring with a well-capitalized and strong balance sheet and have no significant debt maturities until 2030. As of March 31, 2024, we had unrestricted cash of approximately $597 million and $544 million of available commitments under our revolving credit facility, resulting in liquidity of approximately $1.1 billion. In addition, we have a $75 million secured bilateral letter of credit facility and a $470 million term loan C letter of credit facility. Our strong balance sheet also provides ample capacity and counterparty appetite for lien-based hedging, which does not require cash collateral posting. Our legacy debt service requirements were significantly reduced as a result of the Restructuring, and we intend to maintain a modest go-forward net leverage ratio of 3.5x or less. We believe these factors provide us with the flexibility to focus on maximizing value through the disciplined operation of our core business.
Experienced, principled and disciplined leadership team. We benefit significantly from the experience and industry expertise of our leadership team. Following the Restructuring, we have reorganized and refined our senior management team to more closely align with our go-forward objectives. Our management team draws from decades of strategic, operational, financial and legal experience as they seek to maximize the value of our business for our stakeholders. We are overseen by an independent Board of Directors with deep power industry experience across all relevant disciplines, markets and asset types, including significant commercial and risk management expertise. While we continue to maintain an internal risk management committee of senior management to monitor, measure and manage risks in accordance with our risk policy, we have also established an independent risk oversight committee of the Board of Directors that makes this a key strategic priority. See “Management.”
Our generation team continues to be led by Company veterans with a proven track record of operational excellence. Furthermore, our commercial team is comprised of seasoned veterans spanning all disciplines: asset optimization, trading, fuel-procurement, risk management, credit and power-flow modeling. We also benefit from hand-selected regional leadership and plant management teams who have significant experience in the power industry and with local and governmental stakeholders, providing us with a deep understanding of the regulatory, political and business environment in each of our key markets. We believe that this high level of experience strengthens our ability to effectively manage, improve and monetize our current power generation assets and to identify, evaluate and execute on opportunities to maximize the value of our platform. We are continually focused on capital discipline and commercial and risk management to ensure stable and predictable cash-flow generation and preserve margin.
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Our Business Strategies
We believe our competitive strengths position us well to achieve our business objectives through the following strategies:
Continue our exceptional operations, with focus on continued cost savings and efficiencies. The foundation of our platform is safe, disciplined operational and commercial performance. We drive operational excellence by maximizing the safety, reliability and efficiency of our core assets, which in turn enhances our cash flows and financial position. 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 through additional cost savings, where available, across all cost categories, in turn maximizing free cash flow from our core asset base and driving shareholder returns. Following the Restructuring, we expect our cost structure to be lower and more flexible due to many successful initiatives that have reduced our recurring operating costs, including significantly reducing our debt service obligations, renegotiating or rejecting fuel contracts, focusing generation facility investments on plant reliability, eliminating unnecessary overhead costs and rewarding our employees with cash flow performance-based compensation. In addition, as part of our cost savings initiative implemented in late 2023, we formally assessed our operational model and cost structure across the Company and executed on specific actions focused on reductions in run-rate O&M and G&A expenses.
To sustain our robust performance, our leadership team focuses on, among other priorities, maximizing reliability through carefully planned and periodic maintenance and upgrades of our equipment, retaining experienced facility managers and employees and positioning them on-site to address emerging issues quickly, capitalizing on procurement efficiencies across our platform and implementing redundancy in our generation facility design. Our leadership team continually sources ideas from, among others, generation facility management teams, asset managers and frontline workers and prioritizes them based on impact, feasibility and expected return on investment.
Focus and maintain our core generation that provides stable earnings and cash flows. Our core fleet generates stable earnings and cash flows backed by multiple sources. Our integrated generation, wholesale marketing and commercial capabilities enable us to produce significant recurring cash flow, and our commercial and risk management strategies provide cash flow stability while balancing operational, price and liquidity risk through physical and financial commodity transactions. In today’s robust but volatile energy markets, our team has been able to capture high realized pricing through both reliable generation and strategic risk management, resulting in $319 million of net income and approximately $289 million of Adjusted EBITDA in the first three months of 2024. “Summary Historical and Unaudited Pro Forma Condensed Consolidated Financial Information—Non-GAAP Financial Measures” contains a description of Adjusted EBITDA and a reconciliation to the most directly comparable GAAP measure. Capacity revenue is a key indicator of the important role that nuclear, natural gas and peaking generation all play in PJM grid reliability. In 2023, our PJM fleet generated approximately $241 million in capacity revenues. Following the Cumulus Data Campus Sale, we are poised to increasingly benefit from long-term, stable cash flows from fixed-price power sales under the Cumulus Data Campus PPA. See “—Recent Developments—Cumulus Data Campus Sale” for additional information. We now also have substantive federal support for nuclear generation, which is accretive to our portfolio, with the Nuclear PTC further de-risking our Susquehanna generation and enhancing its credit profile while maintaining upside optionality in high price environments. We also believe we are well positioned to benefit from current and anticipated proposed regulatory reforms in our key markets, and to respond to changing supply/demand dynamics, in part due to third-party asset and resource retirements.
Optimize risk management program and hedging. We are focused on implementing appropriate risk management policies in the context of a right-sized balance sheet and the cash flow stability provided by the Nuclear PTC. We maintain both an internal risk management committee, comprised of members of senior management from across the organization, and a Board-level risk oversight committee, comprised of members of our Board of Directors with extensive trading and risk backgrounds. We target a hedge range of 60-80% of our expected generation for the prompt 12 months and ratably scale the hedge percentage down further out in time to align with our financial objectives. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which does not require cash collateral posting. We will employ a disciplined go-forward strategy focused on first-lien hedging while minimizing exchange-based hedging and the associated margin requirements.
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Importantly, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service requirements.
Capitalize on low carbon-intensity generation to maintain and grow cash flows in a changing policy environment. In recent years, the power sector has undergone significant policy- and technology-driven changes that, when combined with aging infrastructure and evolving consumer, investor and commercial demands largely focused on ESG practices, are transforming the markets in which we operate. We view responsible ESG practices as a key component for achieving operational excellence, maintaining strong financial performance and maximizing the value of our platform over time. We have dramatically 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. As of December 31, 2023, we have reduced our annual carbon dioxide emissions by approximately 75% when compared to 2010 levels.
Our environmental position is firmly anchored by Susquehanna, which enabled us to generate over half of our electricity output carbon-free in 2023. Our natural gas portfolio also includes a number of energy efficient assets with low heat rates. The overall carbon intensity of our generation was 0.29 metric tons per MWh in 2023, which is over approximately 50% lower than our carbon intensity in 2010. We expect to continue reducing our carbon footprint through the recently-completed conversions of 3.2 GW of our legacy coal fleet to lower-carbon fuels and the planned retirement of up to 1.6 GW of legacy coal assets at Wagner (Unit 3) and Brandon Shores, all with minimal remaining cost requirements.
As we retire older, economically nonviable conventional power generation assets, we are exploring opportunities to repurpose these sites to advance our carbon deleveraging. If ultimately developed, our growing carbon-free generation and storage capabilities will enable us to provide additional clean power while extending the life and increasing the value of our legacy assets.
Disciplined financial policy and capital allocation. We actively manage our capital structure, future capital commitments and asset base by following disciplined capital allocation principles focused on generating cash flow, maintaining reasonable leverage and reducing our cost of capital. We emerged from the Restructuring with a strong balance sheet underpinned by modest leverage and robust liquidity of approximately $875 million, increased to approximately $1.1 billion as of March 31, 2024. We also expect that our hedging program will be significantly less capital-intensive than historically, and that the Nuclear PTC will further hedge a substantial amount of our cash flows. We will continue exploring strategic growth opportunities, such as renewables and battery storage projects, if economically viable, but further investment will require a sound basis and an attractive returns profile when compared to other uses of capital. We may also explore partnerships with experienced long-term partners and investors to achieve the right cost of capital as we further progress any future growth projects. We believe that these factors, together with stable cash flows and limited requirements for go-forward capital expenditures, will maximize our free cash flows and enable us to focus on shareholder return programs as appropriate. In furtherance of our disciplined capital allocation strategy, we recently announced an upsizing of the remaining capacity under our share repurchase program to $1 billion through the end of 2025. As part of this program, we recently completed a tender offer for our common stock. See “—Recent Developments—Share Repurchase Program” for additional information.
We intend to target a modest leverage profile with a go-forward net leverage ratio of 3.5x or less, depending on seasonal dynamics. We also intend to prioritize balance sheet efficiency through the active preservation of liquidity, using solutions, where appropriate, such as first-lien, asset-backed hedging agreements in lieu of exchange-based hedging.
Maximize the value of our platform opportunities in a capital efficient manner. We believe there is significant value embedded in our platform, and our activities will be focused on driving both organic and inorganic strategy in ways that create the best sources of value for our company. In addition to focusing on the core operation of our business, we actively manage decision making to achieve the highest and best use of our assets to recognize the full value of our platform. We believe we have meaningful opportunities to unlock previously unrecognized value in our assets. Within our generation portfolio, we are focused on identifying the most valuable use of the reliable nuclear power generated at Susquehanna, including through long-term power sales to the Cumulus Data Campus and otherwise, and commercially managing our highly flexible gas fleet to capture extrinsic value. We also believe we
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have opportunities to organize our assets to align with investor priorities and related costs of capital and we intend to thoughtfully consider market feedback regarding which strategies would be the most value accretive to us. While higher-carbon emitting assets remain important components of our portfolio, such assets are harder to finance and are more working capital intensive in contrast to certain of our more efficient and lower-emissions assets. Within our Cumulus platform, we have now made significant progress in monetizing our prior investments in the Cumulus Data Campus, and we have several other growth options under evaluation that require only modest incremental spend to maintain interconnection optionality. In furtherance of our value maximization efforts, the recent ERCOT Sale is another example of creating value for the Company by opportunistically engaging in market activities. We may commence a corporate realignment that focuses on nuclear, natural gas and digital assets as our core elements of value, and we are permitted to do so under our key debt documents. We expect to evolve our asset base both by continuing to evaluate opportunities to drive value uplift for our existing assets and by pursuing opportunistic acquisitions and divestitures in order to drive cash flow generation and investor returns.
Recent Developments
Share Repurchase Program
In October 2023, the Board of Directors approved a share repurchase program initially authorizing the Company to repurchase up to $300 million of the Company’s outstanding common stock through December 31, 2025. In May 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion through the end of 2025. Repurchases may be made from time to time, at the Company’s discretion, in open market transactions at prevailing market prices, negotiated transactions, or other means in accordance with federal securities laws, and may be repurchased pursuant to a Rule 10b5-1 trading plan. The Company intends to fund repurchases from cash on hand. Repurchases by the Company will be subject to a number of factors, including the market price of the Company’s common stock, alternative uses of capital, general market and economic conditions, and applicable legal requirements, and the repurchase program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. The Company has no obligation to repurchase any amount of its common stock under the repurchase program. As of March 31, 2024, 493,000 shares of the Company’s common stock have been purchased under the share repurchase program for $39 million, inclusive of transaction costs. See Note 16 in Notes to the Annual Financial Statements for additional information. On July 1, 2024, the Company purchased an additional 5,027 shares under the share repurchase program for approximately $550,000.
In May 2024, the Company commenced a modified “Dutch auction” tender offer (the “Tender Offer”) to purchase shares of the Company’s common stock for cash. The Tender Offer resulted in the purchase for cash of 5,275,862 shares of its common stock, representing 9.0% of the Company’s outstanding common stock, at a clearing price per share of $116.00, or an aggregate of $612 million.
On July 1, 2024, we entered into a purchase agreement with entities affiliated with Rubric Capital Management LP (collectively, “Rubric”) pursuant to which Rubric agreed to sell, and we agreed to repurchase from Rubric, 2,413,793 Shares at $116.00 per share of the Company’s common stock (the “Rubric Share Repurchase”) for an aggregate purchase price of $280 million.
Remarketing of PEDFA Bonds
In June 2024, the Company completed a remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $80.6 million in aggregate principal amount of its PEDFA 2009C Bonds.
The PEDFA 2009B and PEDFA 2009C Bonds will now bear interest at 5.25% until the end of the new term rate period on June 1, 2027. In connection with the remarketing, the approximately $133 million of letters of credit that had previously backstopped the PEDFA 2009B and PEDFA 2009C Bonds will be terminated, providing the Company with increased capacity on its TLC.
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Mandatory Share Exchange
In May 2024, each outstanding restricted share of the Company’s common stock issued with or under CUSIP No. 87422Q208 was exchanged for an unrestricted share of the Company’s common stock issued with or under CUSIP No. 87422Q109. The exchange was intended to provide stockholders with increased liquidity, permitting the previously restricted shares to now trade without restriction, subject to each holder’s compliance with (i) securities laws and (ii) rules promulgated by the OTCQX U.S. Market or Nasdaq, as applicable.
Term Loan Repricing
In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale, and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement.
ERCOT Sale
In May 2024, the Company closed the previously announced sale of its approximately 1.7 GW generation portfolio located in the South Zone of the ERCOT market to CPS Energy for $785 million of gross proceeds (approximately $723 million in net proceeds after customary working capital adjustments and estimated taxes, transaction fees and other costs). These assets included the 897 MW Barney Davis and 635 MW Nueces Bay natural gas-fired generation facilities, both located in Corpus Christi, Texas, as well as the 178 MW natural gas-fired generation facility in Laredo, Texas.
Cumulus Digital Buyouts
In March 2024, TES acquired all of the equity units of Cumulus Digital Holdings held by affiliates of Orion and two former members of Talen senior management in exchange for $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital Holdings. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts” for additional information.
Cumulus Data Campus Sale
In March 2024, AWS purchased substantially all the assets of Cumulus Data for gross proceeds of $650 million, with $350 million delivered to the Company at closing and the remaining $300 million of consideration held in escrow. The first $200 million of escrowed proceeds will be released upon a zoning amendment approval or ordinance allowing construction and operation of data center facilities on the property sufficient to consume an aggregate of at least 540 MW of energy, with the remaining $100 million released upon similar zoning amendment approval sufficient to allow aggregate consumption of at least 960 MW. If the 540 MW zoning amendment approval is not granted prior to March 1, 2025 (subject to certain limited extensions), then AWS has the option either to (i) retain the property and release all escrowed funds to the Company or (ii) revert all escrowed funds to AWS and allow the Company a one-time right to repurchase the property for $355 million. If the 540 MW zoning condition is met but the 960 MW zoning amendment approval is not granted prior to March 1, 2028, the remaining $100 million of escrowed funds will revert to AWS. The zoning amendment was approved by the applicable township on May 28, 2024 for the 960 MW. After a required 30 day public comment period, it is expected the zoning amendment will be approved and that the remaining $300 million of consideration will be released to the Company.
In connection with the Cumulus Data Campus Sale, the Company executed the Cumulus Data Campus PPA with AWS, pursuant to which the Company agreed to supply long-term, carbon-free power from Susquehanna to the Cumulus Data Campus through fixed-price power commitments. Under the Cumulus Data Campus PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW (the “480 MW Case”) or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-
9


applicable PJM energy and capacity prices. The initial term of the Cumulus Data Campus PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, Talen will receive additional revenue from AWS related to the sales of carbon-free energy (“CFE”) to the grid. The following table shows the value of these agreements, to the extent reasonably estimable, based on the minimum commitments described above through achievement of the 480 MW case.
Year
PTC Reference Price ($/MWh) (1)
Power Sales (MW)
Incremental EBITDA ($mm/year) (2)(3)
2024$44 — $15 
2025$45 120 $20-35
2026$45 240 $55-80
2027$46 360 $65-110
2028$46 480 $85-140
__________________
(1)Assumed “PTC Reference Price” represents the max price of the Nuclear PTC floor (assuming 2% annual inflation). Provided for illustrative purposes only; not Company projections.
(2)Incremental impact based on comparison of (1) Susquehanna revenues including AWS power sales and additional revenue from AWS related to sales of CFE vs. (2) Susquehanna revenues without AWS agreements, using the price floor set by the “PTC Reference Price.” Rounded to nearest $5mm.
(3)Financial outcomes reflected here are based on various offtake outcomes and are subject to confidential contractual provisions that may affect actual outcomes in either direction; EBITDA range bounded by minimum contractual payments not dependent on executed power purchases and payments for full consumption of power commitments under the 480 MW Case; outcomes may also be impacted by IRS guidance regarding the nuclear PTC. See “Cautionary Note Regarding Forward Looking Statements.”
PJM, PPL Electric Utilities Corporation (“PPL Electric,” a subsidiary of PPL), and Susquehanna have entered into an Amended Interconnection Service Agreement (the “Amended ISA”) allowing Susquehanna to increase the amount of “behind-the-meter” power that it can provide to directly connected load under the current ISA. In June 2024, certain intervenors filed with FERC a protest to the Amended ISA. Talen does not currently expect this proceeding to have material impacts on the AWS transaction. For additional information, see “Business—Regulatory Matters—Susquehanna ISA Amendment.”
Also in connection with the Cumulus Data Campus Sale, the Company terminated the Cumulus Digital TLF and the outstanding obligations thereunder were satisfied and discharged in full. The security interests granted under the Cumulus Digital TLF were terminated, discharged and released. See Note 11 in Notes to the Interim Financial Statements and Note 13 in Notes to the Annual Financial Statements for additional information.
PPL/Talen Montana Litigation Settlement
In December 2023, Talen reached a litigation settlement with PPL. Under the terms of the settlement agreement, PPL paid TEC’s indirect subsidiary, Talen Montana, $115 million in cash in exchange for a full release of Talen Montana’s claims against PPL. Separately, Talen Montana remitted $11 million of the PPL settlement proceeds to the general unsecured creditors trust that was established pursuant to the Plan of Reorganization. See “Business—Legal Matters—Resolved Legal Matters—PPL/Talen Montana Litigation” and Note 12 in Notes to the Annual Financial Statements for additional information.
Riverstone Repurchase
In September 2023, TEC paid Riverstone $40 million in exchange for the cancellation of all of its TEC common stock warrants and a tax indemnity agreement, as well as waiving its future rights to the Retail PPA Incentive Equity. Also, in September 2023, TES and Orion purchased all of the equity units of Cumulus Digital Holdings held by Riverstone for an aggregate purchase price of $20 million, of which TES paid $19 million. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts,” “Certain Relationships and Related Party Transactions—Riverstone Warrant Cancellation” and Note 16 in Notes to the Annual Financial Statements for additional information.
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Reorganization and Emergence
On May 9, 2022, TES and 71 of its subsidiaries commenced the Restructuring, and in December 2022, TEC joined the Restructuring to facilitate the transactions contemplated by the Plan of Reorganization. In December 2022, the Bankruptcy Court confirmed the Plan of Reorganization that implemented, among other things, the settlement of certain claims and commitments of TES’s debt holders and certain other of its obligations and the Exit Financings, which provided for the infusion of $1.4 billion of new equity capital into our business pursuant to the Rights Offering, the issuance of $1.2 billion aggregate principal amount of the Secured Notes and our entry into the Credit Facilities, which included: (i) $700 million in revolving commitments and $475 million in LC commitments under the RCF, (ii) $1.05 billion in commitments under the Term Loans, $470 million of which is used to cash collateralize trade and standby LCs, and (iii) $75 million in commitments under the Bilateral LCF to support the issuance of standby LCs.
On May 17, 2023, upon receipt of applicable regulatory approvals and the consummation of the Exit Financings, the Plan of Reorganization became effective and we emerged from the Restructuring with a significantly deleveraged balance sheet, driven by the full repayment of TES’s first-lien funded debt outstanding at the commencement of the Restructuring and the consensual equitization of all of TES’s existing Prepetition Unsecured Notes and PEDFA 2009 Bonds outstanding at the commencement of the Restructuring, which resulted in an approximate $2.5 billion reduction in TES’s debt and an additional $530 million of other liabilities subject to compromise. For additional information on the Restructuring, Plan of Reorganization and Exit Financings, see “Business—Restructuring and Financing Transactions,” “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and the notes to the consolidated financial statements included elsewhere in this prospectus.
Risk Factors Summary
An investment in our securities involves a high degree of risk. The occurrence of one or more of the events or circumstances described in the section titled “Risk Factors,” alone or in combination with other events or circumstances, may materially adversely affect our business, financial condition and operating results. In that event, the trading price of our securities could decline and you could lose all or part of your investment. Such risks include, but are not limited to:
Industry and Market Risks
Changes in the market price of electricity, natural gas and other commodities may materially adversely impact our financial condition, results of operations, liquidity and cash flows.
Declines in wholesale electricity prices or decreases in demand for electricity due to macroeconomic factors, such as the ongoing slowdown in the U.S. economy, significant advances in technology or changes in energy consumption, may significantly impact our margins and results of operations.
We face intense competition in the competitive power generation market, which may adversely affect our ability to operate profitably and generate positive cash flow.
Our business is subject to physical, market and economic risks relating to weather conditions, including the effects of climate change and extreme weather events, which may adversely affect our financial condition and results of operations.
Commercial and Operational Risks
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on our financial condition and results of operations, and we may not have adequate insurance to cover the risks and hazards.
Our ownership and operation of Susquehanna, which contributes a majority of our earnings associated with electric generation, subjects us to substantial risks associated with nuclear generation.
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Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Uncertainties in the supply of fuel and other necessary products could adversely impact us.
The retirement and potential reorganization of certain assets and subsidiaries could result in significant costs and have an adverse effect on our operating results.
Regulatory, Legislative and Legal Risks
Any change in the structure and operation of, or the various pricing limitations imposed by, the RTOs and ISOs in regions where our generation is located may adversely affect the profitability of our generation facilities.
Our ownership and operation of a nuclear power facility subjects us to regulations, costs and liabilities uniquely associated with these types of facilities.
The availability and cost of emission allowances could negatively impact our operating costs.
Changes in tax law (including any elimination of the Nuclear PTC), the implementation regulations of certain tax provisions or adverse decisions by tax authorities may adversely affect our business and financial condition.
Our ability to utilize our tax attributes, including net operating loss carryforwards, remaining following Emergence, if any, may be limited.
Our business may be affected by state interference in the competitive marketplaces.
Financial and Liquidity Risks
Our historical financial information may not be indicative of our future financial performance.
Our indebtedness could adversely affect our financial condition and impair our ability to operate our business.
Indebtedness subjects us to the risk of higher interest rates, which could cause our future debt service obligations to increase significantly.
Our debt agreements contain various covenants that impose restrictions on TES and certain of its subsidiaries that may affect our ability to operate our business and to make payments on our indebtedness.
Growth and Strategic Risks
Our project development activities through our Cumulus Affiliates may consume a significant portion of our management’s focus and resources, and if not completed or successful, reduce our profitability.
Joint ventures, joint ownership arrangements and other projects pose unique challenges to our Cumulus projects, and we may not be able to fully implement or realize synergies, expected returns or other anticipated benefits associated with such projects.
Our interest in and operation of a Bitcoin mining facility subjects us to certain risks.
Risks Related to Ownership of Our Common Stock
No prior public trading market existed for our common stock prior to trading on the OTC Pink Market, and an active trading market may not develop or be sustained following the registration of our common stock on Nasdaq, which may cause the market price of our common stock to decline significantly and make it difficult for investors to sell their shares in the future.
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We may not pay any dividends on our common stock in the future.
The requirements of being a public company may strain our resources, increase our costs and distract management, and, as a result, we may be unable to comply with these requirements in a timely or cost-effective manner.
Corporate Information
We were incorporated in Delaware on June 6, 2014. Our principal executive offices are located at 2929 Allen Pkwy, Suite 2200, Houston, TX 77019 and our telephone number is (888) 211-6011. Our website address is www.talenenergy.com. Information contained on, or that can be accessed through, our website is not incorporated by reference into this prospectus, and you should not consider information on our website to be part of this prospectus.
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THE OFFERING
Issuer
Talen Energy Corporation.
Outstanding common stock that may be offered by the Selling Stockholders
Up to 36,825,683 shares.
Common stock outstanding
50,841,161 shares.
Use of proceeds
We will not receive any of the proceeds from the resale of our common stock by the Selling Stockholders, but we have agreed to pay certain registration expenses. See “Use of Proceeds” and “Principal and Selling Stockholders.”
Symbol for common stock
We have been approved to list our common stock on Nasdaq under the symbol “TLN.”
Determination of offering priceThe Selling Stockholders may resell all or any part of the shares of our common stock offered hereby from time to time at fixed prices, prevailing market prices at the times of sale, prices related to such prevailing market prices, varying prices determined at the times of sale or negotiated prices.
Dividend Policy
The holders of shares of common stock are entitled to receive such dividends and other distributions (payable in cash, property or capital stock of the Company) when, as and if declared thereon by our board of directors (“Board of Directors”) from time to time out of any assets or funds of the Company legally available for the payment of dividends and shall share equally on a per share basis in such dividends and distributions.
Any future determination regarding the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors our Board of Directors may deem relevant. In addition, our ability to pay dividends may be restricted by any agreements we may enter into in the future.
Risk Factors
Before making a decision to invest in our common stock, you should carefully consider the information referred to under the heading “Risk Factors” beginning on page 19.
The information above excludes 7,083,461 shares of common stock reserved for issuance under our 2023 Equity Plan.
14


SUMMARY HISTORICAL AND UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION
The following tables set forth summary historical and unaudited pro forma condensed consolidated financial information for the Successor for periods subsequent to Emergence and the Predecessor and its consolidated subsidiaries for periods prior to Emergence. The financial statements of the Successor are not entirely comparable to the financial statements of the Predecessor as those periods prior to Emergence do not give effect to any adjustments to the carrying values of assets or amounts of liabilities that resulted from the Plan of Reorganization and the related application of fresh-start reporting, which includes accounting policies implemented by the Successor that may differ from the Predecessor. The summary historical consolidated financial information as of March 31, 2024 and for the three months ended March 31, 2024 and 2023, respectively, is derived from the unaudited condensed consolidated financial statements of the Successor and Predecessor, which are included elsewhere in this prospectus. The summary historical consolidated financial information (i) as of December 31, 2023 and for the period from May 18, 2023 through December 31, 2023 and (ii) as of and for the years ended December 31, 2022 and 2021 and for the period from January 1, 2023 through May 17, 2023 is derived from the audited consolidated financial statements of the Successor and Predecessor, respectively, each as included elsewhere in this prospectus.
The pro forma information reflects the consolidated financial information of the Predecessor for the period from January 1, 2023 through May 17, 2023 and the Successor for the period from May 18, 2023 through December 31, 2023. The pro forma adjustments give effect to (i) various transactions effected pursuant to the Plan of Reorganization and (ii) the application of fresh-start accounting. The unaudited pro forma condensed consolidated statement of operations for the year ended December 31, 2023 gives effect to the pro forma adjustments as if each adjustment had occurred on January 1, 2023, the first day of the last fiscal year presented. The summary unaudited pro forma condensed consolidated financial information is provided for illustrative purposes only and does not purport to represent what our actual consolidated results of operations would have been had the adjustments occurred on the dates assumed, nor is it necessarily indicative of future consolidated results of operations.
These tables should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” “Unaudited Pro Forma Condensed Consolidated Financial Information,” and the Interim Financial Statements and Annual Financial Statements, and, in each case, the related notes included elsewhere in this prospectus. In addition, as you review the consolidated Predecessor financial statements set forth herein you should be aware that such Predecessor financial statements may not be entirely comparable to our future financial statements because such Predecessor financial statements do not take into account the effects of the Plan of Reorganization and Emergence or any required adjustments for fresh-start reporting, in each case, which were taken into account in the Interim Financial Statements and the Annual Financial Statements and will be taken into account in our future financial statements.
Successor
Predecessor
SuccessorPredecessorPro Forma
Three Months Ended March 31, 2024
Three Months Ended March 31, 2023
Period
From
May 18,
Through
December 31,
2023
Period
From
January 1,
Through
May 17,
2023
Year Ended December 31,Year Ended December 31, 2023
20222021
(in millions, except per share amounts)
Operating revenues
$509 $1,073 $1,344 $1,210 $3,089 $928 $2,554 
Impairments
— (365)(3)(381)— — $(384)
Operating income (loss)
25 116 160 (76)241 (1,100)$117 
Net income (loss)
319 46 143 465 (1,293)(977)$85 
Weighted average shares of common stock outstanding — basic
58,807 N/A59,029 N/AN/AN/A59,029 
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Successor
Predecessor
SuccessorPredecessorPro Forma
Three Months Ended March 31, 2024
Three Months Ended March 31, 2023
Period
From
May 18,
Through
December 31,
2023
Period
From
January 1,
Through
May 17,
2023
Year Ended December 31,Year Ended December 31, 2023
20222021
Weighted average shares of common stock outstanding — diluted
60,716 N/A59,399 N/AN/AN/A59,399 
Net income (loss) per weighted average share of common stock outstanding — basic
5.00 N/A2.27 N/AN/AN/A$1.52 
Net income (loss) per weighted average share of common stock outstanding — diluted
4.84 N/A2.26 N/AN/AN/A$1.52 
Successor
Predecessor
As of March 31, 2024
As of December 31, 2023As of December 31, 2022
(in millions)
Total assets
$7,265 $7,121 $10,722 
Long term debt (including current portion)
2,628 2,820 3,504 
Total liabilities
4,499 4,587 11,204 
Total equity
2,766 2,534 (482)
Non-GAAP Financial Measures
We include in this prospectus Adjusted EBITDA, which we use as a measure of our performance, and which is not a financial measure prepared under GAAP. Non-GAAP financial measures, such as Adjusted EBITDA, 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 or used in our credit facilities, the indentures governing our notes or any of our other debt agreements. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, non-GAAP financial measures are numerical measures of financial performance, financial position or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions investors not to place undue reliance on such non-GAAP financial measures, but to also consider them along with their most directly comparable GAAP financial measures. Non-GAAP measures have limitations as an analytical tool and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
Adjusted EBITDA
We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.
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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) Cumulus Digital (until December 31, 2023) and noncontrolling interests; 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 of 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 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 the financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and across 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 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
Successor
Predecessor
Three Months Ended March 31,Three Months Ended March 31,
May 18 through December 31,
January 1 through May 17,Year Ended December 31,Year Ended December 31,
(in millions)20242023202320232022
2021
Net Income (Loss)
$319 $46 $143 $465 $(1,293)$(977)
Adjustments
Interest expense and other finance charges50 104 181 163 365 336 
Income tax (benefit) expense69 14 51 212 (35)(300)
Depreciation, amortization and accretion75 132 165 200 520 524 
Nuclear fuel amortization35 24 108 33 94 96 
Hedge termination losses, net (a)
— — — — 158 — 
Reorganization (gain) loss, net (b)
— 39 — (799)812 — 
Unrealized (gain) loss on commodity derivative contracts134 (31)(52)63 (625)712 
Nuclear decommissioning trust funds (gain) loss, net(75)(46)(108)(57)184 (196)
Stock-based and other long-term incentive compensation expense
— 21 — — — 
Long-term incentive compensation expense
10 — — — — — 
Environmental and ARO revisions on fully depreciated property, plant and equipment (c)
— — — 18 (7)
(Gain) loss on non-core asset sales, net (d)
(324)(35)(7)(50)(3)(3)
Non-cash impairments (e)
— 365 381 — — 
Legal settlements and litigation costs (f)
(2)— (84)20 
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Unusual market events (g)
(1)13 (19)14 33 78 
Net periodic defined benefit cost (h)
— (2)(3)12 36 
Operational and other restructuring activities (i)
48 17 522 13 
Liability management costs and other professional fees— — — — 46 29 
Development expenses— 10 17 
Non-cash inventory net realizable value, obsolescence, and other charges (j)
24 56 (4)24 
Consolidation of subsidiary (gain) loss, net
— — — — 170 — 
Cumulus Digital activities and noncontrolling interest (k)
(11)(3)(42)(14)— 
Other(1)— 
Total Adjusted EBITDA
$289 $660 $426 $695 $1,015 $387 
__________________
(a)Nonrecurring terminated commercial contracts. See Note 5 in Notes to the Annual Financial Statements for additional information.
(b)See Note 2 in Notes to the Interim Financial Statements and Note 3 in Notes to the Annual Financial Statements for additional information.
(c)See Note 11 in Notes to the Annual Financial Statements for additional information.
(d)See Note 17 in Notes to the Interim Financial Statements and Note 22 in Notes to the Annual Financial Statements for additional information.
(e)See Note 8 in Notes to the Interim Financial Statements and Note 10 in Notes to the Annual Financial Statements for additional information.
(f)See Note 10 in Notes to the Interim Financial Statements and Note 12 in Notes to the Annual Financial Statements for additional information.
(g)Represents the effect of market losses and settlements for Winter Storm Elliott that occurred in 2022 and Winter Storm Uri that occurred in 2021.
(h)Consists of postretirement benefits service cost and postretirement benefits gain (loss).
(i)2022 primarily includes non-cash charges for estimates of damages for contracts terminated in connection with the Restructuring. See Note 3 in Notes to the Annual Financial Statements for additional information.
(j)See Note 6 in Notes to the Interim Financial Statements and Note 8 in Notes to the Annual Financial Statements for additional information.
(k)Noncontrolling interest only beginning in the first quarter of 2024.

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RISK FACTORS
Investing in our common stock involves a high degree of risk. You should consider and read carefully all of the risks and uncertainties described below, as well as other information included in this prospectus, including our consolidated financial statements and related notes appearing elsewhere in this prospectus and in the section titled “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” before making an investment decision. The risks described below are not the only ones we face. 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 or results of operations. In such case, the trading price of our common stock could decline, and you may lose some or all of your original investment. “Talen,” “we,” “us” and “our,” unless the context requires otherwise, refer collectively to TEC, TES and TEC’s other subsidiaries.
Industry and Market Risks
Changes in the market price of electricity, natural gas and other commodities may materially adversely impact our financial condition, results of operations, liquidity and cash flows.
Market prices for electricity, capacity, ancillary services, natural gas, uranium, coal and oil are unpredictable and fluctuate substantially over relatively short periods. Market prices for electricity are particularly volatile due to electricity’s inability to be stored in large quantities, so it must be used as it is produced. This results in electricity prices being subject to significant fluctuations based on supply and demand imbalances in the day-ahead and real-time markets. As a result of the use of natural gas in facilities that often serve as the marginal, price-setting generating units, there is also a strong positive correlation between the price of natural gas and the wholesale market price of electricity, in each case in the competitive electric markets in which we operate. In recent years, the market price of natural gas has experienced significant volatility, while prices for other fuels have also varied. Our energy margins are significantly influenced by the relationship between the price of electricity, the price of natural gas and, to a lesser extent, the price of other fuels like coal and uranium. A decline in the price of natural gas, including any negative impact on energy prices resulting therefrom, could materially adversely impact our energy margins, liquidity and results of operations.
Our business is subject to physical, market and economic risks relating to weather conditions, including the effects of climate change and extreme weather events, which may adversely affect our financial condition and results of operations.
Our operations are significantly impacted by weather conditions, which directly influence the demand for electricity and affect the price of energy. As of March 31, 2024 after giving effect to the ERCOT Sale, approximately 97% of our capacity was located in PJM. A warmer winter in the Mid-Atlantic may suppress regional natural gas prices and reduce our energy margins, particularly in PJM. Alternatively, warmer summer temperatures tend to increase cooling electricity demand, energy prices and margins, and cooler winter temperatures tend to increase winter heating electricity demand, energy prices and margins. Furthermore, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation expenses during the winter in the Mid-Atlantic and, prior to the ERCOT Sale, during the summer in Texas. Moderate temperatures reduce the usage of electricity and adversely affect resulting energy margins to the extent that weather is cooler in the summer or warmer in the winter than forecasted. Moreover, extreme weather events, such as Winter Storm Uri and Winter Storm Elliot, can also materially impact power prices or otherwise exacerbate conditions or circumstances that result in volatility of power prices. Weather conditions, which cannot be accurately predicted, may have an adverse effect on our business, results of operations and financial condition, including by requiring us to sell excess electricity on the spot market at a time when market prices are weak.
In addition, the potential physical effects of climate change, such as increased frequency and severity of storms, floods and other climatic events, could disrupt our operations and cause us to incur significant costs in preparing for or responding to these effects. These or other meteorological changes could lead to increased operating costs, capital expenses or power purchase costs. Climate change could also affect the availability of a secure and economical supply of water in some locations, which is essential for the continued operation of our generation facilities.
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Declines in wholesale electricity prices or decreases in demand for electricity due to macroeconomic factors, such as the ongoing slowdown in the U.S. economy, significant advances in technology or changes in energy consumption, may significantly impact our margins and results of operations.
Adverse economic conditions may reduce the demand for electricity in the key wholesale power markets we serve. In addition, improvements in energy efficiency, conservation efforts and other shifts in energy consumption have slowed, and may continue to slow, electricity consumption growth, particularly in PJM, and may eventually reduce consumption of electricity, which would likely affect our business over the long term. The combination of lower demand for electric power, an increasing supply of natural gas and penetration of renewables in the markets in which we operate has, and may continue to, put downward price pressure on wholesale power market prices in general, further impacting our results of operations. Economic and commodity market conditions will continue to impact our margins on unhedged future energy production, liquidity, earnings growth and overall financial condition.
Our industry is subject to significant advances in technology, including the introduction of new products, technologies and methods of electric power generation. Changes in technology or increased electricity conservation efforts may reduce the value of our generation facilities and may otherwise have a material adverse effect on us. Technological advances have improved, and are likely to continue to improve, existing and alternative methods to produce, dispatch and store power, which could have the further effect of increasing the overall electricity supply. In addition, technological advances in demand-side management and increased conservation efforts have decreased, and are expected to continue decreasing, electricity demand. As a result of these technological advances and changes in consumption patterns, the dispatch, Capacity Factors and value of our generation facilities could decline, which could have a material adverse effect on our financial condition, operating cash flows and results of operations.
We face intense competition in the competitive power generation market, which may adversely affect our ability to operate profitably and generate positive cash flow.
We sell our available electricity and ancillary services and products into competitive wholesale markets through the day-ahead and real-time spot market, and under contracts of varying duration. Our competitors include regulated utilities, industrial companies, other non-utility generators, competitive subsidiaries of regulated utilities, financial institutions and other energy marketers. Additionally, we may face competitors that have access to greater resources, newer generation facilities, lower costs or more experience, which could adversely affect our ability to compete in our markets.
Competition in the wholesale power markets occurs principally on the basis of the price of products and, to a lesser extent, reliability and availability. Competition is affected by electricity and fuel prices, relative cost of production of electricity products, new market entrants and barriers thereto, construction by others of generation or storage assets and transmission capacity, technological advances in power generation, the actions of environmental and other regulatory authorities, establishment of legislation which favors one form of generation over another, such as investment tax credits or production tax credits and other factors. For example, substantial quantities of new generation capacity, including new combined cycle gas and renewable power generation, have been proposed and are under construction in PJM. Commencement of commercial operation of such facilities will increase the supply of electricity, and thus competition, in the wholesale power markets in these regions.
Our wholesale business is also dependent on our ability to operate successfully in a competitive environment and, unlike regulated utilities, we are not assured of any rate of return on capital investments through a regulated rate structure. These competitive factors may negatively affect our ability to sell electricity and related products and services, as well as the prices that we receive for these products and services.
Furthermore, federal and certain state entities in jurisdictions in which we operate have either enacted or are considering regulations or legislation to subsidize otherwise uneconomic plants and attempting to incentivize, including through certain tax benefits, the construction and development of additional renewable or carbon-free resources, as well as increases in energy efficiency investments. For example, the Inflation Reduction Act contains a number of tax credits and incentives relating to new renewable projects and clean energy technologies. These
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incentives could result in increased competition for us, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Our generation business is subject to extensive regulation, including requirements that we obtain and comply with government permits and approvals, which may increase our costs, reduce our revenues or prevent or delay operation of our facilities.
We are required to obtain, and to comply with, numerous permits, approvals, licenses and certificates from governmental agencies. Obtaining and renewing permits can be lengthy and complex and can sometimes result in the establishment of permit conditions that make the project or activity for which the permit was sought unprofitable or otherwise unattractive. Moreover, renewal of existing permits could be denied or jeopardized by various factors, including failure to provide adequate financial assurance for closure, local community, political or other opposition or executive, legislative or regulatory action. The cost of, or the inability to obtain or comply with the conditions of permits or approvals, may result in the delay or temporary suspension of our operations and electricity sales or the curtailment of our power delivery and may subject us to penalties and other sanctions.
Our generation subsidiaries sell electricity into the wholesale markets. Our generation subsidiaries and our marketing subsidiary are subject to rate, financial and organizational regulation by FERC. FERC has authorized us to sell energy, capacity and ancillary services at market-based prices and has granted us various waivers and blanket approvals customarily granted to market-based rate sellers, including a blanket authorization to issue securities and to assume liabilities. FERC retains the authority to modify or withdraw our market-based rate authority and to impose cost-based rates if it determines that the market is not competitive, that we possess market power in one or more markets, that we are not charging just and reasonable rates or that we have violated FERC’s market behavior rules or engaged in market manipulation. Any reduction by FERC in the rates that we may receive, any revocation of the waivers and blanket authorizations we have received from FERC, or any new or unfavorable changes to the regulation of our business by federal or state regulators could materially adversely affect our results of operations. In addition, if we were found to have violated FERC’s market behavior rules or other FERC requirements, FERC could impose civil penalties or order us to disgorge profits associated with the violation. Pursuant to the Capacity Performance construct, we are subject to economic penalties for generation non-performance up to our capacity commitments during certain PJM emergency events, which penalties could be material. See “—Regulatory, Legislative and Legal Risks—Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and regulatory entities to investigate and determine the causes of such events and may result in changes in applicable laws and regulations, mandatory reliability requirements and market rules, including to reform PJM.”
Our generation assets are also subject to the reliability standards promulgated by the FERC-designated Electric Reliability Organization (currently NERC) and approved by FERC. If we fail to comply with the mandatory reliability standards, we could be subject to sanctions, including substantial monetary penalties and increased compliance obligations.
Events outside of our control, including armed conflicts, war, terrorist attacks or threats, pandemics, cyber-based attacks and other significant events could have a material adverse effect on our business.
Instability and unrest, as well as threats of war, other armed conflict and economic sanctions may lead to acts of war or terrorism or other economic disruption and high levels volatility in prices for oil and natural gas and the supply of nuclear fuel, which may significantly affect our business and results of operations.
In addition, we could be significantly affected by an epidemic, outbreak of an infectious disease or other public health events that are outside of our control. Depending on the severity of such an event and the resulting impacts to workforce and other resource availability, the ability to operate our generation facilities could be affected, resulting in decreased service levels and increased costs. Additionally, as our power generation facilities are geographically concentrated in certain areas of the United States, we face increased risk that a natural or man-made disaster in one of our geographical areas could adversely affect a significant percentage of our operations.
The operation of our business is also subject to cyber-based security and integrity risk, which could result in an adverse impact to our reputation or our results of operations. The operation of our generation facilities and of our
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wholesale power sales rely on cyber-based technologies and, therefore, subject to the risk that such systems could be the target of disruptive actions, particularly through cyber-attack or cyber intrusion, including by computer hackers, foreign governments and cyber terrorists, or otherwise be compromised by unintentional events. As a result, operations could be interrupted, property could be damaged and sensitive customer information could be lost or stolen, causing us to incur significant losses of revenues, other substantial liabilities and damages, costs to replace or repair damaged equipment and damage to our reputation. In addition, we may experience increased capital and operating costs to implement increased security for its cyber systems and physical security at our generation facilities.
Commercial and Operational Risks
Operation of power generation facilities involves significant risks and hazards customary to the power industry that could have a material adverse effect on financial condition and results of operations, and we may not have adequate insurance to cover the risks and hazards.
Power generation involves hazardous activities, including transporting, storing and handling fuel, operating large pieces of electrical and other equipment and connecting to high voltage transmission and distribution systems. As a result, our employees, contractors, customers and the general public may be exposed to risks inherent in the nature of our operations, including hazards such as nuclear accidents, accidents involving high voltage electrical equipment, environmental hazards, fires or explosions, structural failures, machinery failures and other dangerous incidents. These and other hazards can cause significant personal injury or loss of life, severe property damage or destruction and any such event may expose us to liability for substantial damages, fine or penalties. Although we currently maintain customary insurance coverage for certain of these risks, we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject, or that insurance coverage will continue to be available at economic rates. See “Business—Insurance.” Any losses not covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
We may experience unplanned interruptions or periods of reduced output, which could have a material adverse effect on our results of operations, cash flows and financial condition.
Operation of our generation facilities and other assets subjects us to a variety of risks, including from accidents, equipment failures, electrical delivery or transportation problems, fuel supply disruptions, environmental incidents, security and information technology breaches, labor disputes, obsolescence and below-expected performance. Any unexpected failure, including failure associated with breakdowns or forced outages, as well as any unanticipated capital expenditures, could result in reduced profitability. Although we maintain customary insurance coverage for certain of these risks, no assurance can be given that such insurance coverage will be sufficient to compensate us fully in the event losses occur. Our facilities require periodic maintenance and repair, and frequent or prolonged planned or unplanned outages could further affect our results of operations, including by requiring us to purchase power at then-current market prices to satisfy our commitments. Furthermore, we cannot be certain of the level of capital expenditures that will be required due to needed facility maintenance and repairs, competitive developments, changing environmental and safety laws and unexpected events, and any such expenditures could be significant.
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 deliver the electricity that we produce to our counterparties. If the transmission service from these facilities is unavailable or disrupted, or if the transmission capacity infrastructure is inadequate, our ability to sell and deliver wholesale power may be materially adversely affected. Electric power blackouts are possible and have occurred, which could disrupt electrical service for extended periods of time. If a blackout were to occur, the impact could result in interruptions to our operations, increased costs to replace existing contractual obligations, the possibility of regulatory investigations and potential operational risks to our facilities. Transmission constraints and outages, including line maintenance outages, can cause transmission congestion that negatively impacts energy
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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, some of which could be significant.
Our ownership and operation of Susquehanna, which contributes a majority of our earnings associated with electric generation, subjects us to substantial risks associated with nuclear generation.
Susquehanna accounted for a majority of our generation and associated earnings in 2023, and we expect that it will continue to contribute a majority of our generation and associated earnings in the future. Accordingly, an adverse development in Susquehanna’s operations, such as an unplanned outage or catastrophic event, could have a significant impact on our results of operations and liquidity. The risks and uncertainties of our nuclear generation include, among other things:
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 spent nuclear fuel (“SNF”) at our on-site dry cask storage facility;
potential impacts of natural disasters, terrorist attacks, cyber security threats or other unforeseen events, and the costs of preventing, preparing for, and responding to any such events;
limitations on the amounts and types of insurance coverage commercially available;
the technological and financial aspects of modifying or decommissioning nuclear facilities at the end of their useful lives;
extensive regulation associated with ownership and operation of nuclear facilities; 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. Although we have met or exceeded our availability targets and have timely completed our planned refueling outages for several years, if future refueling outages last longer than anticipated or Susquehanna experiences unplanned outages for any reason, our results of operations and liquidity could be adversely affected. In addition, if Susquehanna were to experience a significant disruption to its operations, it is possible that our ability to meet our capacity commitments and obligations under long-term power supply contracts, including under the Cumulus Data Campus PPA, could be negatively impacted.
In addition, the costs associated with the nuclear fuel cycle are substantial and the suppliers for certain components and other materials required to produce nuclear fuel are limited. Any disruption to the availability of these components and other materials, whether temporary or long-term, could cause unplanned outages and have a significant impact on the cost of nuclear fuel or otherwise impact our ability to profitably operate Susquehanna.
There remains substantial uncertainty regarding the nuclear industry’s permanent disposal of SNF, which could result in substantial additional costs to us that cannot be predicted. Federal law requires the U.S. Government to provide for the permanent disposal of commercial SNF. Prior to May 2014, nuclear operators were required to contribute to a fund to pay for the transportation and disposal of SNF. In May 2014, this fee was reduced to zero. We cannot predict if or when the U.S. Government will increase this fee in the future, which could result in significant additional costs to us. Susquehanna is currently party to an agreement with the U.S. Government that requires the U.S. Government to reimburse certain costs to temporarily store SNF at the Susquehanna facility through the end of 2025. However, we cannot be certain that this arrangement will be extended beyond 2025.
Although the safety record of nuclear reactors generally has been very good, accidents and other unforeseen problems have occurred both in the United States and abroad. The consequences of a major incident could be severe,
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including loss of life and property damage and could materially adversely affect our results of operations and liquidity.
Our operations may impact the environment or cause exposure to hazardous substances, and our properties may have environmental contamination, which could result in material liabilities to us.
Certain of our operations pose risks of environmental liability due to leakage, migration, emission, releases or spills of hazardous substances to the air, surface or subsurface soils, surface water or groundwater. Certain environmental laws impose strict as well as joint and several liability for costs required to remediate and restore sites. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. We could be held responsible for all liabilities associated with the environmental condition of our generation facilities, including remediation or removal of any soil or groundwater contamination that may be present, regardless of whether we were responsible for the creation of the environmental condition or it arose from the activities of predecessors or third parties and even if our operations met previous standards in the industry at the time they were conducted.
Our activities related to hedging and asset management may result in economic losses and/or limited liquidity.
We actively manage the market risk inherent in our generation and energy marketing activities, as well as monitor compliance with our risk management processes. Nonetheless, such programs may not manage or eliminate all risks or work as expected in all potential market outcomes. For example, actual electricity and fuel prices may be significantly different or more volatile than the historical trends and assumptions upon which we based our risk management calculations. Unforeseen market disruptions could decrease market depth and liquidity, negatively impacting our ability to enter into new transactions. We enter into financial contracts to hedge commodity “basis risk” and as a result are exposed to the risk that the correlation between delivery points could change with actual physical delivery. As a result, we cannot always predict the impact that our risk management decisions may have on us if actual events result in greater losses or costs than our risk models predict or greater volatility in our earnings and financial position. Any failure of our risk management activities to adequately manage the market risk inherent in our operations could adversely affect our business, financial condition and results of operations.
In addition, we are also exposed to market risks associated with selling and marketing products in the wholesale power markets, including, among other risks, volatility arising from location and timing differences that may be associated with buying and transporting fuel and other electricity-related commodities, converting fuel into power and satisfying our contractual electricity sales obligations. We may from time to time undertake these activities to hedge those risks through hedging agreements with various counterparties, many of which require us to provide guarantees, offset or netting arrangements, LCs, a first lien on assets and/or cash collateral to protect the counterparties against the risk of our default or insolvency.
Significant movements in market prices can cause us to be required to provide cash collateral and letters of credit in very large amounts. The effectiveness of our strategy may be dependent on the amount of collateral available to enter into or maintain these contracts, and liquidity requirements may be greater than we anticipate or will be able to meet. Without a sufficient amount of working capital to post as collateral, we may not be able to manage price volatility effectively or to implement our hedging strategy. An increase in the amount of LCs or cash collateral required to be provided to our counterparties may have a material adverse effect on us. As we are required to collateralize hedges that settle in future delivery periods, but do not receive settlements for electric generation until delivery, such collateral requirements could result in lower available cash and liquidity, which could adversely affect our business, financial condition and results of operations.
We believe that we will have sufficient liquidity to fulfill our collateral obligations under these agreements. However, our obligation to post collateral could exceed the amount of our available liquidity, particularly if power prices increase significantly, and our ability to obtain additional liquidity could be limited by our debt or other agreements, willingness of lenders to lend us additional capital, financial markets or other factors.
Despite reduced exchange trading, we may still have significant obligations that require cash collateral or the posting of LCs, which are at risk of being drawn down in the event we default on our obligations. In the normal course of business, we enter into agreements that provide financial performance assurance to third parties on behalf
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of certain subsidiaries for certain obligations, which may include guarantees, stand-by LCs issued by financial institutions, surety bonds issued by insurance companies and indemnifications. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers, in each case upon the occurrence of certain events. TES has surety bonds posted to the MDEQ on behalf of Talen Montana’s proportional share of remediation and closure activities and has, in the past, issued LCs for support of its development and construction activities. If our LCs were drawn down, this may have a material adverse effect on our cash and liquidity, business, financial condition and results of operations.
Our commercial risk management activities may increase the volatility in our quarterly and annual financial results.
We employ a variety of commercial, physical and financial instruments to hedge commodity price volatility, provide stable cash flow generation and preserve forward margin. Certain of these transactions are recognized on the balance sheet at fair value with changes in their fair values resulting from fluctuations in the underlying commodity prices recognized in earnings. However, not all commercial risk management transactions meet the accounting standard for such accounting treatment and, accordingly, there may be timing differences between when these instruments are recognized in earnings. Additionally, even where the changes in fair values of these instruments are immediately recognized in earnings, those changes may not entirely offset the changes in fair values of the instruments that are subject to the hedges. Further, when commercial contract expires or is terminated, we may not secure replacement on acceptable terms or timing, if at all. It is possible that subsequent commercial contracts may not be available at prices that permit the operation of our generation fleet on a profitable basis. As a result, during periods of extreme price volatility or significant changes in market prices, our quarterly and annual results are subject to significant fluctuations due to changes in fair values of commodity derivative instruments caused by changes in market prices.
We are exposed to credit risk and potential concentrations of credit risk resulting from ISOs, other customers and other market counterparties, financial institutions and other parties.
We are subject to the risk of loss resulting from nonpayment by our contractual counterparties in the ordinary course of our business, including ISOs, other customers and other market counterparties and other parties to whom we supply certain products or services. As part of our risk management procedures, we have established credit procedures to evaluate counterparty credit risk, but these procedures and policies may not be adequate to fully identify or effectively manage customer and counterparty credit risk. Further, we cannot predict to what extent our business would be impacted by deteriorating conditions in the economy, including declines in our purchasers’ and hedging counterparties’ creditworthiness. Unanticipated deterioration in the creditworthiness of existing or future customers and hedging counterparties, and any resulting increase in nonpayment or nonperformance by them could cause us to reserve for or write-off uncollectible accounts.
Additionally, we are exposed to concentrations of credit risk from suppliers and customers among electric utilities, financial institutions, marketing and trading companies and the U.S. Government. These concentrations may impact our overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions. See Note 3 in Notes to the Interim Financial Statements and Note 5 in Notes to the Annual Financial Statements for more information.
Uncertainties in the supply of fuel and other necessary products could adversely impact us.
We purchase fuel and other consumables during the production of electricity (such as coal, natural gas, uranium, oil, water, lime, limestone and other chemicals and sorbents) from a number of suppliers. Delivery of these fuels and other consumables to our facilities is dependent upon the continuing financial viability of our contractual counterparties, as well as the transportation infrastructure available to serve each generation facility. If our suppliers or other contractual counterparties fail to perform, we may be forced to not operate, curtail the production of electricity or enter into alternative arrangements. If we have agreements in place to deliver firm electricity and capacity and fail to do so, we could be required to procure electricity from third parties to meet our contractual or capacity obligations or to otherwise pay market-based damages. Depending on price volatility in the wholesale power markets, such damages could be significant.
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We sell forward a portion of our forecasted power generation in order to lock in future power prices that we deem to be favorable at the time we enter into the forward power sales contracts. In order to hedge our cost of production relating to those obligations, we may enter into forward contracts for the purchase and delivery of fuel. Many of the forward power sales contracts do not allow us to pass through changes in fuel costs or discharge the power sale obligations in the case of a disruption in fuel supply due to force majeure events or the default of a fuel supplier or transporter. Disruptions in our fuel supplies may require us to find alternative fuel sources at higher costs, find other sources of power to deliver to counterparties at a higher cost or pay damages to counterparties for failure to deliver power as contracted. Any such event could have a material adverse effect on our results of operations, liquidity or financial condition. Where we have assumed a forward capacity obligation in the PJM capacity market, we may also be exposed to substantial penalties if we fail to generate electricity as ordered during certain emergency periods. Extreme weather conditions, unplanned generation facility outages, environmental compliance costs, transmission disruptions and other factors could affect our ability to meet our obligations or cause significant increases in the market price of replacement capacity and electricity.
We also buy some of our fuel and other consumables on a short-term or spot market basis. Prices for all of our fuels and other products fluctuate, sometimes rising or falling significantly over a relatively short period of time. The price we can obtain for the sale of electricity may not rise at the same rate, or may not rise at all, to match a rise in fuel and other products or their delivery costs. This may have a material adverse effect on our financial performance.
The retirement and potential reorganization of certain assets and subsidiaries could result in significant costs and have an adverse effect on our operating results.
Since 2016, we have retired three economically nonviable coal-fired units, and we have committed to cease burning coal at Montour, Brandon Shores and Wagner by the end of 2025 and Brunner Island by the end of 2028. (However, for additional information on potential Reliability-Must-Run arrangements affecting Brandon Shores and Wagner, see Note 8 in Notes to the Interim Financial Statements.) In connection with the closure and remediation of retired generation units, we have spent, and may in the future spend, a significant amount of money, internal resources and time to complete the required closure and reclamation, which could result in significant costs and have a material adverse effect on our financial and operating performance.
The carrying value of our property, plant and equipment is subject to impairment charges.
Property, plant and equipment used in operations is assessed for impairment whenever changes in facts and circumstances indicate the carrying amount of the asset group may not be recoverable. If we were to experience events, among others, such as a prolonged economic downturn, significant changes to generation facility useful lives, a decrease in the market price of an asset, increased costs, certain negative financial trends or significant changes to the market conditions or the regulatory environment, we could experience future generation facility impairments, which may result in a material adverse effect on our financial conditions, results of operations and cash flows.
Because we own less than a majority of the ownership interests in certain of our generation facilities, we cannot exercise complete control over the related operations and are exposed to the risk associated with the collection of shared expenses from co-owners of jointly owned facilities.
We have limited control over the ownership, and in some cases, the operation of our joint-owned facilities, including the Conemaugh and Keystone generation facilities. We also own 30% of Colstrip Unit 3. We are subject to costs and output-sharing arrangements in respect of Colstrip Units 3 and 4 which are operated by Talen Montana. We seek to exert a degree of influence with respect to the management and operation of these generation facilities by either operating these facilities (i.e., Colstrip) or negotiating to obtain positions on management committees or to receive certain limited governance rights, but we may not always succeed in such negotiations.
In many instances we depend on these co-owners for elements of these arrangements that are important to the success of the joint operation, such as funding their proportional share of capital and operating costs. These co-owners may not have the level of experience, technical expertise, human resources management and other attributes necessary to operate these projects optimally. Moreover, some of these co-owners are rate regulated utilities that
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have significantly different economic incentives and obligations than our business. The ability of co-owners to meet their obligations under any joint operating or other agreement is outside our control. If our current or future co-owners are unable or fail to meet their obligations under these arrangements, the performance, success and value of these arrangements may be adversely affected, and 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 our co-owners and us. If any of these events occur, they may adversely impact us, our financial performance and results of operations, these joint operations or our ability to enter into future joint operations.
If we are unable to successfully retain and attract an appropriately qualified workforce, our financial position or results of operations could be negatively affected.
Retaining key employees and attracting new employees are important to both our operational and financial performance. We cannot guarantee that any member of our leadership team or our key employees will continue to serve in any capacity for any particular period of time. An aging workforce, mismatch of skill set, expectation of future needs, uncertainty around the future of our aging assets or unavailability of short-term contract employees or contractors may lead to operating challenges and increased costs. The challenges that we might face as a result of such risks include a lack of human resources, losses to our operational knowledge base and the time and other resources required to develop new workers’ skills. In particular, our operations at Susquehanna are dependent on highly specialized personnel, and any prolonged absence by these persons may adversely impact our ability to operate. If we are unable to successfully retain and attract an appropriately qualified workforce, our financial position or results of operations could be negatively affected.
Further, we are also subject to the risk of strikes or work stoppages by unionized employees. As of March 31, 2024 after giving effect to the ERCOT Sale, we had 1,892 full-time employees, approximately 44% of which were represented by labor unions. In the event that our union employees participate in a strike, work stoppage or slowdown or engage in other forms of labor disruption, we would be responsible for procuring replacement labor and could experience reduced power generation or outages. Strikes, work stoppages or the inability to negotiate future collective bargaining agreements on favorable terms could have a material adverse effect on our business, financial condition and results of operations.
Significant increases in our labor and benefit expenses, including health care and pension costs, could adversely affect our earnings and liquidity.
We expect to continue to face increased cost pressures in our operations because of increased costs of labor from heightened inflation, the need for higher-cost expertise in the workforce and other factors. Rising or persistently high inflation rates could have a material adverse effect on our business, financial condition, results of operations and liquidity. In addition, pursuant to collective bargaining agreements, we are contractually committed to provide specified levels of health care and pension benefits to certain current employees and retirees. We provide similar benefits to our non-union employees. Due to general inflation with respect to such costs, the aging demographics of our workforce, health care cost trends and other factors, we expect our health care costs, including prescription drug coverage, to continue to increase, despite measures that we have taken to reduce such costs.
As of December 31, 2023, our qualified defined benefit pension plans for our retirees and certain employees were underfunded by an estimated $333 million with a total benefit liability of an estimated $1.31 billion. We expect to continue to incur significant costs with respect to the defined benefit pension plans for our retirees and certain of our employees. The measurement of our expected future pension obligations and costs is highly dependent on a variety of assumptions, most of which relate to factors beyond our control, including investment returns, interest rates, inflation rates, salary increases, future government regulation, required or voluntary contributions made to the plans and the demographics of plan participants. If our assumptions prove to be inaccurate, our costs and cash contribution requirements to fund these benefits could increase significantly. Further, without sustained growth in the pension investments over time, and depending upon the assumptions impacting costs listed above, we could be required to fund our plans with significant amounts of cash in advance of the time we would otherwise fund such payments. Future changes in funding requirements associated with our pension plans, including as a result of poor performance or inaccurate assumptions, or an adverse decision in the litigation related to the TERP (see “Business—
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Legal Matters—Pending Legal Matters—Pension Litigation”) could have a material adverse effect on our financial condition, results of operations and liquidity. Under the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), the Pension Benefit Guaranty Corporation (“PBGC”) has the authority to 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).
Regulatory, Legislative and Legal Risks
Any change in the structure and operation of, or the various pricing limitations imposed by, the RTOs and ISOs in regions where our generation is located may adversely affect the profitability of our generation facilities.
We do not own or control the transmission facilities required to deliver the wholesale power from our generation facilities to load. In most cases, RTOs and ISOs operate transmission facilities and provide related services, administer organized power markets and maintain system reliability. Many of these RTOs and ISOs operate the real-time and day-ahead markets in which we sell electricity. The RTOs and ISOs that oversee most of the wholesale power markets impose, and may continue to impose, offer caps, price limitations and other mechanisms to guard against the potential exercise of market power in these markets. These and other regulatory mechanisms may adversely affect the profitability of our generation facilities that sell electricity and capacity into the wholesale power markets. Problems or delays that may arise in the formation and operation of maturing RTOs and similar market structures, or changes in geographic scope, rules or market operations of existing RTOs, may also affect our ability to sell, the prices we receive or the cost to transmit power produced by our generation facilities. Rules governing the various regional power markets may also change from time to time, which could affect our costs or revenues. As a result, our financial condition, results of operations, liquidity and cash flows may be materially adversely affected.
FERC has issued regulations that require wholesale electricity transmission services, even when offered by parties other than RTOs and ISOs, to be offered on an open-access, non-discriminatory basis. Although these regulations are designed to encourage competition in wholesale market transactions for electricity, there is the potential that fair and equal access to transmission systems will not be available or that transmission capacity will not be available in the amounts we require. We cannot predict the timing of industry changes as a result of these initiatives or the adequacy of transmission facilities in specific markets or whether ISOs, RTOs or other transmission providers in applicable markets will efficiently operate transmission networks and provide related services. Furthermore, regulatory approvals and orders that we have obtained may be subject to challenge and protest from time to time. See “Business—Regulatory Matters” for additional information about ongoing regulatory matters.
There is also unpredictability around capacity revenues due to lack of reliable pricing and PJM Base Residual Auctions. The PJM market is undergoing significant restructuring due to recent weather events that have exposed systemic flaws, resulting in decline or delay in a substantial portion of capacity revenues. We cannot predict what these market reforms will look like or their impact on capacity revenues in the future. Please see Note 10 in Notes to the Interim Financial Statements and Note 12 in Notes to the Annual Financial Statements for more information on the capacity market and systemic risks in PJM.
PJM has established capacity auction dates based upon FERC orders establishing rules for such capacity markets, but we cannot guarantee those auctions will take place on those dates or at all.
Our power generation business competes with other non-utility generators, regulated utilities, unregulated subsidiaries of regulated utilities, other energy service companies and financial institutions. The competitive wholesale marketplace may be undermined by changes in market structure and the actions of federal or state entities, including out-of-market payments to nuclear facilities, renewable mandates or subsidies and out-of-market payments to new generators.
In July 2021, PJM filed proposed tariff language to significantly reduce the application of the existing PJM MOPR by applying it only when the state requires an entity to act in a certain manner in the capacity market in exchange for receiving a subsidy. FERC did not act on PJM’s July 2021 filing, and the PJM MOPR tariff language
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went into effect in September 2021. In December 2023, the U.S. Court of Appeals for the Third Circuit denied the petitions for review of the MOPR tariff language. On March 28, 2024, the Public Utilities Commission of Ohio filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the December 2023 order of the Third Circuit. The final impacts on Talen’s financial condition, results of operations and liquidity are not known at this time.
In June 2023 and February 2024, FERC accepted requests by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delays currently schedule the PJM Base Residual Auctions for 2025/2026 in July 2024, 2026/2027 in December 2024, 2027/2028 in June 2025 and 2028/2029 in December 2025. Although PJM has established dates for the next four auctions, there is no guarantee that the auctions will take place on those dates or at all. Depending on the ultimate outcome of matters related to PJM’s capacity auctions, capacity revenues in PJM could be affected, which could have a material adverse effect on our business, financial condition and results of operations.
There is uncertainty related to the future profitability of our fossil fuel-fired power generation business and the amount and timing of associated environmental liabilities.
Many political and regulatory authorities, along with certain financing sources and environmental groups, are devoting substantial resources and efforts to minimize or eliminate the use of fossil fuels as a source of electricity generation, domestically and internationally, thereby reducing the demand and pricing for electricity generated at fossil fuel-fired generation facilities and potentially materially and adversely impacting our future financial results, liquidity, ability to raise capital and growth prospects.
Concerns about the environmental impacts of fossil fuel combustion, including impacts on global climate issues, are resulting in increased regulation of coal combustion and greenhouse gas (“GHG”) emissions, unfavorable lending policies toward the financing of fossil fuel-fired power generation facilities and divestment efforts affecting the investment community, which could significantly affect demand for our products or our securities. Climate issues continue to attract public, scientific and governmental attention to global climate issues and to emissions of GHGs. Changes to the legal and regulatory framework governing electricity generation resulting from such concerns could have a material adverse effect on our operations, cash flow and financial condition. For example, the new water, waste, air and climate rules recently finalized by the EPA could require us to incur costs to comply if they withstand legal challenges. These costs include asset modifications and potential emission control equipment investments, as well as reporting requirements. See “Business—Environmental Matters” for additional information on these new rules. Furthermore, any new legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the power we produce.
Enactment of laws or passage of regulations regarding emissions from the combustion of coal, natural gas or oil by the United States, some of its states or other countries, or other actions to limit such emissions, could also result in electricity generators further switching from coal or natural gas to other fuel sources or additional fossil fuel-fired power generation facility closures. We operate an aging fossil fleet and many of our facilities require periodic maintenance and repair. If we significantly modify a unit such that regulated pollutants are increased beyond thresholds set by the EPA pursuant to New Source Review guidelines promulgated under the Clean Air Act, we may be required to install the best available control technology or to achieve the lowest achievable emission rates, which would likely result in substantial additional capital expenditures.
Compliance with legal and regulatory requirements related to coal-fired generation operations and CCR could have a material and adverse effect on our results of operations, cash flows and liquidity.
In accordance with the relevant legal and regulatory requirements, we perform certain activities to manage large quantities of CCR material resulting from decades of coal-fired electric generation. In particular, Talen Montana has significant decommissioning and environmental remediation liabilities primarily consisting of its proportionate share of remediation, closure and decommissioning costs for coal ash impoundments at the Colstrip Units. Where applicable, we carry the expected cost of these obligations within our ARO liabilities. Actual cash expenditures associated with these AROs are expected to materially increase over the next five years due to the expected timing and scope of anticipated remediation activities and will continue at a reduced spending level for several decades.
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Moreover, new regulations recently finalized by the EPA impose changed and additional requirements that could affect the expected timing, scope of work and its complexity, expected costs for labor and materials, removal and remediation techniques. See “Business—Environmental Matters” for additional information on these new rules. Future adjustments to the Talen Montana ARO estimates, as well as adjustments to other coal ash ARO estimates, may be required due to the ongoing remediation requirements under state obligations and federal rules, which could have an adverse effect on our business, financial condition and results of operations. If the assumptions underlying these ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different than estimated. Please see Note 9 in Notes to the Interim Financial Statements and Note 11 in Notes to the Annual Financial Statements for more information on AROs and Note 10 in Notes to the Interim Financial Statements for additional information on new EPA rules that may impact AROs.
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 of 1954, as amended, our operation and 90% ownership of Susquehanna are subject to regulation by the NRC, including requirements pertaining to: licensing, inspection and enforcement; testing, evaluation and modification of all aspects of nuclear reactor power generation facility design and operation; environmental and safety performance; technical and financial qualifications; decommissioning funding assurance; and transfer and foreign ownership restrictions. The current facility operating licenses for our two units at Susquehanna expire in 2042 and 2044.
The NRC could permanently or temporarily shut down Susquehanna, require it to modify its operations or refuse to permit restart of the unit after unplanned or planned outages. As a result of any shutdown or forced outage, we may face additional costs to the extent we are obligated to provide power from more expensive alternative sources to cover our then-existing forward sale obligations, as well as substantial costs related to the storage and disposal of radioactive materials and SNF. In addition, Susquehanna will be obligated to continue storing SNF if the U.S. DOE continues to fail to meet its contractual obligations under the U.S. Nuclear Waste Policy Act of 1982 to accept and dispose of Susquehanna’s SNF. NRC regulations also require us to demonstrate reasonable assurance that certain funds will be available to decommission each nuclear generation facility at the end of its life. There are uncertainties with respect to certain technological and financial aspects of decommissioning these facilities, and related costs may exceed the amounts available from the Susquehanna NDT funds.
New or amended NRC safety and regulatory requirements may give rise to additional operation and maintenance costs and capital expenditures. Additionally, aging equipment may require more capital expenditures to keep Susquehanna operating efficiently. Any unexpected failure, including failure associated with breakdowns or any unanticipated capital expenditures, could result in reduced profitability. Costs associated with these risks could be substantial and could have a material adverse effect on our business, financial condition or results of operations. See “—Commercial and Operational Risks—Our ownership and operation of Susquehanna, which contributes a majority of our earnings associated with electric generation, subjects us to substantial risks associated with nuclear generation.”
While Susquehanna maintains property and liability insurance for losses related to nuclear operations at Susquehanna and is subject to NRC insurance requirements and the Price-Anderson Act scheme, there may be limitations on the amounts and types of insurance commercially available, or we may have insufficient coverage with respect to any such losses. Uninsured losses and other liabilities and expenses resulting from an incident at Susquehanna, to the extent not recovered from insurers or the nuclear industry, could be borne by us. Additionally, an accident or other significant event at a nuclear facility within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. If an incident did occur at Susquehanna, any resulting operational loss, damages and injuries would likely have a material adverse effect on our results of operations, cash flows, financial condition and liquidity.
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Our costs to comply with state, federal and local statutes, rules and regulations relating to environmental protection and worker health and safety could be material and could cause the continued operation of certain of our generation facilities to be uneconomic.
Our business and facilities are subject to extensive federal, state and local statutes, rules and regulations relating to environmental protection and human health and safety, which have become more stringent over time. These laws and regulations impose numerous requirements, including requiring permits to conduct regulated activities, incurring costs to limit or prevent pollution or releases of regulated materials to the environment, imposing specific standards addressing worker protection and process safety, and imposing substantial liabilities and remedial obligations for pollution or contamination. If there is any delay in obtaining any environmental regulatory approvals necessary for our operations or capital projects, or failure to obtain, maintain or comply with any such approvals, operations at our affected facilities could be halted, reduced or subjected to additional costs. New or more stringent enforcement of existing laws or regulations could adversely affect our business, financial condition and results of operations.
As a result of various factors, including existing and recently revised rules and regulations, such as those pertaining to water, waste, air (including GHG regulations) and climate, we have spent, and expect to continue to spend, substantial amounts on measures regarding environmental control, compliance and remediation. See “Business—Environmental Matters” for additional information on new water, waste, air and climate rules recently finalized by the EPA. We anticipate that certain of these new EPA rules will be legally challenged; the outcome of our spend will depend on the success and timing of such challenges, which we cannot currently predict.
The EPA regulates GHG emissions from the power sector and certain states regulate carbon dioxide emissions from power generation facilities. The EPA recently finalized GHG standards for new and certain existing power plants. These regulations primarily affect higher-emitting units in the national power fleet, including our coal-fired generation facilities that have not set near-term retirement dates (e.g., Colstrip). More stringent limits on carbon dioxide and other GHG emissions and carbon taxes could be implemented or expanded at the state or regional levels. Recently, certain state legislatures have considered bills that could materially affect our ability to operate our coal-fueled generation facilities. Failure to comply with applicable laws, regulations and permits may result in liability for administrative, civil or criminal fines or penalties or in unforeseen costs or obligations, including requirements to install additional equipment or make substantial changes to our operations. In addition, private parties may also have the right to pursue legal actions to enforce compliance, as well as seek damages for non-compliance, with environmental laws, regulations and permits.
Our operations are subject to changes in applicable laws and regulations.
The conduct of our business is subject to various laws and regulations administered by federal, state and local governmental agencies. In addition, changes in state laws and regulations may be less predictable or could occur more rapidly, or have a more drastic effect, than changes at the federal level. Changes in laws and regulations occur frequently and sometimes dramatically, as a result of political, economic or social events or in response to significant events. For example, economic downturns, periods of high energy supply costs and other factors can lead to changes in, or the development of, legislative and regulatory policy designed to promote reductions in energy consumption, increased energy efficiency, renewable energy and self-generation by customers. Such a focus may result in a decline in electricity demand, which could in turn adversely affect our business. Any change in the legal and regulatory landscape (including the processes for obtaining or renewing permits, costs associated with providing healthcare benefits to employees, health and safety standards, accounting standards, taxation regulations and requirements and competition laws) may have a material adverse effect on our results of operations, competitive position or financial condition. See “Business—Environmental Matters” for additional information on new water, waste, air and climate rules recently finalized by the EPA.
Separately, the wholesale energy markets vary from region to region with distinct rules, practices and procedures. Changes in these market rules, problems with rule implementation and compliance or failure of any of these markets could have a material adverse effect on our business, results of operations, cash flows and financial condition. See “Business—Regulatory Matters” for additional information about ongoing market reforms.
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Extreme weather events have resulted, and in the future may result, in efforts by both federal and state government and regulatory entities to investigate and determine the causes of such events and may result in changes in applicable laws and regulations, mandatory reliability requirements, and market rules, including to reform PJM.
During Winter Storm Elliott, certain of our generation facilities failed to meet the Capacity Performance requirements set forth by PJM, while our remaining generation facilities met or exceeded their capacity obligations. As a result, we incurred certain Capacity Performance penalties charged by PJM for our under-performing facilities and earned bonus revenues from PJM for our over-performing generation facilities. Accordingly, Talen Energy Marketing recognized in 2022 and 2023 a net penalty charge, of approximately $51 million, net of expected bonus revenues. Talen Energy Marketing and its affiliates, along with other suppliers, subsequently filed complaints against PJM at FERC disputing a significant portion of the penalties assessed by PJM. In December 2023, FERC approved a market-wide settlement that resolved the disputes. As a result, Talen’s estimated aggregate penalties, net of expected bonus revenues, were reduced from $51 million to $28 million, but no assurance can be provided that these amounts will not vary based on the final market settlements or any other legal and (or) regulatory actions.
In the future, we are highly likely to face additional severe weather events, which are inherently unpredictable in nature, location, scope and timing, and which may give rise to investigations or other efforts to determine the causes or consequences of such events. Any such efforts may result in further changes to applicable laws and regulations, mandatory reliability requirements and market rules, which could affect our liquidity and results of operations, all of which are unpredictable at this time.
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 our operations in the ordinary course of operating our power generation facilities. These allowances are used to meet the obligations imposed on us by various applicable environmental laws. Given the historical correlation between rising natural gas prices and increasing prices for wholesale electricity, we may idle our units less as natural gas prices increase, resulting in an increase in emissions. If our operational needs require more than our allocated allowances, we may be forced to purchase such allowances on the open market, which could be costly. If we are unable to maintain sufficient emission allowances to match our operational needs, we may have to curtail our operations so as not to exceed our available emission allowances or install costly new emission controls. If such allowances are available for purchase, but only at significantly higher prices, the purchase of such allowances could materially increase our costs of operations in the affected markets.
Changes in tax law (including any elimination of the Nuclear PTC), the implementation regulations of certain tax provisions or adverse decisions by tax authorities may adversely affect our business and financial condition.
The laws and rules dealing with U.S. federal, state and local income taxation are routinely being reviewed and modified by governmental bodies, officials and regulatory agencies, including the Internal Revenue Service (“IRS”) and the U.S. Treasury Department. It cannot be predicted whether, when, in what form or with what effective dates, tax laws, regulations and rulings may be enacted, promulgated or issued, which could result in changes in the estimated values of recorded deferred tax assets and liabilities and future income tax assets and liabilities and an increase in our effective tax rate and tax liability. For example, the Inflation Reduction Act was signed into law in August 2022. Among the Inflation Reduction Act’s provisions are changes to the U.S. corporate income tax system, including a one percent excise tax on certain repurchases of stock (and economically similar transactions) after December 31, 2022. The Inflation Reduction Act also includes amendments to the Internal Revenue Code of 1986, as amended (the “Code”), to create a nuclear production tax credit program. While electricity produced and sold by Susquehanna through December 31, 2032 may qualify for the Nuclear PTC, which is subject to potential adjustments, these provisions are subject to implementation regulations, whose terms are not yet fully known. As such, we cannot fully predict the impacts that any such tax credits may have on our liquidity or results of operations. We are continuing to evaluate the Inflation Reduction Act and its requirements, as well as its application to us. Any elimination of the Nuclear PTC may adversely affect our business and financial condition.
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In addition, our tax reporting is subject to audit by tax authorities. We may enter into transactions and arrangements in the ordinary course of business in which the tax treatment is not entirely certain. We must therefore make estimates and judgments in determining our consolidated tax provisions and accruals. The final outcome of any audits by tax authorities may differ from estimates and assumptions used in determining our consolidated tax provisions and accruals, and the resolution of tax assessments or audits by tax authorities could impact operations. This could result in a material and adverse effect on our consolidated income tax provision, financial position and the net income/loss for the period for which such determinations are made.
Our ability to utilize our tax attributes, including net operating loss carryforwards, remaining following Emergence, if any, may be limited.
As of December 31, 2023, we had approximately $1.3 billion of U.S. federal net operating loss (“NOL”) carryforwards and approximately $1.4 billion of disallowed business interest expense carryforwards under Section 163(j) of the Code and certain other tax attributes (including significant tax basis in assets). However, we expect that, absent an election under Section 108(b)(5), we will be required to substantially reduce or eliminate certain of our tax attributes, including NOL carryforwards, as a result of cancellation of indebtedness income realized in connection with the Restructuring. We are still considering whether we will make a Section 108(b)(5) election to reduce fixed asset tax basis prior to any reduction in NOL carryforwards.
Because the consummation of the Plan of Reorganization resulted in an ownership change for purposes of Sections 382 and 383 of the Code, our ability to utilize any remaining tax attributes after reduction and disallowed business interest expense carryforwards is subject to limitation under Sections 382 and 383 of the Code. As a result, certain of our tax attributes have been substantially reduced, eliminated or otherwise restricted.
Our business may be affected by state interference in the competitive marketplaces.
Our generation and wholesale power sales business relies on a competitive marketplace. The competitive marketplace may be impacted by out-of-market subsidies provided by states or state entities, including bailouts of uneconomic nuclear facilities, imports of power from Canada, renewable mandates or subsidies, mandates to sell power below its cost of acquisition and associated costs, as well as out-of-market payments to new or existing generators. These out-of-market subsidies to existing or new generation undermine the competitive marketplace, which can lead to premature retirement of existing facilities, including those owned by us. If these measures continue, capacity and energy prices may be suppressed, and we may not be successful in our efforts to insulate our platform from this interference in the competitive market.
We are subject to litigation risks.
We are, and in the future may be, subject to litigation arising out of our operations. Damages claimed under such litigation may be material, and the outcome of such litigation may materially adversely impact our financial condition, cash flows, results of operations and liquidity. While we will assess the merits of any lawsuits and defend such lawsuits accordingly, we may be required to incur significant expense or devote significant financial resources to such defenses. In addition, the adverse publicity surrounding such claims may have a material adverse effect on our operations. Our insurance may not adequately cover losses for damages claimed against us, and we do not have insurance coverage for all litigation risks. Please see Note 10 in Notes to the Interim Financial Statements, Note 12 in Notes to the Annual Financial Statements, and “Business—Legal Matters” for more information regarding our litigation matters.
Financial and Liquidity Risks
Our ability to raise capital and access liquidity may be affected by increased focus on our fossil fuel-fired power generation business.
In recent years, shifting worldwide social and political views toward the environment, including uncertainty or instability resulting from climate change, changes in political leadership and environmental policies, changes in geopolitical-social views toward fossil fuels and concern about investors’ expectations regarding environmental matters, have necessitated changes in fossil fuel-related industries. Many institutional investors have recently
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adopted environmental investing guidelines that may prevent them from increasing or taking new stakes with companies with exposure to fossil fuels, including lending to energy companies that rely even in part on fossil fuels. Additional institutional investors may adopt similar investment guidelines in the future. Limitation of investments in, or financings for, companies with a fossil fuel-fired power generation business could adversely affect our ability to obtain equity or debt financing or otherwise raise capital, which could have a material adverse effect on our business, financial condition and results of operations.
No assurance can be given that we will have sufficient access to financing for our business.
Our primary liquidity requirements, in addition to our ordinary course operating expenses, are for servicing our debt and capital expenditures and, in certain cases, providing collateral for our hedging program. If our sources of liquidity are not sufficient to fund our current or future liquidity needs, we may be required to take other actions, including refinancing, restructuring or reorganizing all or a portion of our debt or capital structure, reducing or delaying capital investments or obtaining alternative financing. Our ability to obtain financing is subject to numerous factors that we may not be able to control, including conditions in the capital markets, our current operations, credit ratings and other events which we are not able to predict. Furthermore, any financing may be at a higher cost than we expect or have other security, collateral or other conditions or requirements. Additionally, applicable regulations may impose costly additional requirements on our business and the businesses of others with whom we contract or may increase costs to conduct our business or access sources of capital and liquidity. There can be no assurance that we will be able to obtain financing on commercially reasonable terms, or at all, or in a manner that would be permitted under the terms of our debt instruments or in a manner that does not negatively impact our business. Additionally, there can be no assurance that the above actions, if taken, would allow us to meet our debt obligations and operating requirements.
Our historical financial information may not be indicative of our future financial performance.
Our capital structure was significantly altered under the Plan of Reorganization. Upon Emergence, we adopted fresh-start accounting, which required us to adjust our assets and liabilities to fair value and restate our accumulated deficit to zero. In addition, we adopted accounting policy changes and such policies could result in material changes to our financial reporting and results. Accordingly, our financial condition and results of operations following the Restructuring are not comparable to the financial condition and results of operations reflected in our Annual Financial Statements.
Our indebtedness could adversely affect our financial condition and impair our ability to operate our business.
Our indebtedness, including the Indenture and the Credit Facilities, could have important consequences to our future financial condition, operating results and business, including the following:
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
limiting our ability to adjust to changing market and economic conditions and to carry out capital spending that is important to our growth.
Although the Credit Facilities, the Indenture and other existing indebtedness contain restrictions on the incurrence of additional indebtedness, these restrictions are subject to a number of qualifications and exceptions, and any additional indebtedness incurred in compliance with these restrictions could be substantial. See “—Risks Related to Ownership of Our Common Stock—TEC is a holding company; its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the agreements governing our indebtedness contain certain restrictions on distributions of cash to TEC.” and
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“Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources.”
Indebtedness subjects us to the risk of higher interest rates, which could cause our future debt service obligations to increase significantly.
Our borrowings under the Credit Facilities are at variable rates of interest and expose us to interest rate risk. If interest rates increase, our debt service obligations on such variable rate indebtedness would increase even though the amount borrowed remained the same, and our ability to make payments of principal and interest on the Secured Notes (as well as on loans with respect to the Credit Facilities) may be adversely impacted.
Our debt agreements contain various covenants that impose restrictions on TES and certain of its subsidiaries that may affect our ability to operate our business and to make payments on our indebtedness.
Our debt agreements, including the Indenture and the agreements governing the Credit Facilities, contain covenants that, among other things, limit the ability of TES and certain of its subsidiaries to, among other things:
incur additional debt;
create or incur liens upon any principal property to secure debt for borrowed money;
redeem and/or prepay certain debt;
pay dividends on our stock or repurchase stock;
make certain investments;
consolidate, merge, lease or transfer all or substantially all of our assets; and
in the case of the agreements governing our Credit Facilities, enter into transactions with affiliates.
These restrictions on our ability to operate our business could seriously harm our business by, among other things, limiting our ability to take advantage of financings, mergers, acquisitions and other corporate opportunities. Various risks, uncertainties and events beyond our control could affect our ability to comply with these covenants. Failure to comply with the covenants in our existing or future financing agreements could result in a default under those agreements and other agreements containing cross-default provisions. A default would permit lenders to accelerate the maturity for the debt under these agreements and to foreclose upon any collateral securing the debt. Under these circumstances, we might not have sufficient funds or other resources to satisfy all of our obligations. In addition, the limitations imposed by financing agreements on our ability to incur additional debt and to take other actions might significantly impair our ability to obtain other financing, which could adversely affect our financial condition and results of operations and could cause us to become bankrupt or insolvent.
Growth and Strategic Risks
Our project development activities through our Cumulus Affiliates may consume a significant portion of our management’s focus and resources, and if not completed or successful, reduce our profitability.
Our project development activities related to the Cumulus projects may consume a significant portion of our management’s focus, and if not completed or successful, reduce our profitability. TES currently provides corporate, administrative and operational services to the Cumulus Affiliates. As a result, the operations and activities of the Cumulus Affiliates may divert the attention and impact the availability of TES personnel. The Cumulus projects may also require us to spend significant sums for engineering, construction, permitting, legal, financial advisory and other expenses before we determine whether a development project is feasible, economically attractive or capable of being financed. In addition, the economic assumptions underlying one or more of the Cumulus projects may prove to be incorrect or materially different than projected, which may cause us to reevaluate pursuing or further investing in a particular project.
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Our Cumulus projects may be complex, which increases the chances that we may not be able to complete them. There can be no assurance that we will be able to negotiate the required agreements, overcome any local opposition or obtain the necessary approvals, licenses, permits and financing. Failure to achieve any of these elements may prevent the development and construction of a project. If that were to occur, we could lose all of our investment in development expenditures and may be required to write-off project development assets. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by noise.
Joint ventures, joint ownership arrangements and other projects pose unique challenges to our Cumulus projects, and we may not be able to fully implement or realize synergies, expected returns or other anticipated benefits associated with such projects.
Through certain Cumulus Affiliates, we are party to joint venture agreements with various third parties, including Pattern Energy and BQ Energy Development, LLC for potential solar and wind projects. Additionally, Cumulus Coin holds a 75% equity interest in Nautilus, with TeraWulf as our joint venture partner. Conflicts may arise with our joint venture or joint owner counterparties due to differing strategic or commercial objectives or disagreement on governance matters or whether a project merits continued investment. A deadlock in management decisions could cause us to sell our interest in the project or buy our joint venture partner’s interest. We may also be subject to the risk that our counterparties do not fund their obligations and to preserve the value of our investment, we may be required to expend additional internal resources that could otherwise be directed to other projects. Conversely, if we no longer desire to invest in a project, our counterparties may determine to cover our investment which may dilute our interests and lead to a loss of voting or other rights in the project. If we are unable to successfully execute and manage our existing and proposed joint venture and jointly owned projects, the anticipated benefits associated with such arrangements may not be achieved or could be delayed, which could adversely impact our financial and operating results. See “Certain Relationship and Related Party Transactions.”
Fluctuating costs and disruptions could impact construction and operation of renewable energy and digital infrastructure projects.
The capital expenditures and time required to develop new renewable and digital infrastructure projects are considerable and can increase due to a wide variety of factors, many of which are beyond our control. These include, but are not limited to, weather conditions, ground conditions, availability of construction material, availability and performance of contractors and suppliers, changes in cost or construction schedules, inflation, delivery and installation of equipment, design changes, accuracy of estimates, availability of accommodations for the workforce, change in laws or regulations and the ability to obtain necessary government approvals. In addition, the Cumulus Data Campus’s and Nautilus’s operations are and will be powered exclusively by electricity generated at Susquehanna. Any disruption or outage at Susquehanna affecting its ability to generate sufficient electricity for Cumulus Data operations (including submetered electricity to Nautilus) could have a material adverse effect on their respective businesses, financial condition and results of operations.
Our interest in and operation of a Bitcoin mining facility subjects us to certain risks.
While we expect to maintain our existing Bitcoin operations through our interest in Cumulus Coin, we do not currently plan to expand such operations or expect any material capital expenditures within the next twelve months. Nonetheless, our existing Bitcoin operations do expose us to certain risks. Almost all of Cumulus Coin’s expected revenue is from the sale of Bitcoin mined by Nautilus. Investing in Bitcoin is speculative, as it has historically experienced significant intraday and long-term price volatility. For example, during 2023, the per-coin price of Bitcoin reached a low of approximately $16,500 and a high of approximately $44,700. If the price of Bitcoin declines, Cumulus Coin’s profitability will decline, which would adversely affect the business, prospects, financial condition, and results of operation of Nautilus and Cumulus Coin.
Additionally, digital assets, including Bitcoin, are under increasing regulatory scrutiny, and the extent and content of any forthcoming laws and regulations are uncertain. New laws and increased regulation could result in new compliance-related costs for Cumulus Coin’s operations, result in regulation of Bitcoin under the securities
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laws or restrict or eliminate the Bitcoin market, which could negatively affect the value of Cumulus Coin’s operations and may result in expense or burdens to us.
Furthermore, cryptocurrency assets are generally controllable only by the possessor of the unique private key relating to the digital wallet in which such assets are held. To the extent that any of the private keys relating to wallets containing Bitcoin held by Nautilus are lost, destroyed, stolen or otherwise compromised or unavailable, Nautilus would be unable to access the Bitcoin held in the related wallet.
Moreover, as a reward for successfully solving cryptological blocks, Bitcoin miners are primarily compensated in newly issued Bitcoin. However, the Bitcoin reward paid to Bitcoin miners for successfully solved cryptological blocks is periodically reduced by half according to a pre-determined schedule. While Bitcoin prices may fluctuate around such reward reductions, there can be no guarantee that any price fluctuations associated with reward reductions will be favorable or would compensate for the reduction in reward, which may lead Bitcoin miners, such as Nautilus, to forgo Bitcoin mining, thus reducing the profitability of Nautilus’s and Cumulus Coin’s operations.
Acquisition or divestiture activities may have an adverse effect on us.
From time to time, we may seek to acquire additional assets or businesses. The acquisition of new assets or businesses is subject to substantial risks, including delays in completion or an inability to complete them at all, the failure to identify material problems during due diligence, the risk of over-paying, the ability to retain customers or employees of such acquired businesses and the inability to arrange required or desired financing for an acquisition. We may acquire assets or businesses in geographic regions or markets in which we do not currently operate or lines of business outside of our core focus, which may expose us to increased market or regulatory risks. There can be no assurances that any future acquired businesses will perform as expected or that the returns from such acquisitions will support any related financing incurred or the cash flows needed to operate them profitably.
In addition, we may from time to time choose to sell certain assets or businesses. The risks of such dispositions may relate to employment matters, counterparties, regulators and other stakeholders in the disposed business, separating the disposed assets from our other businesses, the management of our ongoing business, as well as risks unknown to us at the time and other financial, legal and operational risks related to such disposition. In connection with such dispositions, we may also indemnify or guarantee counterparties against certain liabilities, which may result in future costs or liabilities payable by us. Any such risk may result in one or more costly disputes or litigation. In addition, any disposition would decrease our Adjusted EBITDA, which could impact our ability to pay dividends or effect share repurchases under our debt agreements. The failure to realize the anticipated returns or benefits from an acquisition or disposition could adversely affect our business, financial condition and results of operations.
Risks Related to Ownership of Our Common Stock
No prior public trading market existed for our common stock prior to trading on the OTC Pink Market, and an active trading market may not develop or be sustained following the registration of our common stock on Nasdaq, which may cause the market price of our common stock to decline significantly and make it difficult for investors to sell their shares in the future.
There was no public market for our common stock prior to commencing trading on the OTC Pink Market on June 23, 2023 and subsequent commencement of trading on the OTCQX U.S. Market on July 24, 2023. We have been approved to list our common stock for trading on Nasdaq under the symbol “TLN.” However, listing on Nasdaq does not ensure that an active trading market for our common stock will develop or be sustained. Accordingly, no assurance can be given as to the likelihood that an active trading market for our common stock will develop or be sustained, the liquidity of any such market or the ability of our stockholders to sell their common stock at the price desired.
The stock markets, including Nasdaq, have from time to time experienced significant price and volume fluctuations. As a result, the market price of our common stock may be similarly volatile, and investors in shares of our common stock may from time to time experience a decrease in the market price of their shares, including decreases unrelated to our financial performance or prospects. The market price of shares of our common stock
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could be subject to wide fluctuations in response to a number of factors, including those listed in this “Risk Factors” section of this prospectus and others. No assurance can be given that the market price of our common stock will not fluctuate or decline significantly in the future or that our stockholders will be able to sell their shares when desired on favorable terms, or at all. From time to time in the past, securities class action litigation has been instituted against companies following periods of extreme volatility in their stock price. This type of litigation could result in substantial costs and divert our management’s attention and resources.
Sales of a substantial number of shares of our common stock by our existing stockholders, as well as any future issuances of equity or debt securities by us, may adversely affect the market price of our common stock, even if our business is doing well.
Sales of a substantial number of shares of our common stock in the public market or the perception in the market that the holders of a large number of shares intend to sell shares (particularly with respect to our affiliates, directors, executive officers or other insiders) could depress the market price of our common stock and could impair our future ability to obtain capital, especially through an offering of equity securities. If there are more shares of common stock offered for sale than buyers are willing to purchase, then the market price of our common stock may decline. In the future, we may issue additional shares to our employees, directors or consultants under our equity compensation plans, in connection with corporate alliances or acquisitions, or to raise capital. Due to these factors, sales of a substantial number of shares of our common stock in the public market could occur at any time.
In the future, we may attempt to obtain financing or to further increase our capital resources by issuing additional shares of our common stock or by offering debt or other equity securities. Any future debt financing could involve restrictive covenants relating to our capital-raising activities and other financial and operational matters, which might make it more difficult for us to obtain additional capital and to pursue business opportunities. Moreover, if we issue debt securities, the debt holders would have rights to make claims on our assets senior to the rights of our stockholders. The issuance of equity securities or securities convertible into equity may dilute our existing stockholders. Debt securities convertible into equity could be subject to adjustments in the conversion ratio pursuant to which certain events may increase the number of equity securities issuable upon conversion.
TEC is a holding company; its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the agreements governing our indebtedness contain certain restrictions on distributions of cash to TEC.
TEC is a holding company that does not (and does not intend to) conduct any business operations or incur material obligations of its own. While we do not expect TEC to incur obligations that it is unable meet due to contractual restrictions on distributions from subsidiaries, certain subsidiaries are subject to such limitations. However, TEC’s cash flows are largely dependent on the operating cash flows of TES and TEC’s other subsidiaries and the payment of such operating cash flows to TEC in the form of dividends, distributions, loans or otherwise. These subsidiaries are separate and distinct legal entities from TEC and have no obligation (other than any existing contractual obligations) to provide TEC with funds to satisfy its obligations. Any decision by a subsidiary to provide TEC with funds to satisfy its obligations, whether by dividends, distributions, loans or otherwise, will depend on, among other things, such subsidiary’s results of operations, financial condition, cash flows, cash requirements, contractual and other restrictions, applicable law and other factors. The deterioration of income from, or other available assets of, any such subsidiary for any reason could limit or impair its ability to pay dividends or make other distributions to TEC. Furthermore, the agreements governing the indebtedness of TES contain provisions restricting the ability of those entities to pay dividends or otherwise transfer assets to TEC.
The Indenture and Credit Facilities restrict the ability of TES to pay dividends or distributions to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or distributions: (1) in an amount not to exceed $160 million, (2) in an unlimited amount so long as TES’s pro forma consolidated total net leverage ratio is less than or equal to 1.5 to 1.0 (or, on and after the date the second quarter 2024 financials are due under the Credit Agreement, 2.0 to 1.0), and (3) in an amount not to exceed the sum of: (a) TES’s adjusted EBITDA minus 140% of TES’s consolidated interest expense, in each case, for the period beginning June 1, 2023 (subject to (i) in the case of the Credit Facilities, compliance with a pro forma consolidated total net leverage ratio of less than or equal to 2.75 to 1.0 (or, after the date the second quarter 2024 financials are due under the Credit Agreement, 3.25 to
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1.0) and (ii) in the case of the Indenture, the ability to incur $1 of additional ratio debt), (b) $150 million, (c) equity contributions to TES, and (d) other customary “builder basket” components. See “—Financial and Liquidity Risks—Our debt agreements contain various covenants that impose restrictions on TES and certain of its subsidiaries that may affect our ability to operate our business and to make payments on our indebtedness.”
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, capital requirements, market conditions, our growth strategy and the availability of growth opportunities, contractual restrictions (including restrictions on the payment of dividends imposed by the Credit Facilities and the Indenture), our level of indebtedness and other restrictions with respect to the payment of dividends, applicable law and other factors that the Board of Directors deems relevant.
A small number of stockholders could be able to significantly influence our business and affairs.
The three largest TEC stockholders collectively own approximately 38.2% of our outstanding common stock (the “Principal Stockholders”). Large holders such as the Principal Stockholders may be able to affect matters requiring approval by our stockholders, including the election of directors and the approval of mergers or other business combination transactions. See “Principal and Selling Stockholders.”
If securities analysts do not publish research or reports or if they publish unfavorable or inaccurate research about our business and common stock, the price of our common stock and the trading volume could decline.
We expect that the trading market for our common stock will be affected by research or reports that industry or financial analysts publish about us or our business. There are many large, well-established companies active in our industry and portions of the markets in which we compete, which may mean that we receive unfavorable or less widespread analyst coverage than our competitors. If one or more of the analysts who covers us downgrades their evaluations of us or our common stock or TES or its indebtedness, the price of our common stock could decline. If one or more of these analysts cease coverage of us, our common stock may lose visibility in the market, which in turn could cause the price of our common stock to decline.
Delaware law, as well as our organizational documents, contain anti-takeover provisions that could delay or prevent a change of control.
We are a Delaware corporation and the anti-takeover provisions of the Delaware General Corporation Law (the “DGCL”) may discourage, delay or prevent a change in control by prohibiting us from engaging in a business combination with an interested stockholder for a period of three years after the person becomes an interested stockholder, even if a change in control would be beneficial to our existing stockholders.
Additionally, the Third Amended and Restated Certificate of Incorporation of TEC (the “Charter”) and the Second Amended and Restated Bylaws of TEC (the “Bylaws”) contain provisions that could depress the market price of our common stock by acting to discourage, delay or prevent a change in control of TEC or changes in our management that stockholders may deem advantageous. These provisions in our Charter and Bylaws, among other things:
authorize the issuance of “blank check” preferred stock that the Board of Directors could issue to increase the number of outstanding shares to discourage a takeover attempt;
restrict transfers whereby, except for secondary market purchases (including secondary market purchases on Nasdaq), no person may purchase or otherwise acquire, and no stockholder of the Company may transfer to any person, shares of our common stock such that, after giving effect to such purchase, acquisition or other transfer, the holdings of the transferee, together with its “affiliates” (as such term is defined in 18 C.F.R. §35.36(a)(9)), directly or indirectly, would equal or exceed 10% of our outstanding voting securities, without the prior written consent of our Board of Directors;
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prohibit stockholder action by written consent unless a written consent is signed by holders of outstanding common stock having not less than the minimum voting power that would be necessary to authorize such action at a meeting at which all shares of outstanding common stock entitled to vote thereon were presented and voted;
permit the Board of Directors to establish the number of directors comprising the Board of Directors;
eliminate the ability of stockholders to fill vacancies on the Board of Directors;
provide that the Board of Directors is expressly authorized to make, amend or repeal our Bylaws;
establish advance notice requirements for nominations for elections to the Board of Directors or for proposing matters that can be acted upon by stockholders at stockholder meetings; and
designate the Court of Chancery of the State of Delaware as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our stockholders. See “Description of Capital Stock—Anti-Takeover Effects of Delaware Law and Our Charter and Bylaws.”
These provisions could make it more difficult for a third-party to acquire us, even if the third party’s offer may be considered beneficial by many of our stockholders. As a result, our stockholders may be limited in their ability to obtain a premium for their shares of common stock. These provisions could also discourage proxy contests and make it more difficult for you and other stockholders to elect directors of your choosing and to cause us to take other corporate actions you desire.
The requirements of being a public company may strain our resources, increase our costs and distract management, and, as a result, we may be unable to comply with these requirements in a timely or cost-effective manner.
As a public company, we will need to comply with new laws, regulations and requirements, certain corporate governance provisions of the Sarbanes-Oxley Act of 2002 (the “Sarbanes-Oxley Act”), related regulations of the SEC and the requirements of Nasdaq, with which we were not required to comply as a private company. Complying with these statutes, regulations and requirements will occupy a significant amount of our time and may strain our resources, increase our costs and distract management, which may inhibit our ability to comply with these requirements in a timely or cost-effective manner.
The standards required for a public company under Section 404(a) of the Sarbanes-Oxley Act are significantly more stringent than those required as a private company. While we generally must comply with Section 404 of the Sarbanes-Oxley Act, we may not be required to have our independent registered public accounting firm attest to the effectiveness of our internal controls until as late as our first annual report following the first entire fiscal year in which we are subject to reporting requirements of the Exchange Act. At any time, we may conclude that our internal controls, once tested, are not operating as designed or that the system of internal controls does not address all relevant financial statement risks. Once required to attest to control effectiveness, our independent registered public accounting firm may issue a report that concludes it does not believe our internal controls over financial reporting are effective. Moreover, management may not be able to effectively and timely implement controls and procedures that adequately respond to the increased regulatory compliance and reporting requirements that will become applicable after the consummation of this offering. If we identify material weaknesses in the future or otherwise fail to implement or maintain effective internal controls over financial reporting, we may not be able to accurately or timely report our financial condition or results of operations, which may subject us to adverse regulatory consequences, adversely affect our business and harm investor confidence and the market price of our common stock.
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS
This prospectus contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would” or similar expressions. Although we believe that the expectations and assumptions reflected in these statements are reasonable, there can be no assurance that these expectations will prove to be correct. Forward-looking statements are subject to many risks and uncertainties, and actual results may differ materially from the results discussed in forward-looking statements.
Such risks and uncertainties include, but are not limited to:
our ability to comply with the covenants under the agreements governing our indebtedness;
the limitations our level of indebtedness may place on our financial flexibility;
our inability to access the capital markets on favorable terms or at all;
the availability of cash flows from operations and other funds to finance reserve replacement costs or satisfy our debt obligations;
risks related to future changes in the market price of electricity, natural gas and other commodities;
risks related to weather and the demand for electricity;
declines in wholesale electricity prices or decreases in demand for electricity due to macroeconomic factors;
risks related to competition in the competitive power generation market;
adverse developments or losses from pending or future litigation and regulatory proceedings;
risks related to regulation and compliance with government permits and approvals;
risks related to environmental regulation of our fossil fuel and coal-fired power generation businesses and uncertainty surrounding the associated environmental liabilities and asset retirement obligations;
risks related to potential changes to environmental regulatory requirements related to coal-combustion byproducts, the operation and remediation of coal ash ponds and other regulatory oversight to our operations;
risks related to armed conflicts, war, terrorist attacks or threats and other significant events, including cyber-based attacks;
risk related to our reliance on the operations and financial results of Susquehanna to fund our other operations and satisfy our liquidity and other financial requirements;
risks related to the impact of our operations on the environment, including the risk of exposure to hazardous substances;
risks associated with Susquehanna, including risks relating to: (i) the operation of, and unscheduled outages at, the facility; (ii) the availability and cost of nuclear fuel and fuel-related components; (iii) increased nuclear industry security, safety and regulatory requirements; and (iv) the substantial uncertainty regarding the storage and disposal of SNF;
risks related to the continuation of capacity auctions in the PJM RTO, or changes to the capacity auction rules and procedures;
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credit risk and potential concentrations of credit risk resulting from market counterparties, financial institutions, customers and other parties;
risks related to pandemics, epidemics, outbreaks or other public health events that are outside of our control, and could significantly disrupt our operations and adversely affect our financial condition;
risks related to potential disruptions in the supply of fuel and other products necessary for the operation of our generation facilities;
unplanned outages or periods of reduced output at our generation facilities;
effects of transmission congestion, including due to line maintenance outages, on the realized margins of our generation fleet;
risks associated with the collection of shared expenses from co-owners of jointly owned facilities;
the expiration or termination of hedging contracts;
risks related to our ability to retain and attract a qualified workforce;
operational, price and credit risks associated with selling and marketing products in the wholesale power markets, including uncertainty around unknown future changes in market constructs, market responses (such as penalties) to extraordinary events and potential negative financial impacts (such as short payments) stemming from shortfalls of other market participants;
market and liquidity risks arising from our purchase and sale of power, capacity and related products, fuel, transmission services and emission allowances;
risks related to our generation facilities being part of interconnected regional grids, including the risk of a blackout due to a disruption on a neighboring interconnected system;
cyber-based security and related integrity risks;
the impacts of climate change, including related changes in legislation, regulation, market rules or enforcement;
risks related to any change in the structure and operation of, or the various pricing limitations imposed by, the RTOs and ISOs in regions where our generation is located;
the availability and cost of emission allowances;
risks related to our ability to fund and otherwise successfully execute on our energy transition plans, including development of our renewable energy and battery storage projects, our ability to supply power to our digital infrastructure growth projects, and our efforts to repower facilities to run on alternate fuel sources, and the risk that our plans may not achieve its desired results;
operational risks relating to the Nautilus facility, including the risk of interruptions to the provision of power, as well as cyber or other breaches of its infrastructure;
risks relating to cryptocurrency mining, including price volatility of digital assets, increasing scrutiny from investors, lenders and other stakeholders and the likelihood of increased regulation of digital assets; and
other risks identified in this prospectus.
We caution you that the foregoing list may not contain all forward-looking statements made in this prospectus.
You should not rely on forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this prospectus primarily on our current expectations and projections about future events and trends that we believe may affect our business, financial condition and results of operations. The outcome
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of the events described in these forward-looking statements is subject to risks, uncertainties and other factors described in the section titled “Risk Factors” and elsewhere in this prospectus. 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 prospectus. The results, events and circumstances reflected in the forward-looking statements may not be achieved or occur, and actual results, events or circumstances could differ materially from those described in the forward-looking statements.
In addition, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based on information available to us as of the date of this prospectus. While we believe such information provides a reasonable basis for these statements, such information may be limited or incomplete. Our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely on these statements.
The forward-looking statements made in this prospectus relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this prospectus to reflect events or circumstances after the date of this prospectus or to reflect new information, actual results, revised expectations or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions or expectations disclosed in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments.
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USE OF PROCEEDS
This prospectus relates to shares of our common stock that may be offered for resale by the Selling Stockholders, who may, or may not, elect to sell shares of our common stock covered by this prospectus. To the extent any Selling Stockholder chooses to sell shares of our common stock covered by this prospectus, we will not receive any proceeds from any such resales of our common stock, but we have agreed to pay certain registration expenses. The net proceeds from any resale of such shares will be received by the applicable Selling Stockholders. See the section titled “Principal and Selling Stockholders.”
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MARKET PRICES AND DIVIDEND POLICY
Our common stock was quoted on the OTC Pink Market under the symbol “TLNE” from June 23, 2023 to July 23, 2023 and is currently quoted on the OTCQX U.S. Market under the symbol “TLNE,” where it has been traded since July 24, 2023. No established trading market existed for our common stock prior to June 23, 2023. The following table sets forth the per share high and low closing prices for our common stock as reported on the OTCQX U.S. Market for the periods presented.
Per Share Sale Price
HighLow
OTC Pink Market
Second Quarter 2023 (for the period from June 23, 2023 through June 30, 2023)$52.50 $46.40 
Third Quarter 2023 (for the period from July 1, 2023 through July 23, 2023)$52.50 $49.50 
OTCQX U.S. Market
Third Quarter 2023 (for the period from July 24, 2023 through September 30, 2023)$55.25 $51.50 
Fourth Quarter 2023$64.00 $51.75 
First Quarter 2024$94.35 $62.26 
Second Quarter 2024 $120.00 $92.60 
Third Quarter 2024 (for the period from July 1, 2024 through July 8, 2024)$118.99 $116.00 
On July 8, 2024, the closing price of our common stock as reported on the OTCQX U.S. Market was $118.99 per share. As of July 8, 2024, there were three stockholders of record of our common stock, not including beneficial owners of shares registered in nominee or street name.
We have been approved to list our common stock for trading on Nasdaq, under the symbol “TLN.”
Dividends and Dividend Policy
The holders of shares of common stock are entitled to receive such dividends and other distributions (payable in cash, property or capital stock of the Company) when, as and if declared thereon by the Board of Directors from time to time out of any assets or funds of the Company legally available for the payment of dividends and shall share equally on a per share basis in such dividends and distributions.
Any future determination regarding the declaration and payment of dividends, if any, will be at the discretion of our Board of Directors and will depend on then-existing conditions, including our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors our Board of Directors may deem relevant. In addition, our ability to pay dividends may be restricted by agreements governing TES’s indebtedness and other agreements we may enter into in the future.
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CAPITALIZATION
The following table sets forth our cash and cash equivalents and capitalization as of March 31, 2024. You should read the information set forth below together with our consolidated financial statements and the related notes contained elsewhere in this prospectus.
(Millions of Dollars, except share data)March 31, 2024
Cash and cash equivalents
$597 
Debt:
Revolving credit facilities— 
Long-term debt2,619 
Total debt2,619 
Stockholders’ equity:
Common stock, $0.001 par value, 350,000,000 shares authorized; 59,028,843 shares issued and 58,535,843 shares outstanding
— 
Treasury stock, 493,000 shares(39)
Additional paid-in capital
2,339 
Accumulated retained earnings
428 
Accumulated other comprehensive income (loss)
(27)
Total stockholders’ equity
2,701 
Noncontrolling interests65 
Total equity2,766 
Total capitalization$5,385 
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UNAUDITED PRO FORMA CONDENSED CONSOLIDATED FINANCIAL INFORMATION
Introduction
The following unaudited pro forma financial information (the “Unaudited Pro Forma Financial Information”) consists of the Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2023. The Unaudited Pro Forma Financial Information was prepared as if the Plan of Reorganization had become effective and fresh start accounting occurred on January 1, 2023. An unaudited pro forma condensed consolidated balance sheet has not been presented, as the Plan of Reorganization and fresh start accounting adjustments have already been fully reflected in the Consolidated Balance Sheet as of December 31, 2023. The unaudited pro forma condensed consolidated statements of operations give effect to (i) various transactions effected pursuant to the Plan of Reorganization and (ii) the application of fresh start accounting.
The Unaudited Pro Forma Financial Information was derived from and should be read in conjunction with the Talen Energy Corporation and Subsidiaries Consolidated Statements of Operations for the Period from January 1, 2023 through May 17, 2023 (Predecessor) and for the Period from May 18, 2023 through December 31, 2023 (Successor).
The Unaudited Pro Forma Financial Information has been prepared in accordance with Article 11 of Regulation S-X, as amended by the final rule, Release No. 33-10786, “Amendments to Financial Disclosures about Acquired and Disposed Businesses.” The Unaudited Pro Forma Financial Information is presented for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan of Reorganization and the application of fresh start accounting had been consummated or applied, as applicable, on the dates indicated, nor is it necessarily indicative of our results of operations in the future.
Plan of Reorganization
The Plan of Reorganization implemented, among other things, the transactions contemplated by the RSA and the related settlements. Pursuant to the Plan of Reorganization, among other things:
Claims against TEC were paid in full in cash or reinstated. All prepetition equity interests in TEC were extinguished, and new equity interests in TEC were issued as follows:
Holders of claims under TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds received (i) 99% of the TEC common stock (subject to dilution), less the Retail PPA Incentive Equity issued to Riverstone at Emergence, and (ii) subscription rights to purchase additional shares of TEC common stock in the Rights Offering (or, in the case of certain ineligible holders, cash in lieu thereof).
Riverstone received (i) 1.00% of the TEC common stock (after giving effect to the Rights Offering and payment of the remaining Backstop Premium), (ii) the Retail PPA Incentive Equity and (iii) warrants to purchase additional shares of TEC common stock.
The remaining portion of the Backstop Premium was paid to the Backstop Parties in the form of TEC common stock.
The Rights Offering was consummated, which resulted in net cash proceeds of approximately $1.4 billion. Approximately 92% of claims under TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds were tendered in the Rights Offering, and the Backstop Parties were required to purchase the remainder of the unsubscribed for shares of TEC common stock attributable to the remaining claims under the Prepetition Unsecured Notes and PEDFA 2009A Bonds.
All intercompany equity interests among the Debtors were reinstated so as to maintain the pre-existing organizational structure of the Debtors. Intercompany claims among the Debtors were cancelled, released, discharged and extinguished.
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The Exit Financings were consummated, comprised of: (i) the RCF, a $700 million revolving credit facility, including letter of credit commitments of $475 million, (ii) the TLB of $580 million (and subsequently increased to $870 million in August 2023), (iii) the TLC of $470 million (the proceeds of which were used to cash collateralize LCs under the TLC LCF), (iv) the TLC LCF, which provides commitments for up to $470 million in LCs (cash collateralized with the proceeds of the TLC), (v) the Bilateral LCF, which provides commitments for up to $75 million in LCs, and (vi) $1.2 billion of Secured Notes.
The proceeds of the Rights Offering and the Exit Financings, together with cash on hand, were used to fully repay the DIP Facilities and to pay other claims in cash as follows:
Holders of claims under the Prepetition CAF received their pro rata share of approximately $1.0 billion, as agreed in the relevant settlement;
Holders of prepetition first lien secured claims (other than those under the Prepetition CAF) received their pro rata share of approximately $2.1 billion, as agreed in the relevant settlement; and
Holders of Other Secured Claims (as defined in the Plan of Reorganization) received the unpaid portion of their allowed claims.
Each holder of a General Unsecured Claim (as defined in the Plan of Reorganization) received its pro rata share of interests in a $26 million pool of cash set aside for general unsecured creditors (the “GUC Trust”). To the extent any proceeds were recovered by the Debtors pursuant to the PPL/Talen Montana litigation, 10% of the net proceeds recovered were be contributed to the GUC Trust, subject to a cap of $11 million. Talen Montana contributed $11 million to the GUC Trust in December 2023 following the settlement of the PPL/Talen Montana litigation. See Note 12 in Notes to the Annual Financial Statements for additional information on the PPL/Talen Montana litigation and the related settlement.
As a result of Emergence, the combination of TES and TEC was accounted for as a reverse acquisition under GAAP, in accordance with ASC 805, Business Combinations. As such, TEC was treated as the accounting acquiree and TES as the accounting acquirer for financial reporting purposes. In accordance with guidance applicable to these circumstances, the combination of TEC and TES was in substance a share exchange in which the TES creditors became the controlling shareholders of TEC. As a result of TES being the accounting acquirer, the historical operations of TES are deemed to be those of TEC. As TEC was primarily a holding company with no operations, the accounting for the reverse acquisition of TEC had no material impact on the financial statements, and as a result, no pro forma adjustments are required.
Fresh Start Accounting
Upon emergence from the Restructuring, TES adopted fresh start accounting, which resulted in TEC becoming a new entity for financial reporting purposes. As a result of fresh start accounting, TEC’s reorganization value was allocated to its individual assets and liabilities based on its fair values (except for deferred income taxes) in conformity with applicable guidance for business combinations. Deferred income tax amounts were determined in accordance with accounting guidance for income taxes. The estimated fresh start accounting adjustments give effect to the application of fresh start accounting to the unaudited condensed consolidated statement of operations assuming Emergence occurred on January 1, 2023.
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Unaudited Pro Forma Condensed Consolidated Statement of Operations
for the Year Ended December 31, 2023
 Successor Historical  Predecessor Historical  Transaction Accounting Adjustments
(Millions of Dollars, except share data)
 May 18, 2023 through December 31, 2023
 January 1 through May 17, 2023  Reorganization Adjustments  Fresh Start Adjustments  Pro Forma
Capacity revenues$133 $108 $— $— $241 
Energy and other revenues1,156 1,042 — — 2,198 
Unrealized gain (loss) on derivative instruments55 60 — — 115 
Operating Revenues
1,344 1,210   2,554 
Energy Expenses
Fuel and energy purchases(424)(176)— — (600)
Nuclear fuel amortization(108)(33)— (16)(d)(157)
Unrealized gain (loss) on derivative instruments(3)(123)— — (126)
Total Energy Expenses
(535)(332) (16)(883)
Operating Expenses
Operation, maintenance and development(358)(285)— — (643)
General and administrative(93)(51)— — (144)
Depreciation, amortization and accretion(165)(200)— 49 (e)(316)
Impairments(3)(381)— — (384)
Other operating income (expense), net(30)(37)— — (67)
Operating Income (Loss)
160 (76) 33 117 
Nuclear decommissioning trust funds gain (loss), net108 57 — — 165 
Interest expense and other finance charges(176)(163)66  (a) — (273)
Reorganization income (expense), net— 799 (1,259) (b) 460 (b)— 
Other non-operating income (expense), net102 60 — — 162 
Income (Loss) Before Income Taxes
194 677 (1,193)493 171 
Income tax benefit (expense)(51)(212)192 (c)(15) (c) (86)
Net Income (Loss)
143 465 (1,001)478 85 
Less: Net income (loss) attributable to noncontrolling interest(14)— — (5)
Net Income (Loss) Attributable to Stockholders
$134 $479 $(1,001)$478 $90 
Earnings Per Common Share
Net Income (Loss) Attributable to Stockholders - Basic$2.27 $1.52 
Net Income (Loss) Attributable to Stockholders - Diluted2.26 1.52 
Weighted-Average Number of Common Shares Outstanding - Basic (in thousands)59,029 59,029 
Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands)59,399 59,399 
The accompanying Notes to the Unaudited Pro Forma Financial Information are an integral part of the financial statements.
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Notes to the Unaudited Pro Forma Financial Information
Note 1. Basis of Presentation
The unaudited Pro Forma Condensed Consolidated Statement of Operations sets forth the combined results of operations of: (i) Talen Energy Supply, LLC (“TES” or the “Predecessor”) for the period from January 1 through May 17, 2023 (Predecessor), (ii) Talen Energy Corporation (“TEC” or the “Successor”) for the period, from May 18 through December 31, 2023 (Successor), and (iii) pro forma impacts to the Successor after giving effect to Plan of Reorganization and the application of fresh start accounting as if the Plan of Reorganization and application of fresh start accounting had occurred on January 1, 2023.
The Unaudited Pro Forma Financial Information has been prepared in accordance with Article 11 of Regulation S-X and is provided to give effect to: (i) various transactions effected pursuant to the Plan of Reorganization, including the incurrence by TES of indebtedness and the issuance of new TEC equity at Emergence; and (ii) the application of fresh start accounting. The Unaudited Pro Forma Financial Information is presented for illustrative purposes only and is not necessarily indicative of the financial results that would have occurred if the Plan of Reorganization and the application of fresh start accounting had been consummated or applied, as applicable, on the dates indicated, nor is it necessarily indicative of our results of operations in the future.
Note 2. Plan of Reorganization and Fresh Start Adjustments
(a)Reflects the adjustment to interest expense to eliminate interest expense, associated fees, and financing costs related to prepetition debt and the Talen Commodity Accordion RCF. The pro forma interest expense reflects interest, bank fees, and LC fees. A one-eighth percent change in the interest rates on the outstanding variable rate borrowings would result in an approximate change of $1 million in interest expense for the year ended December 31, 2023.
(b)Represents the reversal of Chapter 11 reorganization items, which consist of an aggregate fresh start adjustment of $460 million related to losses on revaluation adjustments for the year ended December 31, 2023, and the following reorganization adjustments for the year ended December 31, 2023:
(Millions of Dollars)Year ended December 31, 2023
Gain on debt discharge$1,459 
Backstop Premium(70)
Professional fees(56)
Make-whole premiums and accrued interest on certain indebtedness(21)
Professional fees incurred to obtain the DIP Facilities— 
Write-off of deferred financing cost and original issue discount(46)
Gains (losses) on contract terminations— 
Other(7)
Pro Forma Reorganization Adjustments
$1,259 
(c)Represents the adjustments to income tax benefit (expense) related to the Income (Loss) Before Income Taxes resulting from the pro forma other adjustments. Adjustments are tax effected using an estimated statutory blended rate of 21% with the exception of the reorganization adjustments, which are based on actual income tax benefit (expense).
(d)Represents the adjustment to nuclear fuel amortization related to the increase in fair value of the nuclear fuel contract intangibles. The adjustment for the year ended December 31, 2023 also takes into consideration the Successor amortization that was reported during the period.
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(e)Represents the difference in depreciation, amortization, and accretion to account for the fair value adjustments to property, plant and equipment and asset retirement obligations. Below is the depreciation, amortization, and accretion expense for the year ended December 31, 2023:
(Millions of Dollars)Year ended December 31, 2023
Depreciation expense$(266)
Amortization expense(5)
Accretion expense(45)
Pro forma depreciation, amortization and accretion expense
(316)
Historical depreciation, amortization and accretion expense - Successor(165)
Historical depreciation, amortization and accretion expense - Predecessor(200)
Net (increase) / decrease in depreciation, amortization and accretion expense
$49 
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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 should be read in conjunction with information contained in “Business,” “Risk Factors,” the Interim Financial Statements, the Annual Financial Statements, and their accompanying notes. In addition, the following discussion contains forward-looking statements, which involve risks and uncertainties. See “Cautionary Note Regarding Forward-Looking Statements” for additional information on forward-looking statements. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
Overview
Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity, and ancillary services into wholesale power markets in the United States primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic and Montana. The majority of our generation is produced at zero-carbon nuclear and lower-carbon gas-fired facilities. Consistent with our risk management initiatives, we may execute physical and financial commodity transactions involving power, natural gas, nuclear fuel, oil and coal to economically hedge and optimize our generation fleet.
See “Business—Our Properties” for additional information on our generation portfolio. See “—Recent Developments—ERCOT Sale” below for information on the recent sale of our generation assets in Texas.
Recent Developments
Share Repurchase Program
In October 2023, the Board of Directors approved a share repurchase program initially authorizing the Company to repurchase up to $300 million of the Company’s outstanding common stock through December 31, 2025. In May 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion through the end of 2025. Repurchases may be made from time to time, at the Company’s discretion, in open market transactions at prevailing market prices, negotiated transactions, or other means in accordance with federal securities laws, and may be repurchased pursuant to a Rule 10b5-1 trading plan. The Company intends to fund repurchases from cash on hand. Repurchases by the Company will be subject to a number of factors, including the market price of the Company’s common stock, alternative uses of capital, general market and economic conditions, and applicable legal requirements, and the repurchase program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. The Company has no obligation to repurchase any amount of its common stock under the repurchase program. As of March 31, 2024, 493,000 shares of the Company’s common stock have been purchased under the share repurchase program for $39 million, inclusive of transaction costs. See Note 16 in Notes to the Annual Financial Statements for additional information. On July 1, 2024, the Company purchased an additional 5,027 shares under the share repurchase program for approximately $550,000.
In May 2024, the Company commenced the Tender Offer to purchase shares of the Company’s common stock for cash. The Tender Offer resulted in the purchase for cash of 5,275,862 shares of its common stock, representing 9.0% of the Company’s outstanding common stock, at a clearing price per share of $116.00, or an aggregate of $612 million.
On July 1, 2024, we entered into a purchase agreement with Rubric pursuant to which Rubric agreed to sell, and we agreed to repurchase from Rubric, 2,413,793 Shares at $116.00 per share of the Company’s common stock for an aggregate purchase price of $280 million pursuant to the Rubric Share Repurchase.
Remarketing of PEDFA Bonds
In June 2024, the Company completed a remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $80.6 million in aggregate principal amount of its PEDFA 2009C Bonds.
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The PEDFA 2009B and PEDFA 2009C Bonds will now bear interest at 5.25% until the end of the new term rate period on June 1, 2027. In connection with the remarketing, the approximately $133 million of letters of credit that had previously backstopped the PEDFA 2009B and PEDFA 2009C Bonds will be terminated, providing the Company with increased capacity on its TLC.
Mandatory Share Exchange
In May 2024, each outstanding restricted share of the Company’s common stock issued with or under CUSIP No. 87422Q208 was exchanged for an unrestricted share of the Company’s common stock issued with or under CUSIP No. 87422Q109. The exchange was intended to provide stockholders with increased liquidity, permitting the previously restricted shares to now trade without restriction, subject to each holder’s compliance with (i) securities laws and (ii) rules promulgated by the OTCQX U.S. Market or Nasdaq, as applicable.
Term Loan Repricing
In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale, and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement. See Note 11 in Notes to the Interim Financial Statements for additional information on Talen’s indebtedness.
ERCOT Sale
In May 2024, the Company closed the previously announced sale of its approximately 1.7 GW generation portfolio located in the South Zone of the ERCOT market to CPS Energy for $785 million of gross proceeds (approximately $723 million in net proceeds after customary working capital adjustments and estimated taxes, transaction fees and other costs). These assets included the 897 MW Barney Davis and 635 MW Nueces Bay natural gas-fired generation facilities, both located in Corpus Christi, Texas, as well as the 178 MW natural gas-fired generation facility in Laredo, Texas. See Note 17 in Notes to the Interim Financial Statements for additional information.
Cumulus Digital Buyouts
In March 2024, TES acquired all of the equity units of Cumulus Digital Holdings held by affiliates of Orion and two former members of Talen senior management in exchange for $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital Holdings. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts” for additional information.
Cumulus Data Campus Sale
In March 2024, AWS purchased substantially all the assets of Cumulus Data for gross proceeds of $650 million, with $350 million delivered to the Company at closing and the remaining $300 million of consideration held in escrow. The first $200 million of escrowed proceeds will be released upon a zoning amendment approval or ordinance allowing construction and operation of data center facilities on the property sufficient to consume an aggregate of at least 540 MW of energy, with the remaining $100 million released upon similar zoning amendment approval sufficient to allow aggregate consumption of at least 960 MW. If the 540 MW zoning amendment approval is not granted prior to March 1, 2025 (subject to certain limited extensions), then AWS has the option either to (i) retain the property and release all escrowed funds to the Company or (ii) revert all escrowed funds to AWS and allow the Company a one-time right to repurchase the property for $355 million. If the 540 MW zoning condition is met but the 960 MW zoning amendment approval is not granted prior to March 1, 2028, the remaining $100 million of escrowed funds will revert to AWS. The zoning amendment was approved by the applicable township on May 28, 2024 for the 960 MW. After a required 30 day public comment period, it is expected the zoning amendment will be approved and that the remaining $300 million of consideration will be released to the Company.
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In connection with the Cumulus Data Campus Sale, the Company executed the Cumulus Data Campus PPA with AWS, pursuant to which the Company agreed to supply long-term, carbon-free power from Susquehanna to the Cumulus Data Campus through fixed-price power commitments. Under the Cumulus Data Campus PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-applicable PJM energy and capacity prices. The initial term of the Cumulus Data Campus PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, Talen will receive additional revenue from AWS related to the sales of CFE to the grid. For additional information about the Cumulus Data Campus PPA, see “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale” and Note 17 in Notes to the Interim Financial Statements.
PJM, PPL, and Susquehanna have entered into the Amended ISA allowing Susquehanna to increase the amount of “behind-the-meter” power that it can provide to directly connected load under the current ISA. In June 2024, certain intervenors filed with FERC a protest to the Amended ISA. Talen does not currently expect this proceeding to have material impacts on the AWS transaction. For additional information, see “Business—Regulatory Matters—Susquehanna ISA Amendment.”
Cumulus Digital TLF Repayment
In connection with the Cumulus Data Campus Sale, the Company terminated the Cumulus Digital TLF and the outstanding obligations thereunder were satisfied and discharged in full. The security interests granted under the Cumulus Digital TLF were terminated, discharged and released. See Note 11 in Notes to the Interim Financial Statements and Note 13 in Notes to the Annual Financial Statements for additional information.
PPL/Talen Montana Litigation Settlement
In December 2023, Talen reached a litigation settlement with PPL. Under the terms of the settlement agreement, PPL paid TEC’s indirect subsidiary, Talen Montana, $115 million in cash in exchange for a full release of Talen Montana’s claims against PPL. Separately, Talen Montana remitted $11 million of the PPL settlement proceeds to the general unsecured creditors trust that was established pursuant to the Plan of Reorganization. See “Business—Legal Matters—Resolved Legal Matters—PPL/Talen Montana Litigation” and Note 12 in Notes to the Annual Financial Statements for additional information.
Riverstone Repurchase
In September 2023, TEC paid Riverstone $40 million in exchange for the cancellation of all of its TEC common stock warrants and a tax indemnity agreement, as well as waiving its future rights to the Retail PPA Incentive Equity. Also, in September 2023, TES and Orion purchased all of the equity units of Cumulus Digital Holdings held by Riverstone for an aggregate purchase price of $20 million, of which TES paid $19 million. See “Certain Relationships and Related Party Transactions—Cumulus Investments—Cumulus Digital Holdings; Buyouts,” “Certain Relationships and Related Party Transactions—Riverstone Warrant Cancellation” and Note 16 in Notes to the Annual Financial Statements for additional information.
Emergence from Restructuring
In May 2022, Talen commenced a reorganization under Chapter 11 of the Bankruptcy Code to allow the Debtors to, among other things, strengthen their financial position and provide additional liquidity to fund their operations and protect their investments in certain energy transition projects.
The Plan of Reorganization became effective in May 2023. At Emergence, TES adopted “fresh start” accounting, which required our assets and liabilities to be remeasured at fair value. Such measurement affected the carrying value of our assets and liabilities, and by extension, the comparability of our financial statements between periods.
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Through consummation of the Exit Financings and the Plan of Reorganization, we achieved a significant reduction in debt and interest, provided for full repayment of TES’s Prepetition Secured Indebtedness and completed the consensual equitization of all of TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds.
Upon Emergence, the Successor experienced an ownership change under Section 382 of the Internal Revenue Code. The Internal Revenue Code Sections 382 and 383 impose limitations on the ability of a company to utilize tax attributes after experiencing an ownership change. As a result, we have estimated our annual base limitation is approximately $72 million against the utilization of our loss carryforwards and other tax attributes. The Company can increase its annual Section 382 base limitation for the amount of recognized built-in gain (“RBIG”) pursuant to the application of Notice 2003-65. The additional deemed RBIG is approximately $859 million over a 5-year recognition period. States generally have similar tax attribute limitation rules following an ownership change.
See Notes 2, 3 and 4 in Notes to the Annual Financial Statements for additional information regarding the Restructuring. See “—Liquidity and Capital Resources” for additional information on the Exit Financings and Note 13 in Notes to the Annual Financial Statements for additional information on Talen’s indebtedness.
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 Statements,” “Risk Factors,” Notes 3 and 10 in Notes to the Interim Financial Statements, and Notes 5 and 12 in Notes to the Annual Financial Statements for additional information on our risks.
We completed the ERCOT Sale in May 2024. As a result, we have updated certain operational data presented in this prospectus to give effect to the ERCOT Sale. Our financial statements, segment information and related financial data as of and for the periods ending on or prior to March 31, 2024 include the results of operations from the ERCOT fleet. We intend to reevaluate our segment information for the first financial period after the ERCOT Sale, which is the quarter ending June 30, 2024.
Generation Facility Updates
H.A. Wagner Deactivation and Reliability Impact Assessment. In October 2023, for economic reasons, the Company provided a notice to PJM that it intends to deactivate H.A. Wagner as of June 1, 2025. The coal-to-fuel oil conversion of H.A. Wagner Unit 3 was completed in December 2023 and will allow the generation facility to serve as a capacity resource until its deactivation. In January 2024, PJM notified H.A Wagner that its generation units 3 and 4 are needed for transmission reliability. In April 2024, H.A. Wagner filed a cost-of-service rate schedule at FERC for the continued Reliability Must Run operation and provision of service from these units. No assurance can be provided when, if at all, FERC will approve the filing. See Note 8 in Notes to the Interim Financial Statements and Note 12 in Notes to the Annual Financial Statements for additional information.
Brandon Shores Fuel Conversion Cancellation, Planned Retirement, and Reliability Impact Assessment. In the first quarter 2023, due to increased project costs and declining PJM capacity revenues, management concluded that the lower return on investment to convert Brandon Shores’ fuel source from coal to fuel oil no longer met Talen’s investment criteria. In April 2023, Brandon Shores notified PJM that it will deactivate electric generation on June 1, 2025. Accordingly, an aggregate $379 million of non-cash, pre-tax charges was recognized for the period from January 1 through May 17, 2023 (Predecessor), including a $361 million charge for the generation facility and $18 million of net realizable value and obsolescence charges for materials and supplies inventories and coal inventories.
In June 2023, PJM notified Brandon Shores that the units were needed for reliability. Talen subsequently notified PJM that it does not agree to continue to operate Brandon Shores under a Reliability-Must-Run arrangement. In April 2024, Brandon Shores filed a cost-of-service rate schedule at FERC for the continued Reliability Must Run operation and provision of service from these units. No assurance can be provided when, if at all, FERC will approve the filing. See Note 8 in Notes to the Interim Financial Statements and Notes 10 and 12 in Notes to the Annual Financial Statements for additional information.
Montour Coal-to-Natural Gas Conversion. In August 2023, Montour completed its natural gas fuel conversion. Units 1 and 2 are now dispatchable on either coal or natural gas. Permanent retirement of coal at Montour is required
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by the end of 2025, with an earlier retirement at the Company’s election. Montour incurred aggregate conversion capital expenditures of $16 million from May 18 through December 31, 2023 (Successor), $40 million from January 1 through May 17, 2023 (Predecessor) and $90 million for the year ended December 31, 2022 (Predecessor).
Unusual Market Events
Winter Storm Elliott. During December 2022, as a result of Winter Storm Elliott, PJM experienced extreme cold weather conditions that resulted in PJM’s declaration of a Capacity Performance event requiring generators to operate at their maximum output capacity. Certain of Talen’s generation facilities failed to meet the Capacity Performance requirements set forth by PJM, while Talen’s remaining generation facilities met or exceeded their capacity obligations. Talen and certain other market participants filed complaints at FERC against PJM that disputed a portion of the Capacity Performance penalties assessed by PJM. In December 2023, FERC approved a market-wide settlement that resolved the disputes. Talen’s final aggregate net penalty payments of $29 million were remitted during the period from May 18 through December 31, 2023 (Successor) and the period from January 1 through May 17, 2023. See Note 12 in Notes to the Annual Financial Statements for additional information.
Commodity Markets
The following tables summarize average on-peak power prices and natural gas prices for each of the PJM, ERCOT, and WECC markets for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor). During the first quarter 2024, natural gas prices for Texas Eastern M-3 and Houston Ship Channel settled below each of their ten-year averages resulting from reduced demand for natural gas as the regions experienced milder quarterly average temperature conditions. In PJM, the combination of mild temperatures and natural gas prices contributed to the similar on-peak power price settlements experienced during the prior year. In ERCOT and WECC, increased demand resulting from colder-than-average temperatures during January 2024 contributed to higher average on-peak power prices in each region compared to the prior year.
PJM. The average settled market prices for the three months ended March 31 were:
20242023
PJM West Hub Day Ahead Peak - $/MWh$36.03 $36.35 
PJM PL Zone Day Ahead Peak - $/MWh29.68 31.43 
PJM BGE Zone Day Ahead Peak - $/MWh38.31 40.18 
Texas Eastern M-3 - $/MMBtu2.90 2.93 
The average January and February forward market prices as of March 31 were:
20242023
2025 PJM West Hub Day Ahead Peak - $/MWh$66.52 $80.40 
2026 PJM West Hub Day Ahead Peak - $/MWh73.49 83.48 
2025 Texas Eastern M-3 - $/MMBtu5.50 8.80 
2026 Texas Eastern M-3 - $/MMBtu6.31 9.09 
The PJM West Hub 2025 and 2026 January and February average on-peak forward prices decreased approximately 17% and 12%, respectively, compared to the prior year.
ERCOT. The average settled market prices for the three months ended March 31 were:
20242023
ERCOT South Hub Day Ahead Peak - $/MWh$31.27 $27.46 
ERCOT South Hub Day Ahead Spark Spreads - $/MWh(a)17.79 11.91 
Houston Ship Channel - $/MMBtu1.92 2.23 
__________________
(a)Spark Spreads are computed based on a heat rate of 7 MMBtu/MWh.
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The average July and August forward market prices as of March 31 were:
20242023
2024 ERCOT South Hub Real Time Spark Spreads - $/MWh (a)
$109.57 $51.61 
2025 ERCOT South Hub Real Time Spark Spreads - $/MWh (a)
81.33 45.63 
2026 ERCOT South Hub Real Time Spark Spreads - $/MWh (a)
75.14 45.62 
__________________
(a)Spark Spreads are computed based on a heat rate of 7 MMBtu/MWh.
The ERCOT South Hub Day Ahead Spark Spreads 2024 quarter average settled prices increased approximately 49% compared to the prior year.
The ERCOT South Hub 2024 and 2025 July and August average on-peak forward spark spreads prices increased approximately 112% and 78%, respectively, compared to the prior year.
WECC. The average settled market prices for the three months ended March 31 were:
20242023
Mid-Columbia Day Ahead Peak - $/MWh$113.11 $107.98 
Sumas - $/MMBtu3.23 8.26 
The average third quarter forward market prices as of March 31 were:
20242023
2024 Mid-Columbia Day Ahead Peak - $/MWh$134.96 $180.76 
2025 Mid-Columbia Day Ahead Peak - $/MWh134.99 172.36 
2026 Mid-Columbia Day Ahead Peak - $/MWh
122.66 136.66 
The Mid-Columbia Day Ahead Peak 2024 quarter average settled prices increased approximately 5% compared to the prior year.
The Mid-Columbia 2024 and 2025 third quarter average on-peak forward prices decreased approximately 25% and 22%, respectively, compared to the prior year.
Capacity Markets
Approximately 85% of our generation capacity is located in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, ISO demand forecasts, reserve margin targets and adjustments to PJM MSOC as determined by the PJM IMM.
PJM Capacity Auctions. Under the RPM, PJM conducts a series of capacity auctions. Most capacity is procured in the auctions conducted each May for the delivery of generation capacity for the PJM Capacity Year, which is three years from the date of the auction. Capacity auctions have recently been delayed, resulting in the auctions being held with less than 3 years between the auctions and the PJM Capacity Year. The capacity market construct provides generation owners the opportunity for some revenue visibility on a multiyear basis. The results of each of these auctions impacts Talen's capacity revenues in the specific PJM Capacity Year.
See “—Capacity Prices” below for additional information on capacity prices and see Note 10 in Notes to the Interim Financial Statements for additional information on the PJM RPM and other PJM matters.
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Capacity Prices. The following table displays the PJM Base Residual Auction’s cleared capacity prices for the markets and zones in which we primarily operate as of March 31, 2024:
2024/20252023/20242022/20232021/2022
PJM Capacity Performance ($/MW-day) (a)
MAAC$49.49 $49.49 $95.79 $140.00 
PPL49.49 49.49 95.79 140.00 
BGE73.00 69.95 126.50 200.30 
PSEG54.95 49.49 97.86 204.29 
__________________
(a)Displayed prices are from the applicable market publications.
Nuclear Production Tax Credit
The Inflation Reduction Act of 2022 was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program.
The Nuclear PTC program provides qualified nuclear power generation facilities with a $3 per MWh transferable credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna after December 31, 2023 through December 31, 2032 will qualify for the credit, which is subject to potential adjustments. Such adjustments include inflation escalators, a five-times increase in tax credit value (to $15 per MWh) if the qualifying generation facility meets prevailing wage requirements, and a pro-rata decrease in tax credit value once the annual gross receipts of a qualifying generation facility exceeds $25 per MWh. As the credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation), the Nuclear PTC program is expected to create a minimum price Susquehanna is expected to receive for its generation. Susquehanna generated approximately 18 million MWh in each of the calendar years 2023, 2022 and 2021.
The credit would be:
Annual Gross ReceiptsCredit Amount
$25 per MWh or less$15 per MWh
Greater than $25 per MWhRatably reduced until gross receipts equal $43.75 per MWh, $0 after that threshold
The Inflation Reduction Act’s provisions are subject to implementation regulations, whose terms are not yet known. No assurance can be provided as to the magnitude of the benefit to Susquehanna as the Inflation Reduction Act’s provisions, including the computations of the Nuclear PTC, are subject to implementation regulations. As such, Talen cannot fully predict the realization of any minimum price for Susquehanna’s generation and (or) impacts to Talen’s liquidity or results of operations. See Note 4 in Notes to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized.
Seasonality/Scheduled Maintenance
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results in the future may fluctuate substantially on a seasonal basis. For example, a lack of sustained cold weather in the Mid-Atlantic region may suppress regional natural gas prices and reduce our future capacity and energy revenues. Alternatively, above-average temperatures in the summer tend to increase summer cooling electricity demand, energy prices and revenues, and below-average temperatures in the winter tend to increase winter heating electricity demand, energy prices and revenues. Inversely, the milder weather during spring and fall tend to decrease the need for both cooling electricity demand and heating electricity demand. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region and during the summer in Texas.
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We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance requirements of our facilities and the terms of bilateral contracts to purchase or sell electricity. The largest and recurring maintenance project is the annual spring refueling outage at Susquehanna. The outages normally occur during late March and into April each year.
Results of Operations
The results of operations presented below should be reviewed in conjunction with the Interim Financial Statements, the Annual Financial Statements, and their respective notes. Our financial results for the three-month period ending March 31, 2023, the period January 1 through May 17 , 2023, and for the years ended December 31, 2022 and 2021, are referred to as the “Predecessor” periods. Our financial results for the three-month period ending March 31, 2024 and the period from May 18 through December 31, 2023 are referred to as the “Successor” periods. The operating results of the three-month period ending March 31, 2024 and the period May 18 through December 31, 2023 cannot be adequately compared with any of the previous periods reported in the Interim Financial Statements or the Annual Financial Statements. Our results of operations as reported in the Interim Financial Statements and the Annual Financial Statements are prepared in accordance with GAAP.
In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. Energy revenues relate to sales to an ISO or RTO, sales under wholesale bilateral contracts or realized hedging activity, Bitcoin revenue and Nuclear PTC revenue. Fuel and energy purchases includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
In addition, unrealized gains (losses) on derivatives instruments resulting from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” in the Interim Financial Statements and the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities.
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Results for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor)
The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:
SuccessorPredecessor
Three Months Ended March 31, 2024Three Months Ended March 31, 2023
Capacity revenues$45 $66 
Energy and other revenues572 862 
Unrealized gain (loss) on derivative instruments(108)145 
Operating Revenues
509 1,073 
Energy Expenses
Fuel and energy purchases(150)(107)
Nuclear fuel amortization(35)(24)
Unrealized gain (loss) on derivative instruments(27)(114)
Total Energy Expenses
(212)(245)
Operating Expenses
Operation, maintenance and development(154)(177)
General and administrative(43)(29)
Depreciation, amortization and accretion(75)(132)
Impairments— (365)
Other operating income (expense), net— (9)
Operating Income (Loss)
25 116 
Nuclear decommissioning trust funds gain (loss), net75 46 
Interest expense and other finance charges(59)(104)
Reorganization income (expense), net— (39)
Gain (loss) on sale of assets, net
324 — 
Other non-operating income (expense), net23 41 
Income (Loss) Before Income Taxes
388 60 
Income tax benefit (expense)(69)(14)
Net Income (Loss)
319 $46 
Less: Net income (loss) attributable to noncontrolling interest25 (2)
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $294 $48 
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Successor Period — Three months ended March 31, 2024
Net Income (Loss) Attributable to Members totaled $294 million for the three months ended March 31, 2024 (Successor). Results were driven by:
Capacity Revenues totaled $45 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 delivery period.
Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $422 million. This consisted of: (i) $329 million in third-party wholesale electricity sales and ancillary revenues; (ii) $78 million in other revenue primarily related to Nautilus operations and Nuclear PTC; and (iii) $166 million in net realized gains from hedging activities. Such amounts were partially offset by $(151) million in fuel and purchased power costs.
Unrealized Gain (Loss) on Derivative Instruments totaled $(135) million loss, net. This consisted of: (i) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period; and (ii) unrealized losses incurred as a result of increases in forward power prices.
Nuclear Fuel Amortization totaled $(35) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $(11) million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence.
Operation, Maintenance, and Development totaled $(154) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Depreciation, Amortization and Accretion totaled $(75) million. This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion.
Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $75 million. This consisted of realized and unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
Interest Expense and Other Finance Charges totaled $(59) million. This primarily consisted of interest expense incurred on the Secured Notes and Term Loans.
Other Non-operating Income (Expense), net, totaled $23 million. This primarily consisted of the gain on the sale of the Cumulus Data Center Campus. See Note 17 in Notes to the Interim Financial Statements for additional information.
Income Tax Benefit (Expense) totaled $(69) million. This primarily consisted of federal/state income taxes, effects of permanent nondeductible items, trust tax on the nuclear decommissioning trust income, and changes in the valuation allowance.
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Predecessor Period — Three months ended March 31, 2023
Net Income (Loss) Attributable to Member totaled $48 million for the three months ended March 31, 2023 (Predecessor). Results were driven by:
Capacity Revenues totaled $66 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $(13) million of net PJM capacity penalties related to the 2022 Winter Storm Elliot. See Note 10 in Notes to the Interim Financial Statements for additional information on PJM capacity penalties.
Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $755 million. This consisted of: (i) $585 million in net realized gains from hedging activities; (ii) $245 million in third-party wholesale electricity sales and ancillary revenues; and (iii) $9 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(84) million in fuel and purchased power costs.
Unrealized Gain (Loss) on Derivative Instruments totaled $31 million gain, net. This consisted of: (i) unrealized gains incurred as a result of decreases in forward power prices; partially offset by (ii) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
Nuclear Fuel Amortization totaled $(24) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment.
Operation, Maintenance, and Development totaled $(177) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Depreciation, Amortization and Accretion totaled $(132) million. This consisted of the periodic expense of long-lived property, plant and equipment, and ARO accretion.
Impairments totaled $(365) million. This primarily consisted of the Brandon Shores asset group impairment. See Note 8 in Notes to the Interim Financial Statements for additional information.
Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $46 million. This consisted of realized and unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
Interest Expense and Other Finance Charges totaled $(104) million. This primarily consisted of interest expense incurred on prepetition debt and certain LC fees.
Reorganization Income (Expense), net, totaled $(39) million. This primarily consisted of professional fees and make-whole premiums accruals incurred during the Restructuring.
Other Non-operating Income (Expense), net, totaled $41 million. This primarily consisted of non-recurring sale during the period. See Note 17 in Notes to the Interim Financial Statements for additional information on the sale.
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Results for the period from May 18 through December 31, 2023 (Successor), the period from January 1 through May 17, 2023 (Predecessor), and the years ended December 31, 2022 and December 31, 2021 (Predecessor)
The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:
SuccessorPredecessor
May 18
through
December 31,
January 1 through May 17,Year Ended December 31,Year Ended December 31,
2023202320222021
Capacity revenues$133 $108 $377 $444 
Energy and other revenues1,156 1,042 2,035 1,331 
Unrealized gain (loss) on derivative instruments55 60 677 (847)
Operating Revenues
1,344 1,210 3,089 928 
Energy Expenses
Fuel and energy purchases(424)(176)(938)(856)
Nuclear fuel amortization(108)(33)(94)(96)
Unrealized gain (loss) on derivative instruments(3)(123)(52)135 
Total Energy Expenses
(535)(332)(1,084)(817)
Operating Expenses
Operation, maintenance and development(358)(285)(610)(584)
General and administrative(93)(51)(106)(88)
Depreciation, amortization and accretion(165)(200)(520)(524)
Impairments(3)(381)— — 
Operational restructuring— — (488)— 
Other operating income (expense), net(30)(37)(40)(15)
Operating Income (Loss)
160 (76)241 (1,100)
Nuclear decommissioning trust funds gain (loss), net108 57 (184)196 
Interest expense and other finance charges(176)(163)(359)(325)
Consolidation of subsidiary gain (loss)— — (170)— 
Reorganization income (expense), net— 799 (812)— 
Other non-operating income (expense), net102 60 (44)(48)
Income (Loss) Before Income Taxes
194 677 (1,328)(1,277)
Income tax benefit (expense)(51)(212)35 300 
Net Income (Loss)
143 465 (1,293)(977)
Less: Net income (loss) attributable to noncontrolling interest(14)(4)— 
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) $134 $479 $(1,289)$(977)
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Successor Period — May 18, 2023 through December 31, 2023
Net Income (Loss) Attributable to Members totaled $134 million for the period of May 18, 2023 through December 31, 2023 (Successor). Results were driven by:
Capacity Revenues totaled $133 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 delivery period. Capacity revenues were positively impacted by $19 million, as a result of the FERC approved settlement agreement for net PJM capacity penalties assessed related to the 2022 Winter Storm Elliot. See Note 12 in Notes to the Annual Financial Statements for additional information on PJM capacity penalties.
Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $732 million. This consisted of: (i) $950 million in third-party wholesale electricity sales and ancillary revenues; (ii) $81 million in other revenue primarily related to Nautilus operations; and (iii) $33 million in net realized gains from hedging activities. Such amounts were partially offset by $(328) million in fuel and purchased power costs.
Unrealized Gain (Loss) on Derivative Instruments totaled $52 million gain, net. This consisted of: (i) unrealized gains incurred as a result of decreases in forward power prices; and (ii) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
Nuclear Fuel Amortization totaled $(108) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $(53) million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 in Notes to the Annual Financial Statements for additional information.
Operation, Maintenance, and Development totaled $(358) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Depreciation, Amortization and Accretion totaled $(165) million. This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion.
Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $108 million. This consisted of realized and unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 9 and 14 in Notes to the Annual Financial Statements for additional information.
Interest Expense and Other Finance Charges totaled $(176) million. This primarily consisted of interest expense incurred on the Secured Notes, Term Loans and LMBE-MC TLB.
Other Non-operating Income (Expense), net, totaled $102 million. This primarily consisted of the gain on the PPL/Talen Montana litigation settlement. See Note 12 in Notes to the Annual Financial Statements for additional information.
Predecessor Period — January 1, 2023 through May 17, 2023
Net Income (Loss) Attributable to Members totaled $479 million for the period from January 1, 2023 through May 17, 2023 (Predecessor). Results were driven by:
Capacity Revenues totaled $108 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $13 million of net PJM capacity penalties related to the 2022 Winter Storm Elliot. See Note 12 in Notes to the Annual Financial Statements for additional information on PJM capacity penalties.
Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $866 million. This consisted of: (i) $637 million in net realized gains from hedging activities; (ii) $343 million in third-party wholesale
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electricity sales and ancillary revenues; and (iii) $27 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(141) million in fuel and purchased power costs.
Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million loss, net. This consisted of: (i) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period; and (ii) unrealized gains incurred as a result of decreases in forward power prices.
Operation, Maintenance, and Development totaled $(285) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Depreciation, Amortization and Accretion totaled $(200) million. This consisted of the periodic expense of long-lived property, plant and equipment, and ARO accretion.
Impairments totaled $(381) million. This primarily consisted of the Brandon Shores asset group impairment. See Note 10 in Notes to the Annual Financial Statements for additional information.
Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $57 million. This consisted of realized and unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 9 and 14 in Notes to the Annual Financial Statements for additional information.
Interest Expense and Other Finance Charges totaled $(163) million. This primarily consisted of interest expense incurred on the Prepetition Secured Notes, Prepetition RCF, Prepetition TLB, LMBE-MC TLB and certain LC fees.
Reorganization Income (Expense), net, totaled $799 million. This primarily consisted of: (i) $1,459 million gain on debt discharge recognized upon Emergence; and (ii) $460 million loss on revaluation adjustments. See Note 4 in Notes to the Annual Financial Statements for additional information.
Other Non-operating Income (Expense), net, totaled $60 million. This primarily consisted of non-recurring sales during the period. See Note 22 in Notes to the Annual Financial Statements for additional information.
Income Tax Benefit (Expense) totaled $(212) million. This primarily consisted of federal/state income taxes, reorganization adjustments, and changes in the valuation allowance. See Note 7 in Notes to the Annual Financial Statements for additional information.
Predecessor Periods — Year Ended December 31, 2022 vs Year Ended December 31, 2021
Capacity Revenues. $(67) million unfavorable decrease. This primarily consisted of: (i) $(34) million due to lower cleared capacity prices and less MWs cleared through PJM's capacity auction for 2022/2023 PJM Capacity Year compared to the 2021/2022 PJM Capacity Year and partially offset by higher cleared capacity prices and additional MWs cleared in PJM's base capacity auction for the 2021/2022 compared to the 2020/2021 PJM Capacity year; and (ii) $(33) million decrease primarily due to a net PJM capacity penalty related to the 2022 Winter Storm Elliot extreme weather event.
Energy and Other Revenues, net of Fuel and Energy Purchases. $622 million favorable increase. This consisted of: (i) $1 billion increase in margin associated with electric generation resulting from higher realized prices received at our generation facilities partially offset by lower generation volumes; (ii) $(357) million decrease in realized hedges; (iii) $(157) million decrease from losses incurred on early terminated commodity contract agreements; and (iv) $78 million increase due to losses incurred as a result of Winter Storm Uri in 2021.
Unrealized Gain (Loss) on Derivative Instruments. $1.3 billion favorable increase. This consisted of: (i) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period; and (ii) unrealized gains incurred as a result of decreases in forward power prices.
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Operation, Maintenance and Development. $(26) million unfavorable increase. This consisted of: (i) higher operation expense in 2022 throughout PJM due to employee retention payments and an increase in short-term incentive compensation in 2022; and (ii) higher operation and maintenance expense primarily at Susquehanna due to an increase in the cost of material and chemicals, higher utilities, and disposal costs.
Operational Restructuring. $(488) million charge recognized in 2022. This consisted of: (i) $(453) million within PJM, primarily for the charge related to Talen Energy Marketing retail power contracts that were rejected in connection with the Restructuring; and (ii) $(35) million within ERCOT primarily due to the charges for long-term service agreements that were rejected in connection with the Restructuring See Note 3 in Notes to the Annual Financial Statements for additional information on the Restructuring.
Other Operating Income (Expense), net. $(25) million unfavorable increase. This primarily consisted of an increase in expense within PJM for environmental obligation revisions and accrued legal settlements for the Kinder Morgan litigation. See Note 12 in Notes to the Annual Financial Statements for additional information.
Nuclear Decommissioning Trust Funds Gain (Loss), net. $(380) million unfavorable decrease. This consisted of: (i) unrealized losses primarily due to inflation, geopolitics, and rising interest rates weighing on the equity markets in 2022 compared to favorable equity market conditions in 2021; and (ii) an unfavorable change due to realized gains recognized in 2021 as a result of asset portfolio re-balancing activities.
Interest Expense and Other Finance Charges. $(34) million unfavorable increase. This primarily consisted of: interest expense incurred on the Prepetition RCF, DIP TLB, and affiliate borrowing by Montana from TEM.
Consolidation of Subsidiary Gain (Loss), net. $(170) million unfavorable decrease. This consisted of losses recognized from the consolidation of Cumulus Digital Holdings due to a change of control. See Note 2 in Notes to the Annual Financial Statements for additional information.
Reorganization income (expense), net. $(812) million unfavorable increase. This primarily consisted of: (i) $(310) million for Backstop Premiums; (ii) $(210) million for Restructuring professional fees; (iii) $(183) million for make-whole premiums and accrued interest on certain indebtedness; (iv) $(70) million for professional fees incurred to obtain the DIP Credit Agreements; and (v) $(30) million for the write-off of the aggregate prepetition debt issuance cost carrying value.
Income tax benefit (expense). $(265) million unfavorable decrease. This primarily consisted of: (i) $(198) million increase in valuation allowance expense; (ii) $(94) million increase in unfavorable permanent differences; and (iii) $(53) million decrease in federal and state tax benefit due to change in pre-tax book income; partially offset by: (i) $56 million decrease in NDT tax expense; and (ii) $24 million favorable remeasurement of deferred taxes related to a change in the Pennsylvania state rate.
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 commercial and hedging activities, including cash collateral and other forms of credit support; (v) legacy environmental obligations; and (vi) other working capital requirements.
Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt 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
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sufficient to cover fixed and variable expenses, hedging and optimization 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 establishing 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 does not require cash collateral posting. 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. This strategy limits the use of exchange-based hedging and the associated margin requirements, which helps minimize collateral positing requirements. Additionally, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service 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 “Business—Our Commercial Risk Management Strategy” for an overview of our hedging and other risk management strategies.
In May 2023, effective with Talen’s Emergence, Talen completed several secured financing transactions including the issuance of: (i) $1.2 billion aggregate principal of Secured Notes, due 2030; and (ii) approximately $1.1 billion Term Loans, due 2030. See “—Indebtedness—Exit Financings” below for additional information. This included settling claims under the Plan of Reorganization such as the cash settlement of the following recourse long-term debt and revolver facility outstanding cash borrowings: DIP TLB; Prepetition TLB; Prepetition Secured Notes; and the Prepetition CAF and the settlement of Prepetition Unsecured Notes and PEDFA 2009A Bonds through the issuance of our common stock. Proceeds from the TLC were initially used to collateralize letters of credit. See “—Recent Developments—Emergence from Restructuring” above for additional information on the Restructuring and related financings.
In August 2023, we incurred an additional $290 million in aggregate principal amount of the TLB, resulting in proceeds of $285 million, net of original issue discount and other fees. The additional amount, issued as an additional borrowing under the TLB, constitutes a single series of indebtedness with the existing TLB incurred at Emergence. The proceeds of TES’s new debt issuance, together with approximately $12 million of cash on hand at LMBE-MC, were used to fully repay an aggregate $297 million comprised of outstanding principal, accrued interest, and LC fees. The LMBE-MC Credit Agreement along with an aggregate $12 million of outstanding LCs issued under the agreement were terminated at settlement. See Note 13 in Notes to the Annual Financial Statements for additional information on the LMBE-MC Credit Agreement termination.
In March 2024, using proceeds from the sale of Cumulus Data assets, the Cumulus Digital TLF was paid in full, together with all accrued interest and other outstanding amounts. See Note 17 in Notes to the Interim Financial Statements for additional information on the Data Center Campus Sale.
In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale, and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement.
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TEC is a holding company that does not (and does not intend to) conduct any business operations or incur material obligations of its own. While we do not expect TEC to incur obligations that it is unable meet due to contractual restrictions on distributions from subsidiaries, certain subsidiaries are subject to such limitations. However, TEC’s cash flows are largely dependent on the operating cash flows of TES and TEC’s other subsidiaries and the payment of such operating cash flows to TEC in the form of dividends, distributions, loans or otherwise. The Indenture and Credit Facilities restrict the ability of TES to pay dividends or distributions to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or distributions: (1) in an amount not to exceed $160 million, (2) in an unlimited amount so long as TES’ pro forma consolidated total net leverage ratio is less than or equal to 1.5 to 1.0 (or, on and after the date the second quarter 2024 financials are due under the Credit Agreement, 2.0 to 1.0), and (3) in an amount not to exceed the sum of: (a) TES’ adjusted EBITDA minus 140% of TES’ consolidated interest expense, in each case, for the period beginning June 1, 2023 (subject to (i) in the case of the Credit Facilities, compliance with a pro forma consolidated total net leverage ratio of less than or equal to 2.75 to 1.0 (or, after the date the second quarter 2024 financials are due under the Credit Agreement, 3.25 to 1.0) and (ii) in the case of the Indenture, the ability to incur $1 of additional ratio debt), (b) $150 million, (c) equity contributions to TES, and (d) other customary “builder basket” components. See “Risk Factors—Risks Related to Ownership of Our Common Stock—TEC is a holding company; its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the agreements governing our indebtedness contain certain restrictions on distributions of cash to TEC” and “Risk Factors—Financial and Liquidity Risks—Our debt agreements contain various covenants that impose restrictions on TES and certain of its subsidiaries that may affect our ability to operate our business and to make payments on our indebtedness.”
See Notes 3, 5, 11 and 20 in Notes to the Annual Financial Statements and Notes 3, 9 and 16 in Notes to the Interim Financial Statements for additional information regarding various liquidity topics discussed below.
Talen Liquidity
Successor
March 31,
2024
December 31,
2023
Cash and cash equivalents, unrestricted$597 $400 
RCF544 638 
Available liquidity
$1,141 $1,038 
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.
Financial Performance Assurances
Successor
March 31,
2024
December 31, 2023
Outstanding surety bonds$241 $240 
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.
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Forecasted Uses of Cash
Capital Expenditures and Development Funding. Capital expenditure plans and funding requirements for development activities are revised periodically for changes in operational needs, market conditions, regulatory requirements and cost projections. Accordingly, the expected cash requirements for these projects are subject to revision.
20242025
Generation facilities
Nuclear fuel$88 $113 
PJM nuclear generation facility31 50 
PJM fossil generation facilities34 32