As filed with the Securities and Exchange Commission on July 3, 2024.
Registration No. 333-280341
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Amendment No. 2 to
FORM S-1
REGISTRATION STATEMENT
UNDER
THE SECURITIES ACT OF 1933
Talen Energy Corporation
(Exact name of Registrant as specified in its charter)
| Delaware | 4911 | 47-1197305 | ||||||||||||
| (State or other jurisdiction of incorporation or organization) | (Primary Standard Industrial Classification Code Number) | (I.R.S. Employer Identification Number) | ||||||||||||
2929 Allen Pkwy, Suite 2200
Houston, TX 77019
(888) 211-6011
(Address, including zip code, and telephone number, including area code, of Registrant’s principal executive offices)
Mark “Mac” A. McFarland, Chief Executive Officer
Talen Energy Corporation
2929 Allen Pkwy, Suite 2200
Houston, TX 77019
(888) 211-6011
(Name, address, including zip code, and telephone number, including area code, of agent for service)
Copies to:
Matthew R. Pacey, P.C. Michael W. Rigdon, P.C. Anthony L. Sanderson Kirkland & Ellis LLP 609 Main Street Houston, TX 77002 (713) 836-3600 | John C. Wander Rebekah D. Reneau Talen Energy Corporation 2929 Allen Pkwy, Suite 2200 Houston, TX 77019 (888) 211-6011 | ||||
Approximate date of commencement of proposed sale to the public: From time to time after this Registration Statement is declared effective.
If any of the securities being registered on this form are to be offered on a delayed or continuous basis pursuant to Rule 415 under the Securities Act of 1933, check the following box. ☒
If this form is filed to register additional securities for an offering pursuant to Rule 462(b) under the Securities Act, please check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this form is a post-effective amendment filed pursuant to Rule 462(c) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
If this form is a post-effective amendment filed pursuant to Rule 462(d) under the Securities Act, check the following box and list the Securities Act registration statement number of the earlier effective registration statement for the same offering. ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| Large accelerated filer | ☐ | Accelerated filer | ☐ | ||||||||
| Non-accelerated filer | ☒ | Smaller reporting company | ☐ | ||||||||
| Emerging growth company | ☐ | ||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 7(a)(2)(B) of the Securities Act. ☐
The Registrant hereby amends this Registration Statement on such date or dates as may be necessary to delay its effective date until the Registrant shall file a further amendment which specifically states that this Registration Statement shall thereafter become effective in accordance with Section 8(a) of the Securities Act of 1933, as amended, or until the Registration Statement shall become effective on such date as the Commission, acting pursuant to said Section 8(a), may determine.
The information in this prospectus is not complete and may be changed. None of the Selling Stockholders of our common stock may sell these securities until the registration statement filed with the Securities and Exchange Commission is effective. This prospectus is not an offer to sell these securities and it is not soliciting offers to buy these securities in any jurisdiction where such offer or sale is not permitted.
Subject to Completion. Dated July 3, 2024.
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 June 28, 2024, the closing sales price of our common stock as reported on the OTCQX U.S. Market was $111.02 per share. We have applied to list our common stock on the Nasdaq Global Select Market (“Nasdaq”) under the symbol “TLN.” We expect our common stock to begin trading on Nasdaq on or about . If the common stock is not approved for listing on Nasdaq, we will not complete the registration contemplated hereby.
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 , 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.”
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.
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.
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 $300 million of consideration will be released to the Company.
In connection with the Cumulus Data Campus Sale, the Company executed the Cumulus Data Campus PPA with AWS, pursuant to which the Company agreed to supply long-term, carbon-free power from Susquehanna to the Cumulus Data Campus through fixed-price power commitments. Under the Cumulus Data Campus PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW (the “480 MW Case”) or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-
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applicable PJM energy and capacity prices. The initial term of the Cumulus Data Campus PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, Talen will receive additional revenue from AWS related to the sales of carbon-free energy (“CFE”) to the grid. The following table shows the value of these agreements, to the extent reasonably estimable, based on the minimum commitments described above through achievement of the 480 MW case.
| Year | PTC Reference Price ($/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 intend to list our common stock on Nasdaq under the symbol “TLN.” | ||||
| Determination of offering price | The 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.
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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 | Successor | Predecessor | Pro 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 | |||||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||
| (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/A | 59,029 | N/A | N/A | N/A | 59,029 | |||||||||||||||||||||||||||||||||||||||||||
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| Successor | Predecessor | Successor | Predecessor | Pro 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 | |||||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted average shares of common stock outstanding — diluted | 60,716 | N/A | 59,399 | N/A | N/A | N/A | 59,399 | |||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) per weighted average share of common stock outstanding — basic | 5.00 | N/A | 2.27 | N/A | N/A | N/A | $ | 1.52 | ||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) per weighted average share of common stock outstanding — diluted | 4.84 | N/A | 2.26 | N/A | N/A | N/A | $ | 1.52 | ||||||||||||||||||||||||||||||||||||||||||
| Successor | Predecessor | ||||||||||||||||||||||
| As of March 31, 2024 | As of December 31, 2023 | As 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) | 2024 | 2023 | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) | $ | 319 | $ | 46 | $ | 143 | $ | 465 | $ | (1,293) | $ | (977) | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Adjustments | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | 50 | 104 | 181 | 163 | 365 | 336 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Income tax (benefit) expense | 69 | 14 | 51 | 212 | (35) | (300) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | 75 | 132 | 165 | 200 | 520 | 524 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear fuel amortization | 35 | 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 contracts | 134 | (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 | 8 | — | 21 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Long-term incentive compensation expense | 10 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Environmental and ARO revisions on fully depreciated property, plant and equipment (c) | — | — | 5 | — | 18 | (7) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
(Gain) loss on non-core asset sales, net (d) | (324) | (35) | (7) | (50) | (3) | (3) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-cash impairments (e) | — | 365 | 3 | 381 | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Legal settlements and litigation costs (f) | (2) | — | (84) | 1 | 20 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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Unusual market events (g) | (1) | 13 | (19) | 14 | 33 | 78 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net periodic defined benefit cost (h) | — | (2) | 2 | (3) | 12 | 36 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Operational and other restructuring activities (i) | 2 | 8 | 48 | 17 | 522 | 13 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Liability management costs and other professional fees | — | — | — | — | 46 | 29 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Development expenses | — | 7 | 7 | 10 | 17 | 8 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Non-cash inventory net realizable value, obsolescence, and other charges (j) | 1 | 24 | 4 | 56 | (4) | 24 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Consolidation of subsidiary (gain) loss, net | — | — | — | — | 170 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Cumulus Digital activities and noncontrolling interest (k) | (11) | (3) | (42) | (14) | 3 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other | (1) | 1 | — | 3 | 1 | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 289 | $ | 660 | $ | 426 | $ | 695 | $ | 1,015 | $ | 387 | ||||||||||||||||||||||||||||||||||||||||||||||||||
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(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 applied 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 | |||||||||||
| High | Low | ||||||||||
| 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 (for the period from April 1, 2024 through June 28, 2024) | $ | 120.00 | $ | 92.60 | |||||||
On June 28, 2024, the closing price of our common stock as reported on the OTCQX U.S. Market was $111.02 per share. As of June 28, 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 applied 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 debt | 2,619 | ||||
| Total debt | 2,619 | ||||
| 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 interests | 65 | ||||
| Total equity | 2,766 | ||||
| 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 revenues | 1,156 | 1,042 | — | — | 2,198 | |||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 55 | 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), net | 108 | 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), net | 102 | 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 | 9 | (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 - Diluted | 2.26 | 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:
| 2024 | 2023 | ||||||||||||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 36.03 | $ | 36.35 | |||||||||||||||||||
| PJM PL Zone Day Ahead Peak - $/MWh | 29.68 | 31.43 | |||||||||||||||||||||
| PJM BGE Zone Day Ahead Peak - $/MWh | 38.31 | 40.18 | |||||||||||||||||||||
| Texas Eastern M-3 - $/MMBtu | 2.90 | 2.93 | |||||||||||||||||||||
The average January and February forward market prices as of March 31 were:
| 2024 | 2023 | ||||||||||||||||||||||
| 2025 PJM West Hub Day Ahead Peak - $/MWh | $ | 66.52 | $ | 80.40 | |||||||||||||||||||
| 2026 PJM West Hub Day Ahead Peak - $/MWh | 73.49 | 83.48 | |||||||||||||||||||||
| 2025 Texas Eastern M-3 - $/MMBtu | 5.50 | 8.80 | |||||||||||||||||||||
| 2026 Texas Eastern M-3 - $/MMBtu | 6.31 | 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:
| 2024 | 2023 | ||||||||||||||||||||||
| 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 - $/MMBtu | 1.92 | 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:
| 2024 | 2023 | ||||||||||||||||||||||
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:
| 2024 | 2023 | ||||||||||||||||||||||
| Mid-Columbia Day Ahead Peak - $/MWh | $ | 113.11 | $ | 107.98 | |||||||||||||||||||
| Sumas - $/MMBtu | 3.23 | 8.26 | |||||||||||||||||||||
The average third quarter forward market prices as of March 31 were:
| 2024 | 2023 | ||||||||||||||||||||||
| 2024 Mid-Columbia Day Ahead Peak - $/MWh | $ | 134.96 | $ | 180.76 | |||||||||||||||||||
| 2025 Mid-Columbia Day Ahead Peak - $/MWh | 134.99 | 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:
| 2024/2025 | 2023/2024 | 2022/2023 | 2021/2022 | |||||||||||||||||||||||||||||
| PJM Capacity Performance ($/MW-day) (a) | ||||||||||||||||||||||||||||||||
| MAAC | $ | 49.49 | $ | 49.49 | $ | 95.79 | $ | 140.00 | ||||||||||||||||||||||||
| PPL | 49.49 | 49.49 | 95.79 | 140.00 | ||||||||||||||||||||||||||||
| BGE | 73.00 | 69.95 | 126.50 | 200.30 | ||||||||||||||||||||||||||||
| PSEG | 54.95 | 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 Receipts | Credit Amount | |||||||
| $25 per MWh or less | $15 per MWh | |||||||
| Greater than $25 per MWh | Ratably 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:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 45 | $ | 66 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy and other revenues | 572 | 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), net | 75 | 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), net | 23 | 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 interest | 25 | (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:
| Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 133 | $ | 108 | $ | 377 | $ | 444 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy and other revenues | 1,156 | 1,042 | 2,035 | 1,331 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 55 | 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), net | 108 | 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), net | 102 | 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 | 9 | (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 | ||||||||||||||||
| RCF | 544 | 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.
| 2024 | 2025 | ||||||||||
| Generation facilities | |||||||||||
| Nuclear fuel | $ | 88 | $ | 113 | |||||||
| PJM nuclear generation facility | 31 | 50 | |||||||||
| PJM fossil generation facilities | 34 | 32 | |||||||||
| ERCOT and WECC | 27 | 28 | |||||||||
Total generation facilities (a) | $ | 180 | $ | 223 | |||||||
Fuel conversion and other (b) | 10 | — | |||||||||
| Total | $ | 190 | $ | 223 | |||||||
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(a)Expected capitalized interest on capital expenditures is a non-material amount in 2024 and 2025.
(b)See “—Factors Affecting Our Financial Condition and Results of Operations—Generation Facility Updates—Montour Coal-to-Natural Gas Conversion” above for information.
Projected ARO and Accrued Environmental Liability Cash Flows
We have significant legal obligations related to our ARO and accrued environmental liabilities. Our undiscounted projected spending on AROs and accrued environmental liabilities is presented in the table below. The majority of the estimated non-nuclear spend is related to ash impoundments at Colstrip and Brunner Island. The carrying value of these obligations include certain assumptions, including a rate of inflation of approximately 2.5%. Projections are subject to revision based on changes in estimated inflation rates, changes in the estimated timing of settling AROs and escalating retirement costs. Susquehanna’s AROs are expected to be settled with funds available in the NDT at the time of decommissioning. See Note 11 in Notes to the Annual Financial Statements for additional information.
| (in millions) | 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | |||||||||||||||||||||||||||||
Non-nuclear AROs (a) | 16 | 47 | 69 | 55 | 50 | 319 | |||||||||||||||||||||||||||||
| Accrued environmental liabilities | 4 | 4 | 6 | 3 | 3 | 14 | |||||||||||||||||||||||||||||
__________________
(a)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.
Indebtedness
Exit Financings. In May 2023, as part of the Exit Financings, Talen consummated several secured financings, the proceeds of which, together with proceeds from the Rights Offering and cash on hand, were used to fund the settlement of the transactions and claims contemplated by the Plan of Reorganization and to provide liquidity and working capital for Talen’s business following Emergence. The Exit Financings included the:
•Secured Notes, due 2030, in an aggregate principal amount of $1.2 billion;
•RCF, due 2028, a $700 million revolving credit facility, including LC commitments of $475 million;
•TLB, due 2030, in an aggregate principal amount of $580 million (and subsequently increased to $870 million in August 2023);
•TLC, due 2030, in an aggregate principal amount of $470 million, the proceeds of which are used to cash collateralize LCs under the TLC LCF;
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•TLC LCF, which provides commitments for up to $470 million in LCs, cash collateralized with the proceeds of the TLC, and reduced to the extent that borrowings under the TLC are prepaid; and
•Bilateral LCF, which provides commitments for up to $75 million in LCs.
Certain key terms of our post-emergence facilities currently include:
| Facility | Maturity | Index | Rate, Applicable Margin, and Amortization | Prepayment Penalty | ||||||||||||||||||||||
| Secured Notes | June 2030 | None | 8.625% per annum fixed rate No applicable margin No amortization | Prior to June 1, 2026: Redeemable at par plus a customary “make-whole” premium. 10% redeemable during each 12-month period at 103%. 40% redeemable from the proceeds of certain equity offerings at 108.625% On or after June 1 of the following years: 2026: 104.313% 2027: 102.156% 2028 and thereafter: 100% | ||||||||||||||||||||||
| TLB | May 2030 | Term SOFR | 3.50% per annum applicable margin Amortization 1.00% per annum; paid quarterly | 1.00% to the extent prepaid prior to November 8, 2024 in connection with a repricing transaction | ||||||||||||||||||||||
| TLC (TLC LCF) | May 2030 | Term SOFR | 3.50% per annum applicable margin No amortization | 1.00% to the extent prepaid prior to November 8, 2024 in connection with a repricing transaction | ||||||||||||||||||||||
| RCF (cash borrowings) | May 2028 | Term SOFR | 3.50% per annum applicable margin; step-downs to 3.25% and 3.00% based on first lien net leverage ratios in certain fiscal quarters No amortization | None | ||||||||||||||||||||||
| RCF (LCs) | May 2028 | None | 0.125% per annum Fronting Fee and 3.50% per annum LC Fees (step-downs to 3.25% and 3.00% based on first lien net leverage ratios in certain fiscal quarters) | None | ||||||||||||||||||||||
| Bilateral LCF | May 2028 | None | 3.50% per annum LC Fees and 0.125% per annum Issuance Fee | None | ||||||||||||||||||||||
Credit Agreement. The Credit Agreement governs the RCF, TLB, TLC, and TLC LCF.
The Credit Agreement contains customary negative covenants including, but not limited to, limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and asset sales. The Credit Agreement also contains customary affirmative covenants. Solely with respect to the RCF, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving LCs (in excess of (i) $50 million of undrawn revolving LCs; and (ii) cash collateralized or backstopped LCs) exceed 35% of the revolving commitments under the RCF), the Credit Agreement includes a covenant that requires TES’s consolidated first lien net leverage ratio not to exceed 4.00 to 1.00 as of March 31, 2024 and increasing to 4.25 to
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1.00 as of June 30, 2024 and thereafer (to be tested as of June 30, 2024 and thereafter). The financial covenant does not apply to the TLB, TLC, or TLC LCF.
The Credit Agreement also contains customary representations and warranties and events of default. If an event of default occurs under the Credit Agreement, the lenders thereunder are entitled to take various actions, including accelerating amounts due and, in the case of the RCF and the TLC LCF, terminating commitments.
TLC LCF. The TLC LCF provides commitments for up to $470 million in LCs, cash collateralized with the proceeds of the TLC, with commitments thereunder reduced to the extent that borrowings under the TLC are prepaid. The lenders of the TLC have issued LCs totaling $404 million under the TLC LCF, which have been issued either directly to Talen’s counterparties or to lenders under the DIP Facilities to backstop LCs that were previously issued (or continued) thereunder and remain outstanding. These LCs are cash collateralized by $472 million as of March 31, 2024 (Successor) which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets. Additionally, the restricted cash earns interest income, which varies by rate depending on the corresponding letter of credit issuer. The interest income earned on the restricted cash offsets against the calculated effective interest rate for the TLC when determining the computed interest rate.
Bilateral LCF. The Bilateral LC Agreement provides for LC issuances that collectively cannot exceed $75 million and expires in May 2028. The Bilateral LC Agreement contains substantially the same covenants, representations and warranties, and events of default as the Credit Agreement. The Bilateral LCF includes a covenant that requires TES’s consolidated first lien net leverage ratio not to exceed 4.00 to 1.00 as of March 31, 2024 and increasing to 4.25 to 1.00 as of June 30, 2024 and thereafter, but such covenant only applies to the extent a compliance period exists under the Credit Agreement. In addition, the Bilateral LC Agreement contains an affirmative covenant requiring disposition of certain minority-owned coal assets. Subject to customary conditions, commitments under the Bilateral LC Agreement can be terminated by the lenders upon an event of default thereunder.
Secured Notes. Interest on the Secured Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2023, and at maturity. The Secured Notes are subject to customary negative covenants, including, but not limited to, certain limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and transactions involving the Susquehanna assets. The Secured Notes do not contain any financial covenants. The Secured Notes also contain customary affirmative covenants and events of default. If an event of default occurs, the holders of the Secured Notes are entitled to take various actions, including the acceleration of amounts due under the Secured Notes.
Secured ISDAs. Talen Energy Marketing is party to certain Secured ISDAs, a portion of which are continuations of either the Prepetition Secured ISDAs or the DIP Secured ISDAs. Under the Secured ISDAs, TES and the Subsidiary Guarantors provide the applicable counterparties with a first priority lien on and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. The secured obligations under the Secured ISDAs were approximately $61 million as of March 31, 2024 (Successor).
PEDFA Bonds. The PEDFA 2009B and 2009C Bonds remained outstanding following Emergence. These bonds are backstopped by LCs totaling $133 million as of March 31, 2024 (Successor). Each series of PEDFA Bonds was issued by the PEDFA on behalf of TES. TES received the proceeds from the original issuance of each series of PEDFA Bonds pursuant to a separate exempt facilities loan agreement. An unsecured promissory note of TES corresponding to each series of PEDFA Bonds contains principal, interest and prepayment provisions of the respective series.
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The PEDFA 2009B and 2009C Bonds accrue interest at a variable rate in accordance with the provisions of the trust indentures which is payable monthly. Obligations under the PEDFA 2009B and 2009C Bonds are supported by two irrevocable, direct-pay LCs, each corresponding to the applicable series, that were issued by a third-party lender in favor of the bond trustee in an amount equal to the outstanding principal of each series plus an interest component. Prior to Emergence, TES’s obligation to reimburse the third-party lender for payments made under each irrevocable, direct-pay LC was in turn supported by a corresponding backstop LC issued in favor of such lender. Upon Emergence, the backstop LCs were terminated and the direct-pay LCs are outstanding under the TLC LCF.
The PEDFA 2009B and 2009C Bonds: (i) are subject to mandatory purchase by TES at the option of each holder with at least seven days’ advance notice; (ii) may be redeemed at the option of TES at any time prior to their stated maturity date at a redemption price of 100% of the principal amount thereof plus accrued interest, if any, to the redemption date; (iii) are subject to mandatory purchase and optional remarketing upon conversion to an interest rate other than the daily rate as defined in the trust indentures or upon the cancellation, termination, expiration or substitution of the irrevocable, direct-pay LC corresponding to the applicable series; and (iv) are subject to mandatory purchase upon an event of default under the Credit Agreement.
Each series of PEDFA Bonds is subject to customary affirmative and negative covenants appropriate for such indebtedness. The loan agreements relating to the PEDFA Bonds do not limit TES’s ability to incur additional secured or unsecured indebtedness. Each series of PEDFA Bonds also contains customary events of default. If an event of default occurs, the holders of each series of PEDFA Bonds will be entitled to take various actions, including the acceleration of any outstanding amounts due. The Restructuring constituted an event of default under PEDFA Series 2009A bonds, but was not an event of default under the PEDFA 2009B and 2009C Bonds. The PEDFA 2009B and 2009C Bonds continue to be supported by the irrevocable, direct-pay LCs described above and TES continues to perform its associated reimbursement obligations. For additional information about the PEDFA 2009B Bonds and 2009C Bonds, see “Prospectus Summary—Recent Developments—Remarketing of PEDFA Bonds.”
Cash Flow Activities
Cash flow activities for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor)
The net cash provided by (used in) operating, investing and financing activities for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Operating activities | $ | 173 | $ | 744 | ||||||||||||||||||||||||||||||||||||||||||||||
| Investing activities | 265 | (118) | ||||||||||||||||||||||||||||||||||||||||||||||||
| Financing activities | (259) | (28) | ||||||||||||||||||||||||||||||||||||||||||||||||
Successor Period — Three months ended March 31, 2024
•Operating Cash Flows. Cash provided by (used in) operating activities totaled $173 million. This primarily consisted of cash provided from operations of the Company.
•Investing Cash Flows. Cash provided by investing activities totaled $265 million. Talen initially received $339 million of proceeds, net from the Cumulus Data Center Campus Sale. Partially offsetting this inflow were capital expenditures that totaled $(66) million that primarily consisted of $(41) million for nuclear-fuel expenditures. See Note 17 in Notes to the Interim Financial Statements for additional information on the Cumulus Data Center Sale.
•Financing Cash Flows. Cash (used) by financing activities totaled $(259) million. This primarily consisted of $(182) million for the repayment of the Cumulus Digital TLF in March 2024 using a portion of the proceeds from the Cumulus Data Center Campus Sale; $(39) million for the repurchase of noncontrolling interests held by affiliates of Orion and two former members of Talen senior management; and $(30) million to purchase treasury stock.
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Predecessor Period — Three months ended March 31, 2023
•Operating Cash Flows. Cash provided by operating activities totaled $744 million. This consisted of cash provided from the operations of the Company, including declines in accounts receivable and in collateral deposits paid.
•Investing Cash Flows. Cash (used in) investing activities totaled $(118) million. This primarily consisted of capital expenditures offset by $29 million in proceeds from the sale of non-core assets. Capital expenditures, including those for nuclear fuel, totaled $(130) million and consisted of: (i) $(84) million primarily for capital projects including the Montour fuel conversion, growth projects at Cumulus Data and Nautilus; and (ii) $(46) million for nuclear-fuel expenditures. See Note 17 in Notes to the Interim Financial Statements for additional information on the sale.
•Financing Cash Flows. Cash (used in) financing activities totaled $(28) million. This consisted of primarily of a final payment in January 2023 on terminated economic hedges that that were terminated in March 2022 but had deliveries until January 2023.
Cash flow activities 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 net cash provided by (used in) operating, investing and financing activities for the Successor period from May 18, 2023 through December 31, 2023 and Predecessor periods from January 1, 2023 through May 17, 2023 and the years ended December 31, 2022 and 2021 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||
| May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||||||||||||||||||||||||||
| Operating activities | $ | 402 | $ | 462 | $ | 187 | $ | (294) | ||||||||||||||||||||||||||||||||||||||||||
| Investing activities | (171) | (157) | (368) | (280) | ||||||||||||||||||||||||||||||||||||||||||||||
| Financing activities | (84) | (539) | 426 | 956 | ||||||||||||||||||||||||||||||||||||||||||||||
Successor Period — May 18, 2023 through December 31, 2023
•Operating Cash Flows. Cash provided by operating activities totaled $402 million. This primarily consisted of: (i) cash provided from operations; and (ii) the net receipt of $104 million, related to the settlement of the PPL litigation.
•Investing Cash Flows. Cash (used in) investing activities totaled $(171) million. Capital expenditures, including those for nuclear fuel, totaled $(161) million and primarily consisted of: (i) $(116) million for capital projects including the Montour fuel conversion and projects at Cumulus Data; and (ii) $(45) million for nuclear-fuel expenditures.
•Financing Cash Flows. Cash (used) by financing activities totaled $(84) million. This primarily consisted of $(59) million for payments to Riverstone to settle warrants and to repurchase Riverstone’s noncontrolling interest in Cumulus Digital Holdings. See Note 16 in Notes to the Annual Financial Statements for additional information on these transactions.
Predecessor Period — January 1, 2023 through May 17, 2023
•Operating Cash Flows. Cash provided by operating activities totaled $462 million. This consisted of cash provided from the operations of the Company, including declines in accounts receivable, partially offset by payments made for accrued interest and other claims at Emergence.
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•Investing Cash Flows. Cash (used in) investing activities totaled $(157) million. This primarily consisted of capital expenditures offset by $46 million in proceeds from the sale of non-core assets. Capital expenditures, including those for nuclear fuel, totaled $(187) million and consisted of: (i) $(138) million for capital projects including the Montour fuel conversion, growth projects at Cumulus Data and Nautilus, and Susquehanna activities; and (ii) $(49) million for nuclear-fuel expenditures. See Note 22 in Notes to the Annual Financial Statements for additional information on the sales.
•Financing Cash Flows. Cash (used in) financing activities totaled $(539) million. This consisted of $(1.9) billion net cash outflow due to the net effect of issuances and repayments of Prepetition Secured Indebtedness and make-whole premiums partially offset by $1.4 billion of cash contributions from the Rights Offering. See Note 3 in Notes to the Annual Financial Statements for additional information.
Predecessor Periods — Year Ended December 31, 2022 vs Year Ended December 31, 2021
Operating Cash Flows. Cash (used by) operating activities increased by $481 million. This consisted of:
| Change | ||||||||||||||||||||
| Energy and Other Revenues, net of Fuel and Energy Purchases between periods (See “Results of Operations” | $ | 622 | ||||||||||||||||||
| Increase in cash collateral deposits paid to counterparties | (50) | |||||||||||||||||||
Overall lower recourse interest payments due to stayed interest payments during the Restructuring partially offset in increases of interest paid on the Talen Commodity Accordion RCF issued in December 2021and on the DIP TLB issued in May 2022) | 35 | |||||||||||||||||||
| Lower capacity payments between periods (See “Results of Operations”) | (67) | |||||||||||||||||||
| Higher operation and maintenance expenditures between periods (See “Results of Operations”) | (26) | |||||||||||||||||||
| Other changes in cash provided by (used in) operating activities | (33) | |||||||||||||||||||
| Total | $ | 481 | ||||||||||||||||||
Investing Cash Flows. Cash provided by (used in) investing activities had an unfavorable increase of $88 million. This consisted of:
| Change | ||||||||||||||||||||
| Higher contributions to equity method and preferred equity investments. | $ | (97) | ||||||||||||||||||
| Higher capital expenditures between periods for the Montour fuel conversion | (87) | |||||||||||||||||||
| Higher capital expenditures between periods on the renewable, battery and digital infrastructure growth projects | (22) | |||||||||||||||||||
| Increase in cash and restricted cash due to consolidation of affiliate subsidiaries, TRF and Cumulus Digital Holdings | 123 | |||||||||||||||||||
| Other changes in cash provided by (used in) investing activities | (5) | |||||||||||||||||||
| Total | $ | (88) | ||||||||||||||||||
In September 2022, TES consolidated Cumulus Digital Holdings. In the preceding table: (i) amounts contributed by TES for Cumulus Digital Holdings projects before consolidation of Cumulus Digital Holdings are displayed as changes in equity method and preferred equity investment contributions; and (ii) amounts incurred by Cumulus Digital Holdings for growth projects after consolidation of Cumulus Digital Holdings are displayed as changes in growth capital expenditures.
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Financing Cash Flows. Cash provided by (used in) financing activities had an unfavorable decrease of $(530) million. This consisted of:
| Change | ||||||||||||||||||||
| Proceeds, net of premium paid on Talen Commodity Accordion RCF in 2021 | $ | (827) | ||||||||||||||||||
| Net proceeds and repayments of the Prepetition Deferred Capacity Obligations between periods | (337) | |||||||||||||||||||
| Net proceeds and repayments of the Prepetition Inventory Repurchase Obligations in 2022 | (165) | |||||||||||||||||||
| Proceeds from the issuance of PEDFA Bonds in 2021 | (131) | |||||||||||||||||||
| Payments made on the termination of certain economic hedge contracts | (104) | |||||||||||||||||||
| Higher LMBE-MC 2025 TLB repayments between periods | (25) | |||||||||||||||||||
| Higher debt issuance costs between periods | (36) | |||||||||||||||||||
| Proceeds, net of premium paid on DIP TLB in 2022 | 987 | |||||||||||||||||||
| Repayment of 4.6% Senior Notes due December 2021 at maturity | 114 | |||||||||||||||||||
| Other changes in cash provided by (used in) operating activities | (6) | |||||||||||||||||||
| Total | $ | (530) | ||||||||||||||||||
Contractual Obligations and Commitments
Guarantees of Subsidiary Obligations
TES guarantees certain agreements and obligations for its subsidiaries. Certain agreements may contingently require payments to a guaranteed or indemnified party. See Note 10 in Notes to the Interim Financial Statements and Note 12 in Notes to the Annual Financial Statements for additional information regarding guarantees.
Quantitative and Qualitative Disclosures About Market Risk
The forward-looking information presented below provides estimates of what may occur in the future, assuming certain adverse market conditions and model assumptions. Actual future results may differ materially from those presented. These disclosures are not precise indicators of expected future losses, but only indicators of possible losses under normal market conditions at a given confidence level.
Commodity Price Risk
Volatility in the wholesale power generation markets provides uncertainty in the future performance and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: seasonal changes in demand; weather conditions; available regional load-serving supply; regional transportation and (or) transmission availability; market liquidity; and federal, regional and state regulations.
Within the parameters of our risk policy, we generally utilize conventional first lien, exchange-traded and over-the-counter traded derivative instruments, and in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Margin Sensitivities
The table below displays sensitivities for changes in projected margins based upon consistent changes in power prices across our entire portfolio. Actual price changes may differ by market and commodity, which could result in different results than displayed.
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The base case for these sensitivities incorporates market prices, our economic hedge position, expected PTC, and expected generation (including cost inputs and planned outages) as of December 31, 2023 (Successor):
| Sensitivity Range | 2024 Margin Effect (a) | 2025 Margin Effect (a) | |||||||||||||||||||||||||||||||||
| Low | High | Low | High | Low | High | ||||||||||||||||||||||||||||||
| Change in power price per $/MWh (b) | $ | (5.00) | $ | 5.00 | $ | (55) | $ | 65 | $ | (98) | $ | 107 | |||||||||||||||||||||||
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(a)Margin price sensitivities hold constant certain microeconomic and macroeconomic factors that may impact our margin and the impact of changes in prices; value in millions and includes value of PTC.
(b)Power price sensitivities hold market heat rate constant for each month; therefore, gas prices are adjusted accordingly.
Interest Rate Risk
Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
The following table displays the net fair value of interest rate swaps (including accrued interest, if applicable) outstanding at December 31, 2023 (Successor):
| Notional Exposure | Asset (Liability) | 10% Adverse Movement (a) | Maturities Through | ||||||||||||||||||||
| Interest rate swaps | $ | 290 | $ | (5) | $ | (3) | 2026 | ||||||||||||||||
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(a)Effect of a 10% adverse interest rate movement decreases assets or increases liabilities, as applicable, which could result in an asset becoming a liability.
Additionally, we are exposed to a potential increase in interest expense and to changes in the fair value of debt. The estimated impact of a 10% adverse movement in interest rates at December 31, 2023 (Successor) would have caused a $6 million increase in interest expense and a $53 million increase in the fair value of debt compared with a non-material increase in interest expense and a $11 million increase in the fair value of the debt at December 31, 2022 (Predecessor).
Credit Risk
Credit risk is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due causing a financial loss to Talen. Financial assets are considered credit-impaired when facts and circumstances reasonably indicate an event has occurred where the carrying value of the asset will not be recovered through cash settlement. Such events may include deterioration of a customer’s or counterparty’s financial health leading to a probable bankruptcy or reorganization, a breach of contract, or other economic reasons. Credit risk is inherent within cash and cash equivalents, restricted cash and cash equivalents, derivative instruments, and primarily within accounts receivable. The maximum amount of credit exposure associated with financial assets is equal to the carrying value. The carrying values of derivative instruments consider the probability that a counterparty will default when contracts are out of the money (from the counterparty’s standpoint). Additionally, a credit impairment is recognized on receivables when facts indicate a high probability that amounts owed to Talen will not be paid. Such allowances are presented as “Accounts receivable, net” on the Consolidated Balance Sheets. As of December 31, 2023 (Successor) and December 31, 2022 (Predecessor), there were no material credit impairments.
We maintain credit procedures with respect to counterparty credit (including requirements that counterparties maintain specified credit standards) and require other assurances in the form of credit support or collateral in certain circumstances in order to limit counterparty credit risk. However, we have concentrations of suppliers and customers among electric utilities, financial institutions, marketing and trading companies and the U.S. government. These
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concentrations may impact our overall exposure to credit risk, positively or negatively, as counterparties may be similarly affected by changes in economic, regulatory or other conditions.
See Note 5 in Notes to the Annual Financial Statements for additional information on credit risk.
Investment Price Risk
In accordance with certain NRC requirements, Susquehanna maintains trust funds comprised of restricted assets that were established in order to fund its proportional share of Susquehanna’s future decommissioning obligations. As of December 31, 2023 (Successor), the NDT was invested primarily in domestic equity securities, fixed-rate, fixed-income securities and short-term cash-equivalent securities and is presented as fair value on the Consolidated Balance Sheets. The mix of securities is intended to provide returns sufficient to fund Susquehanna Nuclear's decommissioning and to compensate for inflationary increases in decommissioning costs. However, the equity securities included in the NDT are exposed to price fluctuation in equity markets, and the values of fixed-rate, fixed-income securities are primarily exposed to changes in interest rates. We actively monitor the investment performance and periodically review the asset allocation in accordance with our nuclear decommissioning trust investment policy statement.
As of December 31, a hypothetical 10% increase in interest rates and a 10% decrease in equity values would have resulted in:
| Successor | Predecessor | |||||||||||||
| 2023 | 2022 | |||||||||||||
| Estimated increase (decrease) in the fair value of NDT assets | $ | (91) | $ | (85) | ||||||||||
See Notes 9 and 14 in Notes to the Annual Financial Statements for additional information regarding the Susquehanna NDT.
Cybersecurity
Talen maintains policies and controls designed to identify, assess, manage, mitigate, and respond to cybersecurity threats. Our cybersecurity risk mitigation strategy is established at board management level and is implemented by the business units in which the potential threats may occur. The Company maintains business continuity and disaster recovery plans that are expected to be deployed in response to a significant cyberattack.
Cybersecurity and Risk Mitigation
Our cybersecurity policies incorporate standards and (or) recommendations issued by the National Institute of Standards and Technology, the International Organization for Standardization, the NRC, and NERC. These standards: (i) provide guidelines for organizations to establish, implement and improve their information security management system; (ii) form a framework for an intelligence-driven multilayered risk mitigation strategy which incorporates advanced security measures; and (iii) attempt to protect digital computer and communications systems and equipment against cyberattacks that would materially and adversely affect our operational safety, security, or emergency preparedness. We deploy, configure, and maintain technologies designed to enforce security policies, detect and protect against cybersecurity threats, and help safeguard our material assets.
Our digital and cybersecurity controls are augmented with physical controls such as security systems, security site plans, security systems monitoring, and access control to mitigate physical security risks at our facilities. Talen’s procurement policies and organizational controls require vendors to be assessed and vetted, with an enhanced protocols on purchases and installations involving nuclear equipment. Additionally, cybersecurity assessments and monitoring are performed on significant third-party service providers. This process involves reviewing the supplier's available cybersecurity controls and test of controls results. Additionally, where warranted, we request a detailed cybersecurity questionnaire from our vendors to assess the vendor's practices and preparedness in addressing cyber threats.
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Through a multi-functional coordinated effort, Talen assesses and mitigates cybersecurity risks based on likelihood of the risk and potential impact to the Company and its stakeholders. Such risks are identified using tactical, operational and compliance-based approaches. Each risk and associated consequences of each risk, should they materialize, are evaluated using likelihood of occurrence considering existing controls.
The relevant operational employees, corporate employees, as well as certain contractors are each required to complete cybersecurity awareness, technical, and specialized training programs. Mandatory technical training is provided to personnel performing, verifying, or managing cybersecurity activities. Specialized training is required for individuals who have programmatic and procedural cybersecurity authority to develop the necessary skills and knowledge to execute a cyber defensive strategy. Responses for cybersecurity incidents are implemented through qualifications, training, and mandatory annual exercises, cyber crisis response simulations, and annual training exercises to assess the Company’s ability to adapt to information and operational technology threats.
We conduct regular monitoring of our environment either directly or through third-party organizations working on our behalf. In addition to the real-time monitoring, third parties conduct periodic vulnerability assessments on protective systems. To measure its non-nuclear cybersecurity framework maturity, Talen utilizes internal and external audits and assessments, vulnerability testing, and governance processes over outsourced service providers. The nuclear cybersecurity program is inspected biennially by the NRC and assessed annually by quality assurance audit. Nuclear vulnerability management is implemented in collaboration with Department of Homeland Security and the Cybersecurity & Infrastructure Security Agency.
We have an established Cyber Incident Response Plan (CIRP) to manage cybersecurity incidents. CIRP is structured to respond to and manage the effects of cyber events and, if necessary, includes steps for notifying the applicable regulatory and government authorities. Under the CIRP, cybersecurity incidents are escalated based on materiality throughout our business to the Senior Vice President of IT, Chief Administrative Officer, Chief Nuclear Officer, Chief Fossil Officer, General Counsel, Chief Financial Officer, Chief Executive Officer and (or) our Board of Directors. These escalation protocols are in place to ensure that relevant stakeholders are informed promptly to enable appropriate mitigation efforts, regulatory notifications, and (or) cooperation with authorities as necessary.
Governance
The Audit Committee of the Board of Directors oversees Talen’s cybersecurity risk exposures and the steps taken by management to monitor and mitigate cybersecurity risks. Periodic reports are given by senior management to the Committee about material cyber events and our mitigation efforts. Cybersecurity risks are reviewed by the Board of Directors, at least annually.
The senior executive team is responsible for coordination of cybersecurity across the Company. Our cybersecurity teams, which include professionals certified with Certified Information Systems Security Professional credentials, are responsible for assessing and managing the Company’s cyber risk management protocols in their respective areas regarding the prevention, detection, mitigation, and remediation of material cybersecurity incidents as well as communicating risk management matters to key stakeholders. The cybersecurity teams have experience selecting, deploying, and operating cybersecurity technologies, initiatives, and processes, and relies on threat intelligence as well as other information obtained from governmental, public, or private sources. In coordination with Talen senior management, the SVP of IT and the relevant cybersecurity teams review risk management strategy to mitigate cybersecurity risks. Additionally, as needed, the Company engages specialists, consultants, auditors, and (or) other third parties to assist with assessing, identifying, and managing cybersecurity risks.
While cybersecurity incidents have not materially affected the Company, its business strategy, results of operations or financial condition to date, no assurance can be provided that the Company would not be subject to a significant cyber incident in the future. See Risk Factors for additional information on the Company’s cybersecurity risks.
Critical Accounting Policies and Estimates
Financial statements prepared in conformity with GAAP require the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i)
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the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. We believe the following areas contain the most significant accounting judgments, the highest levels of subjectivity, or relate to uncertain matters that are susceptible to material changes in estimates that are critical to understanding the Company’s financial results. Due to such inherent uncertainties, actual results may differ substantially from estimates and (or) estimates may change materially in periods where new information becomes known. Management develops these estimates based on best available information, historical experience, and subject matter experts. See Note 2 in Notes to the Annual Financial Statements for additional information on accounting policies for each of the following topics.
Derivative Instruments
“Derivative instruments,” which assist with commodity-price management by our commercial function, is presented on our Consolidated Balance Sheets at fair value, either as an asset or liability, and are comprised primarily of power and natural gas commodity contracts. Derivative identification is challenging. While a conventional financially settled contract, such as swap or option, generally contains standard terms that facilitate its identification as a derivative instrument, judgment is required to determine whether contracts to buy or sell commodities with physical delivery or contracts that contain certain embedded settlement or fluctuating price features meet the definition of a derivative instrument. This judgment typically includes, among other things, an evaluation of the contract, its expected cash flows and the activity levels of its principal market. Additionally, judgment is required to determine if a commodity contract intended for physical delivery meets an allowable exemption prior to accounting for its income effects under the accrual accounting method rather than at fair value. This typically includes assumptions regarding the probability of physical delivery and the quantities used in normal business activities.
As the Company’s derivative contracts generally settle within future time periods supportable by commodity exchange markets and the frequent occurrence of commercial transactions, the majority of our derivative contracts utilize quoted prices in active markets or other observable market inputs to determine fair value. However, such prices are expected to be subject to volatility between periods based on weather, local market events, macroeconomic trends, and (or) other events and factors. Accordingly, changes in fair value for contracts identified as derivatives may result in material changes to unrealized gains or losses presented on the Consolidated Statements of Operations between periods. Changes in fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments,” as a component of either “Operating Revenues” or “Fuel and energy purchases” on the Consolidated Statements of Operations, in a consistent manner with the presentation of its realized net gains or losses.
See Note 5 in Notes to the Annual Financial Statements for additional information on derivative instruments.
Nuclear Decommissioning Asset Retirement Obligations
We have significant legal obligations associated with Susquehanna’s decommissioning. Susquehanna’s Unit 1 and Unit 2 licenses, if not renewed, will expire in 2042 and 2044, respectively, at or before which time the units will shut down.
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Judgment is required to make reasonable ARO assumptions regarding the range of likely outcomes, for cost estimates, as these obligations are not expected to be paid until years or decades in the future, and potentially many years after shutdown. Inflation rates and discount rates may be subject to revision until the ARO settlement date. As such, changes in assumptions to the range of likely outcomes could result in different cash outlay for AROs at the settlement date than the current carrying value of the ARO on our Consolidated Balance Sheets. Susquehanna periodically assesses its ARO through third-party engineering studies in order to determine expected scope, costs, and timing of decommissioning activities. Generally, its decommissioning cost study is updated every 7 years. As part of the annual cost study update process, we and the third-party engineering firm evaluate cost projections based on the latest engineering techniques and the latest information which incorporates nuclear plant retirements in the industry. We incorporate the results of the study as well as our experience, knowledge and professional judgment to the specific characteristics of Susquehanna’s decommissioning plan to update the carrying value of the ARO.
AROs are recognized at fair value at the time of installation and as an increase to property, plant, and equipment. The income effect of AROs is generally presented as “Depreciation, amortization and accretion” on our Consolidated Statements of Operations through the expected ARO settlement date. However, for an asset that has a fully depreciated property, plant, and equipment carrying value, revisions in ARO estimates have an immediate effect in earnings. Revisions to the estimated ARO are presented as “Other operating income (expense), net” on our Consolidated Statements of Operations.
See Note 11 in Notes to the Annual Financial Statements for additional information on AROs.
Recoverability of Long-Lived Assets
Property, plant, and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate the carrying amount of the asset group may not be recoverable. Judgment exists in identifying these events. In certain instances, the events could be external to us and may include, among other events, changes in the economic environment, such as a decrease in the market price of an asset, significant changes to market rules and regulations in the power markets in which we operate and changes in federal or state environmental regulations that would materially affect the cash flows of our generation fleet. In other instances, the events result from negative financial trends, physical damage to assets or decisions of management regarding strategic initiatives, such as sales of assets, generation facility retirements or significant changes in planned capital expenditures or operating costs.
Individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. There is significant judgment in identifying the lowest level of independent cash flows in the merchant power market given certain groups of our generation facilities participate in the same market. In determining the appropriate level of aggregation, we considered the manner in which we make economic decisions regarding the revenue and commercial activities of the generation facilities and the manner in which we make operational and maintenance decisions. Accordingly, we generally aggregate assets for impairment at the reporting unit level, unless there are additional facts and circumstances present which indicate that an asset should be tested for recoverability on a standalone basis. Periodically, we evaluate whether conditions such as changes in market conditions, regulatory changes, or other events require a change in aggregation.
If there is an indication the carrying value of an asset group may not be recovered, we review the expected future cash flows of the asset group. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the asset group is written down to its estimated fair value. Fair value for property, plant, and equipment may be determined by a variety of valuation methods including third-party appraisals, market prices of similar assets, and present value techniques. However, as there is generally a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates which are believed to be consistent with those used by principal market participants. The estimated cash flows and related fair value computations consider all available evidence as of the date of the review such as estimated future generation volumes, capacity prices, energy prices, operating costs, and capital expenditures.
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Impairment charges are presented on our Consolidated Statements of Operations in the period in which the impairment determination is made.
See Note 10 in Notes to the Annual Financial Statements for additional information on recognized impairments.
Postretirement Benefit Obligations
Our subsidiaries sponsor postemployment benefits that include defined benefit pension plans and health and welfare postretirement plans (other postretirement benefit plans). Accounting for defined benefit pensions and other postretirement benefits involves significant estimates to determine projected benefit obligations and company contribution requirements, which inherently require assumptions be made regarding many uncertainties. Such uncertainties include discount rates, expected return on assets, expected wages for participants at retirement, estimated retirement dates, mortality rates and future health care costs. Over a period of time, we are required to fund all vested benefits for postretirement defined benefit pension plans through plan assets, investment returns or contributions to the plans.
Actuarial assumptions required under GAAP to determine the projected benefit obligations and actuarial assumptions required under the Employee Retirement Income Security Act to determine contribution assumptions differ in their objectives. Actuarial assumptions regarding projected benefit obligations under GAAP affect the net periodic defined benefit cost presented within our Consolidated Statements of Operations. Actuarial assumptions used in the computation to estimate required contributions to the plan affect funding requirements over a period of time.
We are responsible for the estimates regarding our postemployment benefits. However, we engage actuarial firms, who apply professional standards in the determination of the judgmental assumptions for plan contributions, to estimate both the contribution requirements for postemployment benefits and the associated projected benefit obligations under GAAP.
Projected benefit obligations are particularly sensitive to expected return on plan assets and the discount rate. The expected return on plan assets is the estimated long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs. The discount rate is used to compute the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. Please see Note 15 in Notes to the Annual Financial Statements for the weighted-average assumptions used for discount rate and expected return on plan assets for all plans.
A variance in the discount rate or expected return on plan assets could have a significant impact on postretirement benefit obligations and annual net periodic pension costs. The following table displays the estimated increase / (decrease) of a 1% increase and a 1% decrease in the discount rate and expected return on plan assets on the postretirement benefit obligation and net periodic pension cost as of December 31, 2023.
| Sensitivity | ||||||||||||||
| Actuarial Assumption | 1% Increase | 1% Decrease | ||||||||||||
| Discount rate | ||||||||||||||
| Postretirement benefit obligation | $ | (131) | $ | 157 | ||||||||||
| Net periodic pension cost | 5 | (5) | ||||||||||||
| Expected return on plan assets | ||||||||||||||
| Net periodic pension cost | (10) | 10 | ||||||||||||
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Income Taxes
Significant management estimates and judgments are involved to determine the provision for income taxes, deferred tax assets and liabilities and valuation allowances.
An assessment is performed on a quarterly basis to determine the likelihood of realizing deferred tax assets. This assessment includes evaluating positive and negative evidence, such as: (i) creation and timing of future taxable income associated with the reversal of deferred tax liabilities in excess of deferred tax assets; (ii) expiration of net operating losses; and (iii) historical amounts of income or losses. Based on this assessment, valuation allowances are utilized to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not to be realized in future periods.
Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, forecasted financial conditions and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 7 in Notes to the Annual Financial Statements for additional information on income taxes.
Recent Accounting Pronouncements
See Note 2 in Notes to the Annual Financial Statements for a description of recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted.
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BUSINESS
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. See “Prospectus Summary—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 to AWS, the Cumulus Data Campus adjacent to our zero-carbon Susquehanna nuclear facility 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 “Prospectus Summary—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 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 “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale.” We also believe Susquehanna may further benefit from 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.
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.
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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 “—Our Properties.”
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.
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.
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 “Prospectus Summary—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 “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale” for additional information. When measured by the operational and safety standards
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adopted by the 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 “Prospectus Summary—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 “Prospectus Summary—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
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otherwise, and commercially managing our highly flexible gas fleet to capture extrinsic value. We also believe we 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.
Our Properties
As of March 31, 2024, after giving effect to the ERCOT Sale, our power generation facilities are as follows:
_________________
(1)Electric generation capacity (summer rating) is based on factors, among others, such as operating experience and physical conditions, which may be subject to revision.
(2)See Note 10 in Notes to the Annual Financial Statements for additional information regarding jointly owned facilities.
(3)Coal-fired electric generation is restricted during the EPA Ozone Season, which is May 1 to September 30 of each year.
(4)Coal-fired electric generation is required to cease at Montour by December 2025 and at Brunner Island, Keystone, and Conemaugh by December 2028, with an earlier retirement of coal at the wholly owned Montour and Brunner Island facilities at the Company’s election.
(5)See “—Regulatory Matters” for additional information on the Brandon Shores and Wagner deactivations. Filed Reliability-Must-Run cost-of-service rate schedules in April 2024.
Our Segments
Talen’s reportable segments are based upon the market areas in which our generation facilities operate and reflect the manner in which our chief operating decision makers review results and allocates resources. Adjusted
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EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision makers.
Our reportable segments are engaged in electricity generation, marketing activities, commodity risk and fuel management within their respective RTO or ISO markets. The segments include:
•PJM – a reportable segment that includes the operating and marketing activities within the PJM market. PJM is comprised of Susquehanna and Talen’s natural gas and coal generation facilities located within the PJM market; and
•ERCOT and WECC – a reportable segment that includes the operating and marketing activities within the ERCOT market for the operations of Talen’s Texas power generation facilities, and the operating and marketing activities for Talen Montana’s proportionate share of the Colstrip Units. We have determined it appropriate to aggregate results from these markets into one reportable segment, based on a combination of size and economic characteristics.
We completed the ERCOT Sale in May 2024. 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.
Our Key Markets and Revenue Streams
Following the ERCOT Sale, the substantial majority of our generation capacity is located in, and revenues derived from, PJM. The remainder of our generation capacity is in WECC and ISO-NE. For additional detail regarding the market location of each of our facilities, please see “—Our Properties.”
Operating revenues primarily consist of capacity revenues, energy/ancillary revenues and unrealized gain (loss) on derivative instruments. In PJM, we sell capacity through forward PJM Base Residual Auctions and, to the extent we are unable to sell capacity through the PJM Base Residual Auctions we may sell uncleared capacity through PJM Incremental Auctions or bilateral contracts. We also earn capacity revenues in ISO-NE. We sell energy into the spot markets in both PJM and ISO-NE, and we also enter into bilateral agreements with power purchasers for the sale of energy from our generation fleet in PJM and WECC. For a discussion of our commercial optimization strategy, please see “—Our Commercial Risk Management Strategy” below.
PJM
PJM is an RTO that coordinates the movement and sale of wholesale electricity in all or parts of 13 states and the District of Columbia. As of March 31, 2024, it is the largest competitive wholesale power market in the United States, coordinating the dispatch of approximately 180,000 MW to more than 65 million people. The current mix of generating capacity within PJM is diverse, with a significant number of nuclear, natural gas and coal power generation facilities providing approximately 90% of its available capacity as of March 31, 2024. As is the case in many markets in the United States, generating capacity within PJM is transitioning from a coal-dominated generation base to a mix that incorporates larger amounts of natural gas and renewable units, driven in part by current and impending EPA regulations.
PJM benefits from a combination of stable demand growth, liquid trading hubs, limited energy import capacity and a wide range of available market products. Generation owners in PJM may earn energy, capacity and ancillary service revenues. The PJM energy market consists of day-ahead and real-time markets. The day-ahead market is a forward market in which hourly prices are calculated for the next operating day based on offers, bids and bilateral obligations. The real-time market is a spot market in which energy is continuously bought and sold based on actual grid operating conditions.
The PJM RPM is intended to ensure that resources are available when needed to keep the power grid operating reliably for customers. Under the PJM RPM, PJM conducts a series of capacity auctions. Most capacity is procured in the PJM Base Residual Auction, typically conducted three years prior to the start of the applicable period to which
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a capacity commitment in PJM applies (which typically runs from June 1 to May 31), to secure commitments from capacity resources, intended to be held in May of each year for the sale of generating capacity. In these auctions, capacity prices are set based on supply and demand fundamentals and are influenced by factors, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, RTO demand forecasts and reserve margin targets, as well as adjustments to the PJM MOSC (the maximum price at which certain units can bid into the market) as determined by the PJM IMM and/or PJM. See “—Regulatory Matters” for additional information on ongoing market reforms in PJM.
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 future PJM Base Residual Auctions have been delayed and are expected to be conducted as follows: 2025/2026 PJM Base Residual Auctions in July 2024, 2026/2027 PJM Base Residual Auctions in December 2024, 2027/2028 PJM Base Residual Auctions in June 2025 and 2028/2029 PJM Base Residual Auctions in December 2025. Although PJM has established dates for the next four auctions, there is no guarantee that the auction will take place on those dates or at all. At this time, Talen cannot fully predict the impacts of PJM’s reforms on its operations and liquidity.
Our Commercial Risk Management Strategy
Our commercial optimization strategy is focused on hedging commodity price volatility within appropriate risk tolerances while providing stable cash flow generation and preserving forward margin. We employ a variety of commercial, physical and financial instruments to manage risk and optimize the value of our assets. In some cases, we use a portfolio approach to manage risks, such as those associated with capacity and ancillary offerings. 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 which limits the use of collateral posting requirements. It also factors in the Nuclear PTC related to Susquehanna, which may reduce hedging requirements and therefore collateral needs. We use a variety of financial instruments to hedge our generation, including but not limited to fixed price swaps, options, and financial transmission rights (“FTRs”)/congestion revenue rights (“CRRs”), as further discussed in the table below. 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.
| Type | Instruments | Strategy | ||||||||||||
| Power | •Fixed swaps •Options •FTRs / CRRs | •Preserve intrinsic value while creating opportunities to capture extrinsic value •Cover expected generation •FTRs / CRRs critical for PJM assets due to transmission constraints and other factors relating to their positions on the grid | ||||||||||||
| Fuel | •Fixed swaps •Options | •Preserve intrinsic value while creating opportunities to capture extrinsic value •Cover expected generation | ||||||||||||
| Other | •Emission credits, including RGGI | •Emission expenses included in dispatch costs •Generally, cover emission exposure as we hedge or generate obligation | ||||||||||||
Fuel Supply
Our power generation assets are advantaged by significant fuel diversity, including nuclear, natural gas, coal, oil and various facilities capable of utilizing multiple fuel sources. For additional detail regarding the fuel capabilities of each of our facilities, please see “—Our Properties.”
Nuclear
Susquehanna has a portfolio of supply contracts for uranium, conversion, enrichment and fabrication with varying expiration dates. 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. Susquehanna
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has an on-site spent fuel storage facility employing dry cask fuel storage technology, which, together with the spent fuel pools, has the capacity to accommodate discharged SNF. We will continue to expand this spent fuel storage facility in phases to accommodate additional SNF and, assuming appropriate approvals are obtained, we expect such future expansion phases will accommodate all of the SNF expected to be discharged by Susquehanna through 2044, the current licensed life of unit 2.
Natural Gas and Oil
We manage our natural gas and oil supply utilizing a combination of contracted purchases, spot market purchases and on-site storage for the commodities and pipeline capacity. The amount and duration of contracted purchases vary due to several factors, including fuel availability, economic considerations and generation facility location on the pipeline grid, with a significant portion of our natural gas supply needs being satisfied through short-term transactions on a spot basis. Oil is generally supplied from on-site inventory and replenished through purchases on the spot market. The price-risk associated with these transactions is managed via financial hedges.
Coal
We actively manage our coal requirements by purchasing coal from mines located in central and northern Appalachia for our generation facilities located within PJM and from a mine located adjacent to the Colstrip generation facility. Reliability of coal deliveries can be affected from time to time by a number of factors, including fluctuations in demand, coal mine production issues and other supplier or transporter operating difficulties. Coal inventory is maintained at levels estimated to be necessary to avoid operational disruptions at coal-fired generation units. Additionally, long-term supply contracts support adequate levels of coal inventory and are augmented with spot market purchases, as needed. We plan to eliminate the use of coal at our wholly owned generation facilities through either fuel conversion or plant retirement. For more information, see “—Our Platform—Carbon Deleveraging.”
Restructuring and Financing Transactions
Due to the rapid and sustained increases to wholesale natural gas and power prices in mid-2021, our commercial counterparties and commodity exchanges party to certain hedge transactions required us to provide elevated levels of collateral for our hedging positions. However, because we are generally required to collateralize hedges that settle in future delivery periods but do not receive settlements for electric generation until delivery, the heightened collateral posting requirements resulted in lower available cash and liquidity to operate our business. As a result, we concluded that commencing the Restructuring was necessary to allow us to, among other things, strengthen our financial position and provide additional liquidity to fund our operations and protect our equity investments in projects supporting our plans to transition to sustainable power generation. Accordingly, 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. 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. For additional information on the Restructuring, Plan of Reorganization and Exit Financings, see “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources” and Notes to the Annual Financial Statements included elsewhere in this prospectus.
Competition
Since the early 1990s, there has been increased competition in U.S. energy markets because of federal and state competitive market initiatives. PJM is a competitive market and has, from time to time, considered new market rules, while some states have considered re-regulation measures that could result in more limited opportunities for competitive energy suppliers.
The power generation business is a regional business that is diverse in terms of industry structure and fundamentals. Demand for electricity may be met by generation capacity based on several competing generation technologies, such as natural gas-fired, coal-fired or nuclear generation, as well as power generation facilities fueled by alternative energy sources, including hydroelectric power, synthetic fuels, solar, wind, wood, geothermal, waste
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heat and solid waste sources. Talen faces competition in wholesale markets from other suppliers of available energy, capacity and ancillary services. Competition is affected by electricity and fuel prices, congestion along the power grid, subsidies provided by state and federal governments for new generation facilities and certain existing generation facilities (including facilities that might otherwise retire), new market entrants, construction of new generation assets, technological advances in power generation, the actions of environmental and other regulatory authorities and other factors. Talen primarily competes with other electricity suppliers based on our ability to aggregate generation supply at competitive prices from different sources and to efficiently manage fuel supply by utilizing transportation from third-party pipelines and transmission from electric utilities, ISOs and RTOs. Competitors in wholesale power markets include regulated utilities, industrial companies, non-utility generators, competitive subsidiaries of regulated utilities and other energy marketers.
Seasonality
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, prior to the ERCOT Sale, during the summer in Texas.
We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance requirements of our facilities and the terms of bilateral contracts to purchase or sell electricity. The largest recurring maintenance project is the annual spring refueling outage at Susquehanna.
Insurance
Our assets may experience physical damage as a result of an accident or natural disaster. These hazards can also cause personal injury or loss of life, severe damage to and destruction of property and equipment, pollution or environmental damage and suspension of operations. We maintain our own general liability, product liability, property, business interruption, workers compensation and pollution liability insurance policies, among other policies, at varying levels of deductibles and limits that we believe are reasonable and prudent under the circumstances to cover our operations and assets; however, we cannot provide any assurance that our insurance will be sufficient or effective under all circumstances and against all hazards or liabilities to which we may be subject. If we do have insurance coverage, the amount recoverable under the applicable insurance policy may be less than the related impact on revenue or not cover all potential consequences of an incident. In addition, we may be subject to a large deductible, maximum cap or aggregate policy limits. A successful claim for which we are not fully insured could adversely affect our results of operations. Further, due to rising insurance costs and changes in the insurance markets, we cannot provide any assurance that our insurance coverage will continue to be available at economic rates. Any losses not covered by insurance could have a material adverse effect on our business, financial condition and results of operations. We will continue to periodically evaluate our policy limits and retentions as they relate to the overall cost and scope of our insurance program.
Nuclear Insurance
The Price-Anderson Act is a United States federal law which governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of March 31, 2024 (Successor), the liability limit per incident is $16.2 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers (approximately $500 million in coverage), with the remainder covered by an industry retrospective assessment program.
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As of March 31, 2024 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $332 million per incident, payable at a maximum of $49 million per year.
Additionally, Susquehanna purchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna is a member. As of March 31, 2024 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $2.0 billion and non-nuclear property damage losses up to $1.0 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $45 million as of March 31, 2024 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Legal Matters
Talen is involved in certain legal proceedings, claims and litigation. While we believe that we have meritorious positions and will continue to defend our positions vigorously in these matters, we may not be successful in our efforts. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal proceedings and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding the matters specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial.
Pending Legal Matters
Montana Hydroelectric Litigation. Talen Montana is a defendant in litigation in the U.S. District Court for the District of Montana relating to its past ownership and operation of hydroelectric generation facilities in Montana, which were sold to NorthWestern in November 2014 (the “Montana Hydroelectric Sale”). In connection with the sale, Talen Montana agreed to retain liability with respect to this litigation, if any, attributable to time periods prior to closing of the sale.
The lawsuit was originally filed in 2003 and alleges that the streambeds underlying the facilities are owned by the State of Montana (the “State”), and that Talen Montana owes the State compensation for the use of the streambeds. In August 2023, the court held in favor of Talen Montana with respect to streambed segments underlying six of the seven facilities. Regarding the one streambed segment that the court found belongs to the State, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. The State has appealed this holding to the U.S. Court of Appeals for the Ninth Circuit. Damages and defenses related to this proceeding will be addressed in a future adjudication. Nonetheless, because Talen Montana’s liability on all claims asserted by the State was discharged under the Plan of Reorganization, Talen Montana does not expect any further liability from this matter.
ERCOT Weather Event Lawsuits. Beginning in March 2021, the former Talen subsidiaries that at the time owned the Barney Davis, Nueces Bay and Laredo generation facilities were sued in multiple Texas courts along with many other market participants in ERCOT. See Note 17 in Notes to the Interim Financial Statements for information on Talen’s sale of ERCOT generation assets. The lawsuits were consolidated into a multi-district litigation pre-trial court (“MDL”). In these suits, the plaintiffs allege, among other things, that they suffered loss of life, personal injury and/or property damage due to the defendants’ failure to properly prepare their facilities to withstand extreme winter weather and other operational failures during Winter Storm Uri in February 2021. Numerous insurance company plaintiffs also seek to recover payments to policyholders for damage to residential and commercial properties caused by the storm. The plaintiffs seek unspecified compensatory, punitive and other damages. In January 2023, the MDL court denied a motion to dismiss filed by the generation defendants. The generation defendants sought appellant review of the decision, and, in December 2023, the Texas First Court of Appeals granted the generation defendants’ request for mandamus relief and ordered dismissal of the claims against the generation defendants. Plaintiffs have
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filed a motion seeking rehearing en banc with the First Court of Appeals. If unsuccessful, plaintiffs are expected to petition the Texas Supreme Court to review the decision. Plaintiffs asserting prepetition Winter Storm Uri claims are limited to recovering any damages solely from the Talen defendants’ insurers pursuant to the Plan of Reorganization. Certain plaintiffs filed lawsuits asserting Winter Storm Uri claims after commencement of the Restructuring. If any of these post-commencement plaintiffs did not receive effective notice of the Restructuring under applicable bankruptcy law, they may not be subject to the terms of the Plan of Reorganization. Talen cannot predict the outcome of this matter for any such claims or its effect on Talen, which has retained these potential liabilities.
In June 2021, TEC intervened in five cases in which certain market participants are challenging the validity of two PUCT orders directing ERCOT to ensure energy prices were at their maximum of $9,000 per MWh during Winter Storm Uri. One case has since been dismissed, one case is pending in the Texas Third Court of Appeals and two cases are pending in State District Court in Travis County, Texas. In March 2023, the Third Court of Appeals issued an opinion in Luminant v. PUCT that, in part, reversed and remanded the PUCT orders directing ERCOT to ensure prices were at their maximum of $9,000 per MWh during Winter Storm Uri. The PUCT (along with TEC and others) filed petitions for review with the Texas Supreme Court, which were granted in September 2023. Talen cannot predict the timing or outcome of these cases or their ultimate effect on the PUCT’s orders during Winter Storm Uri; however, changes in one or more of the PUCT’s orders could have a material adverse effect on Talen’s results of operations and liquidity.
Pension Litigation. In November 2020, four former Talen employees filed a lawsuit in the U.S. District Court for the Eastern District of Pennsylvania against TES, TEC, the TERP, the TERP committee, and (as amended) ten former retirement plan committee members alleging that they are owed enhanced benefits under the TERP. In September 2023, the parties reached a tentative agreement to settle all claims on a class-wide basis, inclusive of attorneys’ fees, in exchange for $20 million, subject to negotiation of mutually acceptable definitive agreements and court approval of the final settlement. In February 2024, the parties agreed upon the definitive settlement documentation, and on June 3, 2024, the settlement was approved and will become final in July 2024 subject to appeal (if any).
We expect a portion of the settlement to be paid by the TERP with the remainder paid by the Company, net of expected insurance recoveries. The amount paid by the TERP will be the full amount of the settlement less any attorneys’ fee award approved by the court and certain expenses associated with implementing the settlement. TES, at its discretion, may elect to fund a contribution into the TERP to cover settlement payments paid by the TERP. If the settlement is not consummated and the plaintiffs subsequently prevail on their claims, a material adverse judgment could have an adverse effect on the TERP’s assets as well as Talen’s results of operations and liquidity. No assurance can be provided that the final settlement agreement will be consummated as expected or if at all. Accordingly, we cannot predict the outcome of this matter or its effect on Talen if the settlement is not consummated as expected or if the matter is litigated to conclusion. As of March 31, 2024, the settlement amounts agreed to by the parties and expected insurance recoveries are presented on the Consolidated Balance Sheets.
Railroad Surcharge Litigation. In September 2019, TES and certain of its subsidiaries filed suit in the U.S. District Court for the Southern District of Texas, alleging that the four major railroads in the United States violated U.S. antitrust laws by conspiring during the periods from July 2003 through December 2008 to use fuel surcharges as a means to raise price for rail freight shipments. Numerous other plaintiff shippers in various jurisdictions throughout the United States have filed similar lawsuits. The Talen plaintiffs claim that they paid higher rail freight shipment rates than they otherwise would have paid absent the alleged conspiracy and seek treble damages under the antitrust laws. The litigation has been consolidated in the District Court for the District of Columbia with similar lawsuits under the multi-district litigation rules. At this time, Talen cannot predict the outcome of this matter.
Spent Nuclear Fuel Litigation. Substantial uncertainty exists regarding the nuclear industry’s permanent disposal of spent nuclear fuel (“SNF”). Federal law requires the U.S. Government to provide for the permanent disposal of commercial SNF and prior to May 2014, nuclear generation facility 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. Talen cannot predict if or when the U.S. Government will increase this fee in the future, which could result in significant additional costs to Susquehanna.
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In addition, in May 2011, Susquehanna entered into an agreement with the U.S. Government to settle the U.S. Government’s breach of contract to accept and dispose of SNF by the statutory deadline. The settlement agreement, which has been extended four times, requires the U.S. Government to reimburse certain costs to temporarily store SNF at Susquehanna and requires Susquehanna to waive any claims against the U.S. Government for costs paid or injuries sustained related to temporarily storing SNF. For the period from May 18 through December 31, 2023 (Successor), and the years ended December 31, 2022 (Predecessor), and December 31, 2021 (Predecessor), Susquehanna received reimbursements of $24 million, $7 million, and $20 million for such costs. In May 2023, this agreement was extended through the end of 2025. We cannot be certain that subsequent amendments will extend these arrangements beyond 2025.
Resolved Legal Matters
Talen Restructuring. Upon Emergence in May 2023, pursuant to the Plan of Reorganization, the Debtors’ liability was discharged for certain claims arising prior to commencement of the Restructuring. The Debtors may still be liable for certain post-petition claims, including claims arising after commencement of the Restructuring, claims asserted against Talen Energy Corporation, which are unimpaired under the Plan of Reorganization, and claims asserted by parties that did not receive notice of the Restructuring under applicable bankruptcy law. We will continue to defend our positions against any such claims. See Note 3 in Notes to the Annual Financial Statements for additional information on the Restructuring.
Kinder Morgan Litigation. In June 2021, Kinder Morgan filed a suit in Texas state court against Talen Energy Marketing, Nueces Bay and affiliates of Texas Eastern Transmission and NextEra. In the suit, Kinder Morgan alleged, among other things, that Talen agreed to purchase natural gas from it during Winter Storm Uri at the then-prevailing market rate. The case was removed to the Bankruptcy Court. In May 2023, Talen and Kinder Morgan agreed to a settlement in the suit. Under the terms of the settlement, Talen paid Kinder Morgan $10 million, assigned its related claims against NextEra and entered into certain long-term commercial agreements with Kinder Morgan affiliates, which included $8 million in additional settlement payments to be paid over time. In April 2024, in connection with the ERCOT Sale, Talen paid the Kinder Morgan affiliates the remaining balance of these settlement payments. During the year ended December 31, 2022, Talen recognized an $18 million charge with respect to this suit, which was presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
PPL/Talen Montana Litigation. In October 2018, the Talen Montana Retirement Plan filed a class action suit in Montana state court against PPL, its affiliates and certain officers and directors, claiming that PPL and its directors improperly made a distribution of $733 million of net proceeds from the Montana Hydroelectric Sale from Talen Montana to PPL, leaving Talen Montana without adequate funds to pay its obligations. In November 2018, PPL filed a lawsuit in Delaware Court of Chancery (the “Delaware Court”) against Talen and certain affiliates seeking, among other things, indemnity from Talen for the claims asserted in the Montana state lawsuit and a declaratory judgment that such claims asserted in the Montana state lawsuit are without merit and that Talen entities do not have standing to bring such claims. Talen Montana filed an adversary complaint against PPL and its affiliates in the Bankruptcy Court asserting claims similar to those in the Montana lawsuit. The lawsuits pending in Montana state court and the Delaware Court were consolidated with the adversary proceeding. The Talen defendants’ liability on all claims asserted by the PPL defendants, except for claims asserted against TEC, was discharged under the Plan of Reorganization.
In December 2023, Talen reached a settlement of litigation with PPL. Under the terms of the settlement agreement, PPL paid Talen Montana $115 million in cash in exchange for a full release of all claims. $11 million of the settlement amount was remitted to the general unsecured creditors trust established per the Plan of Reorganization, resulting in a gain of $104 million that is presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the year ended December 31, 2023 (Successor).
Other Legal Matters
In the normal course of Talen’s business, we are party to various legal proceedings, claims and litigation arising from current or past operations. While the outcome of these matters is uncertain, the likely results are not presently
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expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations.
Regulatory Matters
Talen is subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to: FERC; the Department of Energy; Federal Communications Commission; NRC; NERC; public utility commissions in various states in which we conduct business; and RTOs and ISOs in the regions in which we conduct business. Talen is party to proceedings before such agencies arising in the ordinary course of business and has other regulatory exposure due to new or amended regulations promulgated by such agencies from time to time. While the outcome of these regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations, although the effect could be material to our results of operations in any interim reporting period.
Susquehanna ISA Amendment. On June 3, 2024, PJM filed at FERC an Amended Interconnection Service Agreement (“Amended ISA”) executed by PJM, PPL Electric Utilities Corporation (“PPL Electric,” a subsidiary of PPL), and Susquehanna, to enable Susquehanna to decrease the amount of power it will provide to the grid and thus increase, up to 480 MW, power that can be sold and provided directly to load via transmission owned by that load and connected directly to Susquehanna (and not to the power grid). The current ISA, previously accepted by FERC and similarly approved and executed by PJM and PPL Electric, already allows Susquehanna to decrease power to the grid in order to sell and provide that power to load up to 300 MW. The increase to 480 MW was studied by PJM, which confirmed that such increase would have no reliability impacts on the grid. The Amended ISA filing by PJM requests an effective date of August 3, 2024. On June 24, 2024, Exelon Corporation and AEP filed a protest, despite the ISA not being in their service territories and despite PPL Electric’s agreement to the terms. The protest raises generic issues about the service of load behind generators and requests that FERC set the Amended ISA proceeding for hearing or, in the alternative, reject the filing. Talen believes nearly all issues raised by Exelon Corporation and AEP are not within FERC’s limited jurisdictional review and lack merit, and Talen intends to defend against them quickly and vigorously.
PJM MOPR. 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 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.
PJM Market Seller Offer Cap. In March 2021, FERC responded to complaints filed by the PJM IMM on behalf of PJM and various consumer advocates alleging that the PJM MSOC was above a competitive offer level and was, therefore, unjust and unreasonable. In September 2021, FERC issued an order requiring the PJM ACR for each generator to be determined administratively by the PJM IMM. In August 2023, the U.S. Court of Appeals for the District of Columbia Circuit denied petitions by Talen and others for review of FERC’s order. On January 12, 2024, the Electric Power Supply Association filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the August 2023 order of the D.C. Circuit. The final impacts of this order on Talen’s financial condition, results of operations and liquidity are not known at this time.
PJM Capacity Market Reform. In February 2023, the PJM Board directed PJM and its stakeholders to resolve: (i) key issues that address the energy transition taking place in PJM; and (ii) issues observed from Winter Storm Elliott. The PJM Board directive included reliability risks, risk drivers and resource availability. The stakeholder process is referred to as Critical Issue Fast Path (“CIFP”) on resource adequacy. On October 13, 2023, PJM made two filings at FERC regarding certain capacity market reforms developed through the CIFP process. On January 30, 2024, FERC accepted one of PJM’s filings, subject to the condition that PJM submit a compliance filing within 30 days. However, in February 2024, FERC rejected the second of PJM’s capacity market reform filings and approved
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a request from PJM for a 35-day delay of the Base Residual Auction. PJM has indicated that it plans to open the Base Residual Auction for the 2025/2026 delivery on July 17, 2024. At this time, Talen cannot fully predict the impacts of PJM’s reforms on its operations and liquidity.
In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delay schedules the PJM Base Residual Auctions for 2026/2027 in December 2024, for 2027/2028 in June 2025, and for 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, but the final impacts on Talen's financial condition, results of operations and liquidity are not known at this time.
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. 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. As a result, Talen incurred certain Capacity Performance penalties charged by PJM for certain generation facilities and earned bonus revenues from PJM for other generation facilities. In April 2023, 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 September 2023, PJM filed a request for FERC to approve a market-wide settlement agreement that would resolve all Winter Storm Elliot complaints, including those filed by Talen. The settlement agreement results in a 31.7% reduction in the total penalties assessed on all capacity market sellers, including Talen, as well as an additional $8 million credit to Talen. In December 2023, FERC approved the settlement agreement which reduced Talen’s aggregate penalties, net of expected bonus revenues, to an estimated $28 million. Talen recognized an estimated $48 million of aggregate net penalties, comprised of: (i) initial penalty of $33 million for the year ended December 31, 2022 (Predecessor); (ii) increase of $13 million for the period of January 1 through May 17, 2023 (Predecessor); and (iii) increase of $2 million for the period of May 18 through December 31, 2023 (Successor) as a result of revised assessments from PJM. Talen remitted aggregate penalty payments of $29 million during the periods of January 1 through May 17, 2023 (Predecessor) and May 18 through December 31, 2023 (Successor). In December 2023, the remaining liability of $19 million was derecognized as a result of the settlement.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, and hazardous and solid waste management. From time to time, in the ordinary course of our business, Talen may become involved in other environmental matters or become subject to other, new or revised environmental statutes, regulations or requirements.
It may be necessary for us to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. We may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operation and maintenance expenses, monetary fines, penalties or other restrictions, which could be material. Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.
Water and Waste. Changes made by the EPA to the EPA CCR Rule and the EPA ELG Rule in 2020 allow coal generation facility operators to request an extension to compliance deadlines if the facility commits to cessation of coal-fired generation by the end of 2028. Pursuant to Talen’s plans to cease wholly owned coal operations, Talen requested extensions for compliance under these rules for certain of its generation facilities; some have been approved and some are still under review. The most significant extension under review is the EPA CCR Rule Part A extension request for Montour Ash Impoundment 1, and a negative result would have a significant impact on the closure plan for this impoundment.
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In 2023, the EPA proposed additional changes to the ELG Rule and the CCR Rule and finalized those changes on May 9 and May 8, 2024, respectively. The new ELG Rule does not add treatment requirements to Talen’s coal-fired power generation facilities planning to cease burning coal by 2028, but it does establish discharge limits for waters collected from CCR units. Under the revised CCR Rule, the EPA has imposed new requirements on: (i) legacy CCR impoundments; and (ii) areas where CCR was disposed of or managed on land outside of regulated units at CCR facilities (subject to a minimum threshold). Furthermore, the EPA’s interpretations of the EPA CCR Rule continue to evolve through enforcement and other regulatory actions.
Talen submitted formal comments on both proposed rules citing their flaws and anticipates it will take legal action to challenge both final rules. If the revised Rules withstand expected legal challenges by power producers (including Talen), industry groups, state attorneys general, and others, the new CCR and ELG requirements could materially impact several Talen facilities. Talen is currently evaluating that potential impact. At this time, Talen cannot predict the full impact of these various rule changes on the operations of its coal-fired generation facilities and its results of operations.
Air. Since 2016, the coal-fired generation facilities in which Talen has ownership, including Brunner Island, Montour, Keystone and Conemaugh, have been the subject of various efforts under the Clean Air Act to strengthen applicable nitrogen oxides (“NOx”) emission limits. These include Section 126 petitions by downwind states, recommendations by the Ozone Transport Commission, and a ruling on Pennsylvania’s RACT2 program by the U.S. District Court for the Southern District of New York. Although the petitions and recommendations are not withdrawn, the EPA’s issuance of a federal implementation plan (the “FIP”) with short-term (RACT2) NOx limits at these plants in 2022 resulting from the court case and the EPA’s “Good Neighbor FIP” issued in June 2023 appear to have addressed open concerns by upwind states regarding NOx controls from Talen’s and other coal plants.
However, both the Pennsylvania NOx RACT2 FIP and the preceding State Implementation Plan (the “SIP”) NOx RACT are under review. The PA DEP agreed to stay the SIP standard while all the parties consider the FIP standards. The EPA FIP is in effect; however, it has since been appealed by other parties and Talen has intervened in the appellate proceeding. Lastly, in November 2022, Pennsylvania finalized its NOx RACT standards for all power generation facilities to address the EPA 2015 Ozone Standard. Affected Talen facilities have submitted permit applications demonstrating their compliance methods for the new standard. At this time, Talen cannot predict the outcome of these potential rule changes on the operations of its generation facilities and its results of operations.
To address the 2015 ozone standard, in June 2023, the EPA published the final rule covering the EPA CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” The EPA made some reductions in allowance allocations, among other changes, to minimize nitrogen oxide emissions during the Ozone Season. Texas, among other states, has received a favorable court ruling, essentially staying its participation in the updated program for 2023. Texas facilities are still subject to the previous version of EPA CSAPR, and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. Additionally, the entire rule has been challenged by multiple parties, and the U.S. Supreme Court heard oral arguments on the emergency applications to stay the rule in February 2024. At this time, Talen cannot predict the long-term outcome of these rule changes on the operations of its generation facilities and its results of operations.
The EPA MATS Rule, which is the original EPA NESHAP for coal plants, has been in effect since 2012. In April 2023, the EPA proposed, and on May 7, 2024, finalized, its RTR for coal-fired generation facilities under the EPA NESHAP. The final rule most notably requires coal plants to reduce particulate matter (PM) emissions by the end of 2027 (or 2028 in certain circumstances). Colstrip cannot meet the new PM standard without substantial upgrades to its control equipment; therefore, Talen and the Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the plant. That decision must be made in conjunction with compliance requirements under EPA’s new GHG Rule, finalized on May 9, 2024.
Talen submitted formal comments on the new PM standard and revisions to the MATS Rule, citing the rule’s flaws, and anticipates it (and others, including other power producers, industry groups, and state attorneys general) will take legal action to challenge the revised MATS Rule. On May 8, 2024, a coalition of 23 states filed a challenge to the MATS Rule in the U.S. Court of Appeals for the D.C. Circuit. In light of these filed and expected challenges,
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Talen cannot predict the full impact of the revised MATS Rule on the operations of its coal-fired generation facilities and its results of operations.
RGGI. In April 2022, Pennsylvania formally entered the RGGI program, with compliance set to begin on July 1, 2022. However, certain third parties filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania was stayed. On November 1, 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PA DEP appealed this decision to the Pennsylvania Supreme Court in November 2023, and the following day filed notice with the court that the RGGI program would not be implemented while the appeal is pending. At this time, Talen is unable to determine the full impact of the RGGI program, when and if implemented, on its results of operations and liquidity.
Federal Climate Change Actions. The current federal administration has identified climate change policy as a priority that includes, but is not limited to, greenhouse gas emission reductions. On May 9, 2024, the EPA issued a new rule under the Clean Air Act that establishes New Source Performance Standards for new electric generating units and greenhouse gas Emissions Guidelines for existing EGUs for state implementation. The guidelines would allow all existing EGUs to continue to operate until at least the end of 2031 without having to meet new greenhouse gas limits. Existing oil/gas steam EGUs (for example, Martins Creek) will not require additional controls at this time. However, if existing coal-fired EGUs (for example, Colstrip) are to be able to operate beyond 2031, they must install a GHG reduction technology, like carbon capture and sequestration (CCS), by the end of 2031. Talen will need to evaluate the viability and costs of additional controls and decide whether to invest in those controls at Colstrip or retire the units. That decision may be influenced by the cost of compliance with the revised MATS rule. EPA stated that it chose not to finalize emission guidelines for existing fossil fuel-fired combustion turbines (for example, LMBE); however, EPA intends to take further action on such emission guidelines at a later date.
In 2023, Talen submitted formal comments on the proposed GHG Rule, citing the rule’s flaws, and anticipates it will take legal action to challenge the GHG Rule. A number of petitions for review of the GHG Rule were filed on May 9, 2024, in the U.S. Court of Appeals for the D.C. Circuit, including by coalitions representing 27 states. If the rule withstands filed and expected legal challenges by power producers (including Talen), industry groups, state attorneys general, and others, the GHG Rule could materially impact Colstrip and Talen. Talen is currently evaluating that potential impact. At this time, Talen cannot predict the full impact of the GHG Rule on the operations of its coal-fired generation facilities and its results of operations.
Environmental Remediation. From time-to-time, Talen undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from our operations and undertakes similar actions necessary to resolve environmental matters that arise in the course of normal operations.
Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs, but at this time we are unable to determine if such investigation or remediation work will have a material adverse effect on our financial condition or results of operations.
Employees
Our culture is rooted in three key principles—simplification, engagement and teamwork—which empowers our employees to influence operational decisions and trust and rely on each other, while driving operational excellence and strong financial performance. Consistent with this culture, our leadership team, together with local generation facility managers and employees, has been able to modernize and standardize legacy labor agreements, ensuring that managers and employees across Talen are subject to similar employment terms and incentive structures, which has been critical to driving our culture. Consistent with this culture, many key contributors across the organization participate in an equity compensation program that aligns our team with Talen’s strategy and with the interests of our stockholders.
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. Our collective bargaining agreements (“CBAs”) include: (i) a CBA with IBEW Local 1638, covering approximately 185 Talen Montana employees, which is in effect until April 2026;
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(ii) a CBA with Teamsters Local 190, covering approximately six Talen Montana employees, which is in effect until August 2024; and (iii) a CBA with IBEW Local 1600, covering approximately 629 Pennsylvania employees, which is in effect until August 2025.
Our future success will depend partially on our ability to attract, retain, motivate and develop qualified personnel. We invest in our employees every step of the way by providing the tools they need to succeed in their current roles and to grow personally and professionally. We do this, in part, through our Talen Leadership Academy, which is a week-long program that includes various in-person seminars and trainings for applicable candidates. In addition, we offer bespoke leadership development programs and other training resources generally as needed, both on an individual and group basis.
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MANAGEMENT
The following table sets forth information for our executive officers and directors as of June 20, 2024:
| Name | Age | Position | ||||||||||||
| Mark “Mac” McFarland | 54 | Chief Executive Officer and Director | ||||||||||||
| Terry L. Nutt | 47 | Chief Financial Officer | ||||||||||||
| John Wander | 56 | General Counsel and Corporate Secretary | ||||||||||||
| Andrew Wright | 56 | Chief Administrative Officer | ||||||||||||
| Brad Berryman | 55 | Senior Vice President and Chief Nuclear Officer | ||||||||||||
| Stephen Schaefer | 60 | Chairman of the Board and Director | ||||||||||||
| Gizman Abbas | 51 | Director | ||||||||||||
| Anthony Horton | 63 | Director | ||||||||||||
| Karen Hyde | 62 | Director | ||||||||||||
| Joseph Nigro | 59 | Director | ||||||||||||
| Christine Benson Schwartzstein | 43 | Director | ||||||||||||
Executive Officers
The following is a brief summary of the business experience of our executive officers.
Mark “Mac” McFarland. Mr. McFarland has served as the Chief Executive Officer and a Director of the Company since May 2023. Mr. McFarland oversees all aspects of the Company’s long-term strategy and overall performance including leadership of its wholesale power generation business, commercial operations, and its Cumulus growth businesses. From October 2020 until May 2023, he served as President and Chief Executive Officer of California Resources Corporation (“CRC”), an independent energy and carbon management company committed to energy transition, where he continues to serve on the board of directors and as the Chairman of Carbon TerraVault, a wholly owned subsidiary of CRC. Prior to his roles with CRC, Mr. McFarland served as Executive Chairman of GenOn Energy, an independent power producer, where he also served as President and Chief Executive Officer from April 2017 to December 2018 and continued as a member of the board of directors until September 2022. From 2013 to 2016, he served as Chief Executive Officer of Luminant Holding Company LLC (“Luminant”), a subsidiary of Energy Future Holdings Corporation (“EFH”), a large independent power producer and, from 2008 to 2013, served as both Chief Commercial Officer of Luminant and Executive Vice President, Corporate Development and Strategy of EFH. From 1999 to 2008, Mr. McFarland served in various roles at Exelon Corporation, including as Senior Vice President, Corporate Development. Mr. McFarland currently serves on the board of directors of the Nuclear Energy Institute, and previously served on the boards of directors of TerraForm Power, Bruin E&P Partners, and Chaparral Energy. Mr. McFarland earned his M.B.A. from the University of Delaware and his B.S. in Civil Engineering (Environmental Concentration) from Virginia Polytechnic Institute and State University. He holds a professional engineer license and has completed the MIT Reactor Technology Course for Utility Executives. We believe that Mr. McFarland’s extensive industry experience makes him well-qualified to serve on our Board of Directors.
Terry L. Nutt. Mr. Nutt has served as the Chief Financial Officer of the Company since July 2023. In this role, Mr. Nutt leads the Company’s finance, M&A, risk management and treasury activities. He has over 20 years of experience in the energy industry, including time spent at utility companies, power generation providers and energy trading firms. Prior to joining the Company, Mr. Nutt served as the Chief Financial Officer of Just Energy, a retail energy provider specializing in electricity and natural gas commodities. From 2018 until 2023, he served as Chief Financial Officer and Managing Director for EDF Trading North America (“EDF”), a subsidiary of Électricité de France (EDF) S.A., a multinational energy utility headquartered in France. Prior to his service at EDF, Mr. Nutt served in multiple senior finance positions at Vistra Corporation (and its predecessor entity, EFH), including as Senior Vice President and Controller and Senior Vice President of Risk Management. Mr. Nutt earned his M.S. in Accounting and his B.B.A. from Texas A&M University and is a certified CPA in the state of Texas.
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John Wander. Mr. Wander has served as General Counsel and Corporate Secretary of the Company since June 2023. Mr. Wander is responsible for overseeing all legal matters for the Company. He has nearly 30 years of experience in commercial law, with cases primarily pertaining to finance, accounting and shareholder issues. Prior to joining the Company, Mr. Wander was a Shareholder Litigation and Enforcement Partner at Vinson & Elkins LLP (“V&E”) and served as the firm’s General Counsel. He worked on some of the firm’s most high-profile, high-stakes litigation matters, and focused his practice on commercial litigation in the energy, accounting, securities, manufacturing and insurance industries, routinely representing issuers and accounting firms before the Securities & Exchange Commission. He also tried numerous corporate governance cases in the Delaware Chancery Court. Since joining V&E in 1994, Mr. Wander also served in numerous other leadership positions, including as Managing Partner of the Dallas office, Co-Department Head of Litigation and Regulatory, Co-Practice Group Leader of Complex Commercial Litigation and a member of the firm’s Management Committee. Mr. Wander earned his J.D. from The University of Texas School of Law and his B.A. in Economics from Northwestern University.
Andrew “Andy” Wright. Mr. Wright began serving as the Company’s Chief Administrative Officer in June 2023, after having served as the Company’s General Counsel and Corporate Secretary since June 2018. In his current role, Mr. Wright is responsible for overseeing the human resources, information technology, facilities and corporate security functions of the Company. Prior to joining the Company, Mr. Wright spent 14 years as in-house counsel for EFH., most recently serving as Executive Vice President, General Counsel and Corporate Secretary. Mr. Wright has nearly 20 years of experience in the power generation sector with an intimate knowledge of the financial, operational and regulatory challenges facing the industry. He has led numerous fleet and balance sheet restructuring efforts, complex acquisitions and divestitures, high-stakes litigation and regulatory reviews. His experience includes being involved in the largest leveraged buyout in U.S. history and some of the largest financial restructurings in the industry. He has also worked closely with various boards of directors, private equity sponsors and other stakeholders of Talen and EFH. After earning his J.D. from the University of Notre Dame, Mr. Wright went into private practice with V&E in both Dallas, Texas and London, England with a focus on corporate securities, mergers and acquisitions, and corporate governance. Prior to pursuing his law career, he earned his B.B.A. in Accounting from Southern Methodist University, obtained his CPA certification and practiced as an accountant with KPMG in Chicago.
Brad Berryman. Mr. Berryman has served as the Company’s senior vice president and Chief Nuclear Officer since September 2018, where he is responsible for overseeing all aspects of the Susquehanna nuclear power plant. Mr. Berryman joined the Company in early 2017 in the role of site vice president for Susquehanna, where he was responsible for all plant operations and personnel. With over two decades of extensive commercial nuclear experience, Mr. Berryman has held positions of increasing importance spanning various technical, operational, training and financial capacities. Prior to joining the Company, he served as general manager at Turkey Point Nuclear Generating Station. He also held leadership roles at Wolf Creek Nuclear Operating Corporation, Palo Verde Nuclear Generating Station and Arkansas Nuclear One. In addition, he proudly served his country in the U.S. Navy as part of the submarine fast attack fleet. Mr. Berryman earned his B.S., summa cum laude, in Organizational Management from Central Baptist College.
Directors
The following is a brief summary of the business experience of our directors. All of our directors were re-elected by written consent of our stockholders in July 2024.
Stephen Schaefer. Mr. Schaefer has served as the Chairman of the Board of Directors of the Company since May 2023. Since December 2018, May 2018, September 2020 and September 2021, respectively, Mr. Schaefer has served on the boards of directors of GenOn Holdings Inc. (where he formerly served as Chairman of the board of directors from November 2018 to May 2023), TexGen Power LLC (where he formerly served as Chairman of the board of directors from May 2018 until the sale of the company in February 2024), Just Energy Group, Inc. (where he also served as Chairman of the Audit Committee and as a member of the Risk and Compensation Committee until December 2022), and Alpine Summit Energy Partners (where he also served as Chairman of the Audit Committee since July 2018 and as a member of the Reserves Committee and Compensation Committee until July 2023). Mr. Schaefer has been actively involved in the deregulated natural gas and electricity markets since 1993. He was a Partner with Riverstone, a private equity firm focused on energy investing, from 2004 to 2015. While at
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Riverstone, he served on two of its investment committees and was primarily responsible for conventional power and renewable energy investments. Prior to joining Riverstone, Mr. Schaefer served as a Managing Director with Huron Consulting Group, where he founded and headed its Energy Practice. From 1998 to 2003, he served as a Managing Director and Vice President with Duke Energy North America. Mr. Schaefer earned his B.S., magna cum laude, in Finance and Accounting from Northeastern University in 1987 and is a Chartered Financial Analyst. We believe that Mr. Schaefer’s extensive industry experience makes him well-qualified to serve on our Board of Directors.
Gizman Abbas. Mr. Abbas has served as a Director since May 2023. Mr. Abbas has nearly 30 years of energy and investment experience. He has served on the board of directors of Prairie Operating Company, including as Chairman of the Audit Committee and as a member of the Compensation Committee, since May 2023, as Founding Principal of Direct Invest Development since December 2014, and on the board of directors of the New York Independent System Operator, including as Chairman of the Commerce & Compensation Committee and as a member of the Reliability & Markets Committee, since April 2021. Mr. Abbas served on the boards of directors of Crown Electrokinetics, including as Chairman of the Compensation Committee and as a member of the Audit and Governance Committees, from March 2021 to December 2022, Aranjin Resources Ltd., including as an Audit Committee Member from May 2016 to December 2020, KLR Energy Acquisition Corporation, including as Chairman of the Compensation Committee and a member of the Audit Committee, from January 2016 to May 2017, and Handeni Gold, including as an Audit Committee Member, from February 2012 to July 2017. Previously, Mr. Abbas was a founding Partner of the commodity investment business at Apollo Global Management, a Vice President at Goldman Sachs, an investment associate at Morgan Stanley, a Senior Project Engineer on oil and gas construction projects for Exxon Mobil Corporation, and a Co-Op Power Engineer at Southern Company. Mr. Abbas earned his B.S. in Electrical Engineering from Auburn University and his M.B.A. from Northwestern University’s Kellogg School of Business. We believe that Mr. Abbas’ executive, financial and investment experience makes him well-qualified to serve on our Board of Directors.
Anthony Horton. Mr. Horton has served as a Director since May 2023. Since March 2018, November 2021 and February 2022, respectively, Mr. Horton has served as Chief Executive Officer of AR Horton Advisors, as an Independent Director for Equiniti Trust Company, and as Lead Independent Director for Team, Inc. Additionally, Mr. Horton served as an Independent Director of U.S. Renal Care from January 2023 to February 2024, Travelport GDS, UK from March 2020 to December 2023, Neiman Marcus’ Mariposa Holdings from April 2020 to September 2020, Seadrill Partners from January 2020 to May 2021, and Arena Energy from March 2020 to September 2020, among others, and served as Independent Director and Chairman of the board of directors of NanoLumens from May 2017 to May 2020. Mr. Horton has more than 25 years of energy and technology experience, including having served as Executive Vice President and CFO at EFH and as Senior Director of Corporate and Public Policy at TXU Energy. He also has experience serving on various boards of directors and committees of companies involved in turnarounds and restructuring matters. Mr. Horton earned his Master’s of Professional Accounting and Finance from the University of Texas at Dallas/Arlington and his B.B.A. in Economics and Management from the University of Texas at Arlington. He is a CPA, Chartered Financial Analyst, Certified Management Accountant, and Certified Financial Manager. We believe that Mr. Horton’s extensive financial and business expertise, including a diversified background of both senior leadership and director roles of public and private companies, makes him well-qualified to serve on our Board of Directors.
Karen Hyde. Ms. Hyde has served as a Director since May 2023. Until her retirement in 2022, Ms. Hyde served as Senior Vice President, Chief Compliance & Ethics Officer, Chief Audit Executive, and Chief Risk Officer of Xcel Energy. Across her 30 years with Xcel Energy, she served in various roles with increasing responsibility, including roles in rates and regulatory affairs, resource planning and acquisition, and risk management. She was also responsible forecasting and production cost, expansion plan modeling, and evaluating the effectiveness of compliance programs and control frameworks. Ms. Hyde spent approximately a decade negotiating structured power purchase arrangements, including Xcel Energy’s initial renewable energy contracts, and was responsible for renewable energy compliance. Prior to joining Xcel Energy, she was a lead nuclear engineer as a civilian employee of the U.S. Department of Defense, where she was responsible for overhauling submarine reactors. Since 2013, Ms. Hyde has served with Volunteers of America CO Branch, including as Treasurer, on the board of directors, and as Chair of the Audit Committee. Ms. Hyde earned her M.S. in Mineral Economics from the Colorado School of Mines
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and her B.S. in Metallurgical Engineering from Lafayette College. We believe that Ms. Hyde’s extensive industry, regulatory and risk management experience makes her well-qualified to serve on our Board of Directors.
Joseph Nigro. Mr. Nigro has served as a Director since May 2023. Mr. Nigro has served both as senior advisor to Blackstone Inc.’s energy transition group and on the board of directors of Kindle Energy LLC since July 2023. Mr. Nigro previously served as an advisor to the Exelon Chief Executive Officer until March 2023 after having served as Exelon’s Chief Financial Officer from May 2018 to October 2022. He was also a member of Exelon’s Executive Committee and the Chair of its Corporate Investment Committee. Prior to that, Mr. Nigro served as Chief Executive Officer of Constellation Energy, an Exelon operating division, from 2013 to 2018, after serving as its Senior Vice President of Portfolio Strategy. Before joining Constellation, he was the Senior Vice President of Portfolio Management and Strategy for the Exelon Power Team, where he also led the merger integration for the Exelon Power Team wholesale trading and marketing organization with Constellation. Mr. Nigro started his career with PECO Energy, now an Exelon company, in 1996 and also spent seven years prior with Phibro Energy, Inc., an independent oil trading and refining company. Mr. Nigro earned his Bachelor’s Degree in Economics from the University of Connecticut. He has also completed the Exelon Leadership Institute Program through the Northwestern University Kellogg School of Management, the University of Chicago Executive Development Program, and the MIT Reactor Technology Course for Utility Executives. We believe that Mr. Nigro’s extensive industry experience makes him well-qualified to serve on our Board of Directors.
Christine Benson Schwartzstein. Ms. Benson has served as a Director since May 2023. She has served on the boards of directors of Delek US Holdings, Inc. since January 2024, Just Energy (U.S.) Corp. since February 2024, and Apollo Infrastructure Company since October 2023. Ms. Benson previously served as a member of Orion Infrastructure Capital’s (“OIC”) Senior Advisory Board after retiring as a Managing Director and Investment Principal in 2022. Before joining OIC, she spent 17 years in various roles at Goldman Sachs, most recently as a Managing Director in the Financing Group on the Structured Finance and Risk Management team in the Investment Banking Division, where she was responsible for the firm’s commodity structured finance efforts within Investment Banking. Prior to that, Ms. Benson was a Managing Director on the Energy Sales and Structuring teams in the Securities Division. She began her career at Goldman Sachs in 2004 as an analyst on the Energy team. Ms. Benson earned her A.B. in Earth and Planetary Sciences, magna cum laude, from Harvard University. We believe that Ms. Benson’s extensive industry and financial and risk management experience makes her well-qualified to serve on our Board of Directors.
Family Relationships
There are no family relationships among any of our executive officers or directors.
Composition of Our Board of Directors
Our Board of Directors currently consists of seven members. In accordance with our Charter, our Board of Directors consists of a single class. Each director is to hold office until his or her successor is duly elected and qualified or until his or her earlier death, resignation or removal.
Director Independence
Our Board of Directors has undertaken a review of the independence of each director. Based on information provided by each director concerning his or her background, employment and affiliations, our Board of Directors has determined that each of Messrs. Schaefer, Abbas, Horton and Nigro and Mses. Hyde and Benson do not have relationships that would interfere with the exercise of independent judgment in carrying out the responsibilities of a director and that each of these directors is “independent” as that term is defined under the listing standards of Nasdaq. In making these determinations, our Board of Directors considered the current and prior relationships that each non-employee director has with our company and all other facts and circumstances our Board of Directors deemed relevant in determining their independence, including the beneficial ownership of our shares held by each non-employee director and the transactions described in the section titled “Certain Relationships and Related Party Transactions.”
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Committees of Our Board of Directors
Our Board of Directors has established an audit committee, a compensation committee, a nominating and corporate governance committee and a risk oversight committee. The composition and responsibilities of each of the committees of our Board of Directors are described below. Our Board of Directors may establish other committees as it deems necessary or appropriate from time to time.
Audit Committee
Our audit committee consists of Ms. Hyde and Messrs. Abbas and Horton. Our Board of Directors has determined that each member of our audit committee satisfies the independence requirements under the listing standards of Nasdaq and Rule 10A-3(b)(1) of the Exchange Act. The chair of our audit committee is Ms. Hyde. Our Board of Directors has determined that Ms. Hyde is an “audit committee financial expert” within the meaning of SEC regulations and that each member of our audit committee is financially sophisticated in accordance with applicable requirements. In arriving at these determinations, our Board of Directors has examined each audit committee member’s scope of experience and the nature of their employment.
The primary purpose of our audit committee is to discharge the responsibilities of our Board of Directors with respect to our corporate accounting and financial reporting processes, systems of internal control and financial statement audits and to oversee our independent registered public accounting firm. Specific responsibilities of our audit committee include:
•appointing, compensating, retaining, evaluating, terminating and overseeing our independent registered public accounting firm;
•discussing with our independent registered public accounting firm their independence from management;
•reviewing with our independent registered public accounting firm the scope and results of their audit;
•approving all audit and permissible non-audit services to be performed by our independent registered public accounting firm;
•overseeing the financial reporting process and discussing with management and our independent registered public accounting firm the quarterly and annual financial statements that we file with the SEC;
•overseeing our financial and accounting controls and compliance with legal and regulatory requirements;
•reviewing our policies on risk assessment and risk management;
•reviewing related person transactions; and
•establishing procedures for the confidential anonymous submission of concerns regarding questionable accounting, internal controls or auditing matters.
Our audit committee operates under a written charter that satisfies the applicable listing standards of Nasdaq.
Compensation Committee
Our compensation committee consists of Ms. Hyde and Messrs. Abbas and Horton. The chair of our compensation committee is Mr. Horton. Our Board of Directors has determined that each member of our compensation committee is independent under the listing standards of Nasdaq and a “non-employee director” as defined in Rule 16b-3 promulgated under the Exchange Act.
The primary purpose of our compensation committee is to discharge the responsibilities of our Board of Directors in overseeing our compensation policies, plans and programs, and to review and determine the
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compensation to be paid to our executive officers, directors and other senior management, as appropriate. Specific responsibilities of our compensation committee include:
•reviewing and approving the corporate goals and objectives, evaluating the performance of and reviewing and approving (either alone, or if directed by the Board of Directors, in connection with a majority of the independent members of the Board of Directors) the compensation of our Chief Executive Officer;
•reviewing and setting or making recommendations to our Board of Directors regarding the compensation of our other executive officers;
•reviewing and approving or making recommendations to our Board of Directors regarding our incentive compensation and equity-based plans and arrangements;
•making recommendations to our Board of Directors regarding the compensation of our directors; and
•appointing and overseeing any compensation consultants.
Our compensation committee operates under a written charter that satisfies the applicable listing standards of Nasdaq.
Nominating and Corporate Governance Committee
Our nominating and corporate governance committee consists of Ms. Benson and Messrs. Abbas and Nigro. The chair of our nominating and corporate governance committee is Mr. Abbas. Our Board of Directors has determined that each member of our nominating and corporate governance committee is independent under the listing standards of Nasdaq.
Specific responsibilities of our nominating and corporate governance committee include:
•identifying individuals qualified to become members of our Board of Directors, consistent with criteria approved by our Board of Directors;
•periodically reviewing our Board of Directors’ leadership structure and recommending any proposed changes to our Board of Directors, including recommending to our Board of Directors the nominees for election to our Board of Directors at annual meetings of our stockholders;
•overseeing an annual evaluation of the effectiveness of our Board of Directors and its committees; and
•developing and recommending to our Board of Directors a set of corporate governance guidelines.
Our nominating and corporate governance committee operates under a written charter that satisfies the applicable listing standards of Nasdaq.
Risk Oversight Committee
Our risk oversight committee consists of Ms. Benson and Messrs. Horton and Nigro. The chair of our risk oversight committee is Mr. Nigro.
The primary purpose of our risk oversight committee is to discharge the responsibilities of our Board of Directors in overseeing management’s process for the identification, evaluation and management of the key factors with the potential to have a material impact on the Company’s enterprise risk, the Company’s risk related to commodity prices, commercial transactions and trading, risks related to the operation of Company’s power generation assets (including nuclear and fossil operations generally) and the Company’s management of its insurance programs and investment policies.
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Specific responsibilities of our risk oversight committee include:
•at least annually, to review and discuss with management the Company’s enterprise risk assessment and management’s process for the identification, evaluation and management of enterprise risk;
•to review and discuss reports from management and provide feedback on credit, market and liquidity risks the Company faces, the exposures in each category, significant concentrations within those risk categories, the metrics used to monitor the exposures and management’s views on the acceptable and appropriate levels of those risk exposures; and
•to review any policies that the Company may have from time to time addressing regulatory matters.
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 this independent risk oversight committee of the Board of Directors that makes this a key strategic priority.
Code of Business Conduct and Ethics
We have adopted a code of business conduct and ethics that applies to our directors, officers and employees, including our principal executive officer, principal financial officer, principal accounting officer or controller and persons performing similar functions. Immediately following the effectiveness of the registration statement of which this prospectus forms a part, our code of business conduct and ethics will be available under the Corporate Governance section of our website at www.talenenergy.com. In addition, we intend to post on our website all disclosures that are required by law or the listing standards of Nasdaq concerning any amendments to, or waivers from, any provision of the code. The reference to our website address does not constitute incorporation by reference of the information contained at or available through our website and you should not consider it to be a part of this prospectus.
Compensation Committee Interlocks and Insider Participation
None of the members of our compensation committee is currently or has been at any time one of our officers or employees. None of our executive officers currently serves, or has served during the last year, as a member of the board of directors or compensation committee of any entity that has one or more executive officers serving as a member of our board of directors or compensation committee.
Nuclear Oversight Committee
The principal functions of the nuclear oversight committee are:
•to assist our Board of Directors in the fulfillment of its responsibilities for oversight of the Company’s nuclear operations;
•to advise Company management on nuclear matters; and
•to provide advice and recommendations to our Board of Directors concerning the future direction of the Company and management performance related to nuclear operations.
Among other things, the nuclear oversight committee continually strives to ensure that the Company’s nuclear function has systems in place to protect the health and safety of the public and maintain compliance with applicable laws and regulations.
Risk Oversight
We manage the commodity price, counterparty credit and commodity-related operational risk related to the competitive energy business within limitations established by senior management and in accordance with overall risk management policies. Market risks are monitored by our risk oversight committee and risk management committee, utilizing defined practices and analytical methodologies. These techniques measure the risk of change in value of the portfolio of contracts and the hypothetical effect on this value from changes in market conditions and
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include, but are not limited to, position reporting and review and stress test scenarios. Key risk control activities include, but are not limited to, transaction review and approval (including credit review), operational and market risk measurement, transaction authority oversight, validation of transaction capture, market price validation and reporting, and portfolio valuation and reporting, including mark-to-market valuation and other risk measurement metrics.
Board Diversity
Our nominating and corporate governance committee will be responsible for reviewing with the Board of Directors, on an annual basis, the appropriate characteristics, skills and experience required for the Board of Directors as a whole and its individual members. Although our Board of Directors does not have a formal written diversity policy with respect to the evaluation of director candidates, in its evaluation of director candidates, our nominating and corporate governance committee will consider factors including, without limitation, issues of character, integrity, judgment, potential conflicts of interest, other commitments and diversity, and with respect to diversity, such factors as gender, race, ethnicity, experience and area of expertise, as well as other individual qualities and attributes that contribute to the total diversity of viewpoints and experience represented on the Board of Directors.
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EXECUTIVE COMPENSATION
Compensation Discussion and Analysis
Background
In May 2022, the Company commenced the Restructuring to, among other things, strengthen its financial position and provide additional liquidity to fund its operations. The Company emerged from the Restructuring in May 2023. For more information, see “Prospectus Summary—Recent Developments—Reorganization and Emergence.” Following its Emergence, the Company appointed the Board (or for the purposes of this section, the “Current Board”) and compensation committee thereof (the “Compensation Committee”) and made changes to its executive management team. For more information, see “Management.”
This Executive Compensation section describes our compensation programs in effect for the year ended December 31, 2023, which include compensation arrangements put in place both prior to and during the Restructuring (the “Pre-Emergence Compensation Program”) as well as those put in place following Emergence (the “Current Compensation Program”).
Because compensation paid to our “named executive officers” (“NEOs”) during 2023 was based on the Pre-Emergence Compensation Program from January 1, 2023 until May 16, 2023 and was based on the Current Compensation Program from May 17, 2023 until December 31, 2023, where applicable, this Compensation Discussion and Analysis describes how each applicable compensation component (i) is currently considered and used under the Current Compensation Program and (ii) was previously considered and used under the Pre-Emergence Compensation Program.
Our Named Executive Officers
The purpose of this Compensation Discussion and Analysis is to provide information about the material elements of compensation that were paid to, awarded to, or earned by our NEOs for 2023, which included the Company’s principal executive officer, principal financial officer, and the three other most highly compensated executive officers employed at the end of 2023 (such NEOs collectively, the “Current NEOs”), as well as the Company’s former principal executive officer and former principal financial officer, both of whom were employed by the Company for a portion of 2023. For 2023, our NEOs and their positions were:
•Mark “Mac” McFarland, President and Chief Executive Officer;
•Terry L. Nutt, Chief Financial Officer;
•Brad Berryman, Senior Vice President and Chief Nuclear Officer;
•Andrew Wright, Chief Administrative Officer (and Former General Counsel and Corporate Secretary);
•John Wander, General Counsel and Corporate Secretary;
•Alejandro Hernandez, Former Chief Executive Officer; and
•John Chesser, Former Chief Financial Officer.
We made several changes to our senior management team in 2023 in connection with Emergence: (i) Mr. Hernandez departed the Company in May 2023, at which time Mr. McFarland was appointed as President and Chief Executive Officer, (ii) Mr. Wright transitioned from his role as General Counsel and Corporate Secretary to the role of Chief Administrative Officer in June 2023, at which time Mr. Wander was appointed as General Counsel and Corporate Secretary, and (iii) Mr. Chesser departed the Company in July 2023, at which time Mr. Nutt was appointed as Chief Financial Officer.
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Compensation Philosophy and Objectives
Our Compensation Committee reviews and approves the compensation of our NEOs and oversees and administers our executive compensation programs and initiatives. As we gain experience as a public company, we expect that the specific direction, emphasis and components of our executive compensation program will continue to evolve.
The Company strives to create an executive compensation program that balances short-term versus long-term payments and awards, cash payments versus equity awards, and fixed versus contingent payments and awards in ways that we believe are most appropriate to motivate our executive officers, while balancing the extenuating and evolving circumstances created by our recent Restructuring. Our executive compensation program is designed to:
•attract and retain talented and experienced executives in our industry;
•reward executives whose knowledge, skills and performance are critical to our success;
•align the interests of our executive officers and stockholders by motivating executive officers to increase stockholder value and rewarding executive officers when stockholder value increases;
•ensure fairness among the executive management team by recognizing the contributions each executive makes to our success;
•foster a shared commitment among executives by aligning their individual goals with the goals of the entire executive management team and the Company; and
•compensate our executives in a manner that incentivizes them to manage our business to meet our long‑range objectives.
To achieve these objectives, our Compensation Committee has implemented the current compensation program, which ties a substantial portion of our executives’ overall compensation to shareholder value, and key operating and financial metrics, such as safety, operating performance, EBITDA, and free cash flow.
We seek to foster in our executives a long-term commitment to the Company. We believe that there is great value to the Company in having a team of long-tenured, seasoned managers. Our team-focused culture and management processes are designed to foster this commitment.
Determining Compensation
Role of Our Compensation Committee and Named Executive Officers in the Current Compensation Program
Our Compensation Committee meets outside the presence of all of our executive officers, including our NEOs, to consider appropriate compensation for our Chief Executive Officer. For the compensation of all other NEOs, our Compensation Committee meets outside the presence of all executive officers except our Chief Executive Officer. Our Chief Executive Officer will review annually each other NEO’s performance with our Compensation Committee and recommend appropriate base salary changes, cash performance awards and grants of long-term equity incentive awards (if any). Based upon the recommendations of our Chief Executive Officer and in consideration of the objectives described above and the principles described below, our Compensation Committee will approve the annual compensation packages of our executive officers other than our Chief Executive Officer. Our Compensation Committee also will annually analyze our Chief Executive Officer’s performance and determine his base salary changes, cash performance awards and grants of long-term equity incentive awards (if any) based on its assessment of his performance with input from any consultants engaged by our Compensation Committee. Our Compensation Committee will then recommend to the Current Board any such changes it deems appropriate to our Chief Executive Officer’s compensation package, and the Current Board will approve any such changes.
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Role of the Prior Board and the Restructuring Committee in the Pre-Emergence Compensation Program
Compensation decisions with respect to our NEOs prior to Emergence, including the design and adoption of the Pre-Emergence Compensation Program in place from January 1, 2023 to May 17, 2023 were made by the board of directors prior to the Restructuring (the “Prior Board”), and decisions made during the Restructuring were generally made by the Restructuring Committee of the TES board of managers (the “Restructuring Committee”) and approved by the Bankruptcy Court. The compensation paid to our NEOs prior to Emergence in 2023 is not indicative of how we compensate our Current NEOs (or expect to do so in the future), as it was significantly impacted by circumstances that the Prior Board and the Restructuring Committee determined justified changes in order to focus on cash retention and short-term incentives during the Restructuring. As discussed above, upon Emergence, the Company implemented the Current Compensation Program and pivoted toward an increased use of long-term incentives to facilitate stakeholder alignment.
Role of Compensation Consultants
In order to ensure that we continue to remunerate our executives appropriately, our Compensation Committee has retained Lyons, Benenson & Company, Inc. (“LB & Co.”) as its independent compensation consultant. In such capacity, LB & Co. assisted with the design of the Current Compensation Program, reviewed our executive compensation policies and procedures following Emergence, and currently assists our Compensation Committee by providing comparative market data on compensation practices and programs based on an analysis of peer competitors and by providing guidance on industry best practices. Our Compensation Committee retains the right to modify or terminate its relationship with LB & Co. or to select other outside advisors to assist our Compensation Committee in carrying out its responsibilities.
The Prior Board and the Restructuring Committee retained Willis Towers Watson plc (“WTW”) as independent compensation consultant to assist in designing the Pre-Emergence Compensation Program.
Neither LB & Co. nor WTW provided services to the Company other than the compensation advisory services described above.
Benchmarking
The Prior Board recognized that our success was dependent on our ability to attract and retain skilled executive officers, especially during the Restructuring. Thus, when designing the Pre-Emergence Compensation Program, the Prior Board and the Restructuring Committee, with assistance from WTW, reviewed and considered the compensation paid by our known competitors. The competitive market data provided by WTW was based, in part, on the peer group below, which was developed by WTW.
Following Emergence, in furtherance of the post-Emergence compensation objectives discussed above, our Compensation Committee engaged LB & Co. to review and update the Company’s existing peer group. After its review, LB & Co. recommended maintaining the Company’s existing peer group. LB & Co. reviewed and considered the compensation paid by the Company’s peer group in terms of the elements of pay, total available pay opportunities and compensation actually received.
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Both WTW, with respect to the Pre-Emergence Compensation Program, and LB & Co., with respect to the Current Compensation Program, used the following peer group in forming their recommendations:
| Vistra Corp. | Portland General Electric Company | CyrusOne Inc. | ||||||
| The AES Corporation | Black Hills Corporation | DigitalBridgeGroup, Inc. | ||||||
| CenterPoint Energy, Inc. | PNM Resources, Inc. | CoreSite Realty Corporation | ||||||
| PPL Corporation | IDACORP, Inc. | QTS Realty Trust, Inc. | ||||||
| Iron Mountain Incorporated | Avista Corporation | Sunnova Energy International Inc. | ||||||
| Pinnacle West Capital Corporation | ALLETE, Inc. | Riot Blockchain, Inc. | ||||||
| Alliant Energy Corporation | NorthWestern Corporation | |||||||
| OGE Energy Corp. | Clearway Energy, Inc. | |||||||
Risk Assessment
The Company has determined that any risks arising from our Current Compensation Program and post‑Emergence policies are not reasonably likely to have a material adverse effect on the Company. These compensation programs and policies manage risk by combining performance-based, long-term compensation elements with payouts that are highly correlated to the value delivered to stockholders, which encourages employees to maintain both a short- and a long-term view with respect to Company performance.
Elements of Compensation
The Current Compensation Program, which was put in place at Emergence, is set by our Compensation Committee and consists of the following components:
•base salary;
•annual cash incentive awards linked to our overall performance;
•periodic grants of long-term equity-based compensation, such as restricted stock units and performance stock units;
•other executive benefits and perquisites; and
•employment agreements, which contain termination and change of control benefits.
We combine these elements to formulate compensation packages that provide competitive pay, reward the achievement of financial, operational and strategic objectives and align the interests of our executive officers and other senior personnel with those of our stakeholders.
Pay Mix
We believe the compensation elements mentioned above collectively provide a well-proportioned mix of secure compensation, retention value and at-risk compensation, while balancing short-term and long-term performance incentives and rewards. We strategically use each compensation element to provide our executives a measure of security in the minimum expected level of compensation, while motivating them to focus on business metrics that will produce a high level of short-term and long-term performance for the Company, as well as reducing the risk of recruitment of top executive talent by competitors. The mix of metrics used for our annual performance bonus and long-term incentive program likewise provides an appropriate balance between short-term financial performance and long-term financial and stock performance.
For key executives, including our NEOs, the mix of compensation is weighted toward at-risk pay, such as annual incentives and long-term incentives. Maintaining this pay mix results fundamentally in a pay-for-performance orientation for our executives, which is aligned with our stated compensation philosophy of providing compensation commensurate with performance.
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Base Salary
The base salary established for each of our executive officers is intended to reflect each individual’s responsibilities, experience, prior performance and other discretionary factors deemed relevant by our Compensation Committee. Base salary is also designed to provide our executive officers with steady cash flow during the course of the year that is not contingent on short-term variations in our corporate performance. Our Compensation Committee determines market-level base salaries based on our executives’ experience in the industry with reference to the base salaries of similarly situated executives in other companies of similar size and stage of development operating in our industry. This determination is informal and based primarily on our Compensation Committee’s general knowledge of the compensation practices within our industry. The base salaries paid to our NEOs in 2023 are set forth in the table below.
| Named Executive Officer | Base Salary as of January 1, 2023 | Base Salary as of December 31, 2023 | ||||||||||||
Mark McFarland(1) | — | $ | 1,125,000 | |||||||||||
Terry L. Nutt(1) | — | $ | 550,000 | |||||||||||
Brad Berryman(2) | $ | 533,319 | $ | 550,000 | ||||||||||
Andrew Wright(3) | $ | 529,163 | $ | 530,000 | ||||||||||
John Wander(1) | — | $ | 550,000 | |||||||||||
Alejandro Hernandez(4) | $ | 1,261,750 | — | |||||||||||
John Chesser(4) | $ | 529,163 | — | |||||||||||
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(1)Messrs. McFarland, Nutt and Wander were hired in May 2023, July 2023, and June 2023, respectively, and their base salaries were determined under the Current Compensation Program.
(2)Upon Emergence, Mr. Berryman entered into a new employment agreement pursuant to which he received a salary increase, as reflected in this table.
(3)In connection with Emergence, Mr. Wright’s base salary increased in June 2023 in connection with his transition from General Counsel and Corporate Secretary to his role as Chief Administrative Officer.
(4)Messrs. Hernandez and Chesser left the Company in May 2023 and July 2023, respectively.
Short-Term Cash Incentives
Current and Pre-Emergence Compensation Program: STI Program
Both prior to and following Emergence, the Company has maintained a short-term incentive bonus program (the “STI Program”) pursuant to which certain employees, including our NEOs, are eligible to receive cash bonus payments equal to a percentage of base salary, with the amount of such payment based on the Company’s financial and operational performance as compared to target metrics, with individual awards subject to further adjustment based on management’s determination of individual performance. Cash payments under the STI Program are intended to offer incentive compensation by rewarding the achievement of corporate and individual performance objectives. We believe that establishing cash bonus opportunities helps us attract and retain qualified and highly skilled executives. These annual bonuses are intended to reward executive officers who have a positive impact on corporate results.
Current STI Program. Following Emergence, our Compensation Committee has authority to award annual cash bonuses to our NEOs under the STI Program. On an annual basis, or at the commencement of an executive officer’s employment with us, our Compensation Committee typically sets a target level of bonus compensation that is structured as a percentage of such executive officer’s annual base salary. Following Emergence, the Compensation Committee approved bonus opportunities under the STI Program for the Current NEOs for the second half of 2023 (the “Current STI Program”), with target levels of aggregate bonus compensation structured as a percentage of base salary, as set forth in the table below, in each case, earned based upon the achievement of performance objectives
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determined by our Compensation Committee, as discussed in more detail below. Annual bonus payouts may range from 0-200% of target, depending on performance.
| Executive | Target STI Payout (% of Base Salary) | 2023 Target Payout | ||||||||||||
Mark McFarland(1) | 135 | % | $ | 952,860 | ||||||||||
Terry L. Nutt(3) | 100 | % | $ | 550,000 | ||||||||||
Brad Berryman(2) | 100 | % | $ | 550,000 | ||||||||||
Andrew Wright(2) | 100 | % | $ | 530,000 | ||||||||||
John Wander(3) | 100 | % | $ | 550,000 | ||||||||||
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(1)Mr. McFarland’s 2023 target bonus will be computed pro-rata for the number of days employed during the performance year.
(2)Messrs. Berryman’s and Wright’s payouts will be adjusted to reflect previously received payouts under the various 2023 bonus programs.
(3)Pursuant to their respective employment agreements, Messrs. Nutt’s and Wander’s payouts will be paid as though they were employed during the entire performance year.
Payouts under the Current STI Program were determined based on the Company’s achievement, during the second half of 2023, of safety goals (measured against “Lost Time Incident Rate” performance metrics, as defined below), “Equivalent Forced Outage Factor” performance metrics, as defined below, financial goals (measured against Adjusted EBITDA and Adjusted Free Cash Flow performance metrics) and the Company’s progress toward the transformation of its asset base, as set forth and described in the table below.
| Metric | Weight | Threshold Performance (50%) | Target Performance (100%) | Maximum Performance (200%) | Performance Certified for 2H 2023 (% of Target) | |||||||||||||||||||||||||||
2H 2023 Safety(1) | 15 | % | 0.5 | 0.3 | 0.0 | 137 | % | |||||||||||||||||||||||||
2H 2023 Forced Outage Performance(2) | 15 | % | 5.0 | % | 3.3 | % | 2.7 | % | 0 | % | ||||||||||||||||||||||
| 2H 2023 Adjusted EBITDA | 30 | % | $234 million | $352 million | $570 million | 97 | % | |||||||||||||||||||||||||
| 2H 2023 Adjusted Free Cash Flow | 30 | % | $(29) million | $89 million | $307 million | 114 | % | |||||||||||||||||||||||||
| Progress of Transformation | 10 | % | — | Discretionary Metrics / Guidelines | Discretionary Metrics / Guidelines | 100 | % | |||||||||||||||||||||||||
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(1)Safety is measured as the total number of lost time injuries multiplied by 200,000 divided by the total number of hours worked (“Lost Time Incident Rate”).
(2)Forced Outage Performance is measured as the fraction of a given period in which a generating unit is not available due to forced outages and forced derating (“Equivalent Forced Outage Factor”).
In March 2024, the Compensation Committee certified that, based on the above performance and weightings, performance metrics were collectively satisfied at 94.07% under the Current STI Program in respect of the second half of 2023 for each Current NEO. The Compensation Committee further certified, based on annual performance and weightings, that performance metrics were collectively satisfied at 152.3% for the first quarter of 2023 and 134.1% for the second quarter of 2023, in each case, under the Pre-Emergence STI Program (discussed further below). As Mr. McFarland was not employed until the second quarter of 2023, he did not receive a bonus amount for the first quarter performance period, and he received a pro-rated bonus amount for the second quarter of 2023 (certified at a 94.07% level based on actual performance). Both Messrs. Nutt and Wander were entitled to full year annual bonus payments for 2023 under the terms of their employment agreements. However, because they were not employed by the Company during the first and second quarters of 2023, the Compensation Committee determined to adjust the performance achievement of the Company-wide metrics under the STI Program downward to reflect achievement at 100% for the first and second quarters of 2023 rather than the actual level of performance achieved.
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Individual Multiplier
After performance is determined for the STI Program based on the metrics described above, an individual multiplier is applied to each Current NEO’s annual bonus amount to determine each Current NEO’s overall earned 2023 STI amount. A Current NEO’s individual multiplier is determined by the Chief Executive Officer’s rating of each Current NEO’s individual performance (except his own) on a scale of 1 to 5 (with 5 being the highest), with the resulting multiplier determined, in consultation with the Compensation Committee, based on the recommended range for such rating, as shown in the chart below. The Board determines the individual rating for the Chief Executive Officer on the same scale.
| Bonus Performance Rating and Related Individual Multiplier | ||||||||||||||
| Rating | Minimum | Maximum | ||||||||||||
| 1 | 0 | % | 0 | % | ||||||||||
| 2 | 0 | % | 0 | % | ||||||||||
| 3 | 80 | % | 105 | % | ||||||||||
| 4 | 100 | % | 125 | % | ||||||||||
| 5 | 125 | % | 150 | % | ||||||||||
Based on the ratings recommended by the Chief Executive Officer and the Board’s independent determination of the CEO’s individual performance, an individual multiplier of 135% was applied to each Current NEO’s annual 2023 STI payment. Accordingly, each Current NEO received the following total for 2023 STI.
| Executive | Annual 2023 STI Payout Prior to Applying Multiplier | 2023 STI Total Payout | ||||||||||||
| Mark McFarland | $ | 896,355 | $ | 1,210,079 | ||||||||||
| Terry L. Nutt | $ | 533,558 | $ | 720,304 | ||||||||||
| Brad Berryman | $ | 651,245 | $ | 879,181 | ||||||||||
| Andrew Wright | $ | 627,563 | $ | 847,210 | ||||||||||
| John Wander | $ | 533,558 | $ | 720,304 | ||||||||||
The actual payments made in 2024 for performance under the STI Program for Messrs. Berryman and Wright were reduced to reflect previously paid bonus amounts with respect to the Pre-Emergence STI Program (described below).
Pre-Emergence 2023 STI Program. Prior to Emergence, the Prior Board and the Restructuring Committee approved quarterly bonus opportunities for corporate employees under the STI Program for 2023 (the “Pre-Emergence 2023 STI Program”), with target levels of aggregate bonus compensation structured as a percentage of base salary. Payouts were determined based on the Company’s achievement of its Business Plan Investment goals (measured against Operations and Maintenance; CapEx and General and Administrative performance metrics), Safety goals (measured against Lost Time Incident Rate performance metrics), Equivalent Forced Outage Factor
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performance metrics, and the Company’s progress toward recapitalization and the transformation of its asset base, as set forth and described in the table below.
| Metric | Weight | Threshold Performance | Target Performance (100%) | Maximum Performance (125 – 250%) | Performance Certified for Q2 2023 (% of Target) | |||||||||||||||||||||||||||
Business Plan Investment(1) | 50 | % | $1,190 million | $1,035 million | $880 million (200%) | 167 | % | |||||||||||||||||||||||||
Safety(2) | 15 | % | 0.75 | 0.3 | 0.20 (125%) | 125 | % | |||||||||||||||||||||||||
Forced Outage Performance(3) | 15 | % | 6.6 | % | 3.3 | % | 2.3% (250%) | 79 | % | |||||||||||||||||||||||
| Progress on Recapitalization | 10 | % | — | Board Discretionary Metrics / Guidelines | Board Discretionary Metrics / Guidelines (200%) | 100 | % | |||||||||||||||||||||||||
| Progress of Transformation | 10 | % | — | Board Discretionary Metrics / Guidelines | Board Discretionary Metrics / Guidelines (200%) | 100 | % | |||||||||||||||||||||||||
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(1)The Business Plan Investment goals were measured on an annual basis by comparing actual levels of Operations and Maintenance; CapEx and General and Administrative expenditures as compared against the projected levels of such expenditures in the Company’s business plan.
(2)Safety was measured as Lost Time Incident Rate
(3)The Equivalent Forced Outage Factor was measured as the fraction of a given period in which a generating unit is not available due to forced outages and forced derating.
During the pendency of the Restructuring, NEOs were not eligible to participate in the Pre-Emergence 2023 STI Program and instead received cash bonuses under an Advanced STI Bonus and the KEIP (both discussed in further detail below) for the first quarter of 2023.
For the first quarter of 2023, amounts under the Pre-Emergence 2023 STI Program were prepaid to each participating NEO in April 2022 at target performance level (the “Advanced STI Bonus”), to be earned and retained subject to continued employment through March 31, 2023 and achievement of the applicable performance targets. The Advanced STI Bonuses were subject to clawback provisions until fully earned. In April 2023, the Prior Board deemed all performance metrics were collectively satisfied at 130.2% in respect of the first quarter of 2023 for our participating NEOs, which remained subject to the certification of annual metrics at the end of the year. Accordingly, the portions of the Advanced STI Bonuses in respect of the first quarter of 2023 were deemed earned as of March 31, 2023 and are included in the Summary Compensation Table for compensation earned during 2023 for our participating NEOs. However, because their prepaid amounts reflected 100% performance, additional amounts were paid to Messrs. Berryman and Wright in 2024 to reflect the difference between what was previously paid and actual performance. In March 2024, the Compensation Committee subsequently certified the performance for the first quarter of 2023 at 152.3% to reflect the ultimate achievement of the Business Plan Investment metric at 167.2%.
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The table below shows the Advanced STI Bonuses paid to each participating NEO in respect of Q1 2023 performance, earned in March 2023.
| Executive | Target STI Opportunity (% of Base Salary) | Advanced STI Bonus for Q1 2023 Performance ($) | ||||||||||||
| Brad Berryman | 100 | % | 129,761 | |||||||||||
| Andrew Wright | 100 | % | 128,750 | |||||||||||
| Alejandro Hernandez | 200 | % | 631,000 | |||||||||||
| John Chesser | 100 | % | 128,750 | |||||||||||
Following Emergence, for the second quarter of 2023, the remaining NEOs that remained with the Company (i.e., Messrs. Berryman and Wright) became eligible to participate in the Pre-Emergence 2023 STI Program (based on the performance metrics above), and received cash bonuses under the Pre-Emergence 2023 STI Program for the second quarter of 2023. In August 2023, the Compensation Committee certified performance under the Pre-Emergence 2023 STI Program for the second quarter of 2023 in the amounts described above at 127.6%, which remained subject to the certification of annual metrics at the end of the year. The portions of the 2023 annual bonuses with respect to performance during the second quarter of 2023 were paid in August 2023 (the “Q2 Annual Bonus Payout”) to Messrs. Berryman and Wright in the amounts of $137,500 and $132,500, respectively. In March 2024, the Compensation Committee subsequently certified the performance for the first quarter of 2023 at 134.1% to reflect the ultimate achievement of the Business Plan Investment metric at 167.2%.
Pre-Emergence Compensation Program: Key Employee Incentive Plan
In August 2022, the Bankruptcy Court approved the TES Key Employee Incentive Plan (the “KEIP”), pursuant to which certain key employees identified by the Prior Board, including Messrs. Hernandez, Chesser, Berryman and Wright, were eligible to earn certain performance-related bonuses during the period beginning in the second quarter of 2022 through the third quarter of 2023; however, as the Restructuring was completed in the second quarter of 2023, the KEIP was terminated and no bonuses were earned or paid thereunder for the third quarter of 2023. Such NEOs were eligible to earn the following bonuses under the KEIP in 2023: (i) quarterly incentive payments based on achievement of business plan targets for Equivalent Forced Outage Factor, Safety, and Business Plan Investment (as described below) measured against performance metrics for each of the fourth quarter of 2022 and the first and second quarters of 2023 (collectively, the “Quarterly Performance Bonuses”), (ii) incentive payments based on the Company’s entry into binding agreements to sell certain non-core assets and the proceeds therefrom, to be paid out 50% upon execution of such binding agreement and 50% upon the Company’s receipt of the proceeds (collectively, the “Asset Sale Bonuses”), and (iii) an incentive payment based on achievement of the Company’s Incremental Cash Balance as of March 31, 2023 (the “Cash Balance Bonus” and the incentive payments described in (i) through (iii) collectively, the “KEIP Payments”). The KEIP Payments are in addition to amounts earned by our NEOs under the STI Program.
The potential amount payable to each participating NEO upon the conclusion of each applicable performance period was based on the achievement of specified performance metrics for each applicable performance period as set forth in the table below and subject to the NEO’s continued employment through the date of payment. The
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performance levels, performance period and timing of payment for each component of the KEIP that was eligible to be earned by the participating NEOs in 2023 is set forth below.
| Measurement Period | Performance Goals | Payout Timing | ||||||||||||||||||||||||||||||
| Metric | Threshold | Target | Maximum | |||||||||||||||||||||||||||||
Equivalent Forced Outage Factor(1) | Quarterly (4Q ’22 – 3Q ’23) | 6.60 | % | 3.30 | % | 2.30 | % | Quarterly | ||||||||||||||||||||||||
Safety(2) | Quarterly (4Q ’22 – 3Q ’23) | 0.75 | 0.3 | 0.2 | Quarterly | |||||||||||||||||||||||||||
Business Plan Investment(3) | Quarterly (4Q ’22 – 3Q ’23) | 110% of Target | Business Plan Target | 90% of Target | Quarterly | |||||||||||||||||||||||||||
| Incremental Cash Balance | Quarterly (4Q ’22 – 3Q ’23) | $0 - $120 million | $482 million | $751 million | As soon as practicable following March 31, 2023 | |||||||||||||||||||||||||||
__________________
(1)The Equivalent Forced Outage Factor was measured as the fraction of a given period in which a generating unit is not available due to forced outages and forced derating.
(2)Safety was measured as Lost Time Incident Rate, i.e., the total number of lost time injuries times 200,000 divided by the total number of hours worked.
(3)The Business Plan Investment goals were measured by comparing actual levels of Operations and Maintenance; CapEx and General and Administrative expenditures as compared against the projected levels of such expenditures in the Company’s business plan.
The table below details the threshold and maximum payout as a percentage of target for each performance metric. With respect to the Asset Sale Bonuses, the KEIP provided for a payment equal to 1.9782% of the first $70 million of proceeds from consummation of any sales of non-core assets.
| Metric | KEIP Payout Range (% of Target) | Performance Certified for Q2 2023 (% of Target) | ||||||||||||||||||||||||
| Threshold | Target | Maximum | ||||||||||||||||||||||||
| Equivalent Forced Outage Factor | 20 | % | 100 | % | 225 | % | 225 | % | ||||||||||||||||||
| Safety | 20 | % | 100 | % | 112.5 | % | 93 | % | ||||||||||||||||||
| Business Plan Investment | 20 | % | 100 | % | 180 | % | 106 | % | ||||||||||||||||||
| Incremental Cash Balance | 20 | % | 100 | % | 180 | % | 40 | % | ||||||||||||||||||
The following amounts were earned and paid out under the KEIP in 2023:
•The Prior Board and/or Restructuring Committee (and for the second quarter of 2023, the Compensation Committee) certified the following performance achievements for Quarterly Performance Bonuses and, for the first quarter of 2023, the Cash Balance Bonus, under the KEIP:
◦For the first quarter of 2023, total weighted performance (based on the performance for each metric set forth in the above table) was determined to be 70%, with amounts paid out in April 2023.
◦Pursuant to their separation agreements, each of Messrs. Hernandez and Chesser received prorated KEIP Payments for the second quarter of 2023 through the date of Emergence equal to $76,449 and $22,935, respectively. At Emergence, Messrs. Berryman and Wright were transitioned to the Current STI Program and did not receive KEIP Payments for the second quarter of 2023.
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•The Restructuring Committee certified certain “Asset Sale Bonuses” payable in connection with the sales of (i) certain mineral interests in Pennsylvania, (ii) an asset management and gas transportation agreement, and (iii) an office building in Montana. The Asset Sale Bonuses were paid between March and May 2023.
The KEIP was terminated upon Emergence in connection with the adoption of the Current STI Program described above.
Payments made to our NEOs under the KEIP for performance during 2023 are shown in the table directly below, and the aggregate payments made under the KEIP for 2023 performance are reported in the Summary Compensation Table below.
| Quarterly Performance Bonuses | Asset Sale Bonuses ($) | ||||||||||||||||||||||
| Named Executive Officer | Q1 2023 | Q2 2023 | |||||||||||||||||||||
| Brad Berryman | 37,545 | — | 116,776 | ||||||||||||||||||||
| Andrew Wright | 30,036 | — | 93,421 | ||||||||||||||||||||
| Alejandro Hernandez | 150,178 | 76,449 | (1) | 467,107 | |||||||||||||||||||
| John Chesser | 45,054 | 22,935 | (1) | 140,132 | |||||||||||||||||||
__________________
(1)Represents prorated payment made to NEO under the KEIP for the second quarter of 2023 through the date of Emergence, pursuant to the applicable Separation Agreement.
Special Emergence Bonuses
In June 2023, Messrs. Berryman, Wright and Chesser were awarded and paid one-time cash bonuses in amounts of $300,000, $200,000 and $300,000, respectively, in recognition of their contributions during the Restructuring.
Long-Term Equity-Based Incentives
Current Compensation Program: 2023 Equity Incentive Plan and Equity Awards
Upon Emergence, the Current Board approved the Talen Energy Corporation 2023 Equity Incentive Plan (the “2023 Equity Plan”), a new long-term equity incentive plan for employees and directors of the Company. Grants under the 2023 Equity Plan are denominated in shares of our common stock. Under the 2023 Equity Plan, participants may receive grants of shares, options to purchase shares, restricted stock, restricted stock units, performance-based awards and other stock-based and cash-based awards upon terms and conditions determined by the Current Board, as delegated to the Compensation Committee. A total of 7,083,461 shares of our common stock have been reserved for issuance with respect to awards under the 2023 Equity Plan.
Grants of time-based restricted stock units (“RSUs”) and performance-based restricted stock units (“PSUs”) were made to the Current NEOs. The amount of each award was based on the executive’s scope of responsibility and contribution to value creation, market-based compensation data and other relevant factors determined by our Compensation Committee in its discretion. These grants were intended to represent each executive’s long-term incentive grants for the first three years following Emergence, and regular annual long-term incentive grants are not expected to be made again until 2026. Following Emergence, the Current NEOs were granted the following equity awards under the 2023 Equity Plan:
2023 Emergence Grants (1) | ||||||||||||||||||||||||||
| Executive | Target Annual LTI Payout (% of Base Salary) | Number of RSUs | Target Number of PSUs | Target Value (in Dollars) | ||||||||||||||||||||||
| Mark McFarland | 700 | % | 223,141 | 334,711 | $ | 23,625,000 | ||||||||||||||||||||
| Terry L. Nutt | 400 | % | 62,338 | 93,507 | $ | 6,600,000 | ||||||||||||||||||||
| Brad Berryman | 400 | % | 62,338 | 93,507 | $ | 6,600,000 | ||||||||||||||||||||
| Andrew Wright | 400 | % | 60,071 | 90,107 | $ | 6,360,000 | ||||||||||||||||||||
| John Wander | 400 | % | 62,338 | 93,507 | $ | 6,600,000 | ||||||||||||||||||||
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__________________
(1)The Emergence grants are intended to reflect each Current NEO’s long-term incentive target for the three years following Emergence, and annual grants are expected to resume beginning in 2026.
The RSUs function as a retention incentive and vest in equal annual installments over three years from the “vesting commencement date” (which is generally approximately the grant date) and generally require continued service. The PSUs vest upon achievement of specified per-share values of the Company’s common stock, plus any dividends paid during the term of the award (the “Adjusted Equity Value”), as of the third anniversary of the vesting commencement date (or, if sooner, the occurrence of a “Change in Control” (as defined in the 2023 Equity Plan)), subject to continued service through such date (except as set forth below). The number of PSUs that vest (“Earned PSUs”) can range from 0% to 200% of the target number of PSUs subject to the award, plus, in the case of certain executive officers (including the Current NEOs), if the maximum Adjusted Equity Value set forth in the award agreement is exceeded, an additional incentive in an amount equal to the holder’s proportionate share amongst the participating executive officers of 1% of the Company’s market capitalization above such maximum Adjusted Equity Value. The recipients may not sell or transfer any of the shares of common stock received upon vesting of RSUs and PSUs until the earlier of a Change in Control or the third anniversary of Emergence.
| Performance Level | Adjusted Equity Value (per Share) | Earned PSUs (1) | ||||||||||||
| Threshold | $ | 42.35 | 0% | |||||||||||
| Target | $ | 52.52 | 100% | |||||||||||
| Maximum | $ | 73.69 | 200% | |||||||||||
| Above Maximum | >$73.69 | 1% of market capitalization implied by Adjusted Equity Value in excess of Maximum are allocated as incremental Earned PSUs (see above) | ||||||||||||
__________________
(1)No PSUs will become Earned PSUs if the Adjusted Equity Value is less than Threshold, and linear interpolation shall be used to determine the number of Earned PSUs to the extent that the Adjusted Equity Value is between the Threshold and Maximum amounts set forth in the table.
For treatment of the outstanding RSUs and PSUs upon certain terminations of employment or the occurrence of a “Change in Control,” see the section below entitled “—Potential Payments Upon Termination or Change in Control.”
Long-Term Cash Incentives
Pre-Emergence Compensation Program: Commercial and Risk Team Long-Term Incentive Plan
TES maintained the Commercial and Risk Team Long-Term Incentive Plan (the “CRIP”), pursuant to which certain employees of TES and its subsidiaries, including Mr. Chesser, were eligible to receive the cash retention bonus payments described below. None of the Current NEOs participate in the CRIP.
In March 2022, Mr. Chesser was granted an award under the CRIP, pursuant to which he was eligible to earn an aggregate cash retention bonus of $500,000, payable in three equal installments of $166,666.67 during the first 90 days of each of the 2022, 2023 and 2024 calendar years, subject to his continued employment through the date of payment. Mr. Chesser received his second installment payment under his CRIP award equal to $166,666.67 in June 2023 (which is reflected in the Summary Compensation Table). Mr. Chesser’s entitlement to the third installment payment under his CRIP award was forfeited in connection with his termination of employment in accordance with the terms and conditions of his severance arrangement. For additional information, see the section entitled “—Potential Payments upon Termination or Change of Control.”
Pre-Emergence: Retention Bonus Awards
In November 2021, the Prior Board granted retention bonus awards (the “Pre-Restructuring TRAs”) to certain key employees, including some of our NEOs, pursuant to which each participating NEO was eligible to receive a
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retention bonus in an amount equal to 100% of base salary, paid in two equal installments in November 2021 and November 2022 or such earlier date as determined by the Company’s then Chief Executive Officer after consultation with the Prior Board (the “Second TRA Installment”), subject to continued employment through the payment date and subject to vesting in the right to retain each installment. The participating NEOs were to become vested in the Second TRA Installment on the first anniversary of November 12, 2022. In the event of a “change in control,” vesting of the Second TRA Installment would accelerate to the 30th day following the consummation of such transaction. In April 2022, the Prior Board approved amendments to the Pre-Restructuring TRAs (the “Amended TRAs”), including those held by our participating NEOs, with respect to the timing of payment and vesting schedule of the Second TRA Installment. Under the Amended TRAs, the Second TRA Installment was paid to our participating executives in April 2022, and would vest upon the earliest of (i) December 31, 2023, (ii) 60 days following the effective date of a Chapter 11 plan of reorganization of the Company, and (iii) 30 days after the consummation of a “change in control,” subject to the executive continuing to diligently perform his duties through such date (except in limited circumstances). Accordingly, the Second TRA Installment under each participating NEO’s Amended TRA vested on June 17, 2023 (60 days following Emergence), except for Mr. Hernandez’s, which was deemed vested as of his termination of employment and is reported in the Summary Compensation Table as compensation earned in 2023.
The table below sets forth the value of each NEO’s Amended TRA opportunity earned by our NEOs in 2023:
| Executive | Second TRA Installment ($) | |||||||
| Andrew Wright | 386,623 | |||||||
| Brad Berryman | 365,106 | |||||||
| Alejandro Hernandez | 2,149,788 | |||||||
| John Chesser | 362,260 | |||||||
Other Executive Benefits and Perquisites
We provide the following benefits to our executive officers on the same basis as other eligible employees:
•health insurance;
•vacation, personal holidays and sick days;
•life insurance and supplemental life insurance;
•short-term and long-term disability;
•a $2,500 per year lifestyle account for wellness-related expenses (2023 only); and
•a 401(k) plan with matching contributions.
We believe these benefits are generally consistent with those offered by other companies and specifically with those companies with which we compete for employees.
In addition, Mr. Hernandez received special security arrangements, which included a personal protective detail, including secure transportation, for himself and his immediate family, as well as protective personnel and equipment for their residence.
Employment Agreements with Named Executive Officers
In connection with Emergence, we have entered into employment agreements with each of the Current NEOs, each of which has a three-year term and provides for each of the compensation elements of the Current Compensation Program described above, including base salary, annual bonus, and long-term equity incentive awards. The employment agreements also provide for each Current NEO’s eligibility to participate in the Company’s employee benefit plans, policies and arrangements that are generally available to executive officers. Mr.
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McFarland’s employment agreement entitles him to a cash signing bonus of $2,000,000, payable in two equal installments on each of May 17, 2024 and May 17, 2025 (the first two anniversaries of the execution date of his employment agreement). Mr. Wander’s employment agreement also entitles him to a cash signing bonus of $500,000, payable in two equal installments on each of June 19, 2023 and June 19, 2024 (the execution date of his employment agreement and the first anniversary thereof), subject to his continued employment through the date of payment and to a clawback provision if he is terminated for Cause or resigns without Good Reason (both as defined in his employment agreement) prior to June 19, 2024. The employment agreements also contain non-competition and non-solicitation restrictions applicable during the term of employment and for 12 months thereafter, as well as perpetual non-disparagement and confidentiality provisions. The employment agreements also provide for certain payments and benefits upon a termination by the Company without Cause or by the NEO for Good Reason or due to death or Disability, as described below in the section entitled “—Potential Payments Upon Termination or Change in Control.”
Stock Ownership Guidelines
We believe it is important for our executive officers to share in the ownership of Talen to ensure the alignment of their goals with the interests of our stockholders. We have established guidelines of equity ownership for our Chief Executive Officer equivalent to five times his base salary, for our other executive officers equivalent to three times their respective base salaries and for our non-employee directors equivalent to three times their respective annual cash retainers. Each will have a transition period to meet the requirements set forth in the guidelines to the extent they are not currently in compliance with these guidelines. We anticipate that the three-year holding restrictions on the vested RSUs and PSUs will enable our executive officers and non-employee directors who received such equity awards in 2023 to meet this requirement.
Prohibition on Hedging
We have adopted an insider trading policy prohibiting all employees, including executive officers, and directors from engaging in any form of hedging transaction involving our securities. The policy addresses short sales and transactions involving publicly traded options and prohibits such individuals from holding our securities in margin accounts and from pledging our securities as collateral for loans. We believe that these policies further align our executives’ interests with those of our stockholders.
Impact of Accounting and Tax Requirements on Compensation
The Current Board and our Compensation Committee consider tax deductibility and other tax implications when designing our executive compensation programs. However, we believe that there are certain circumstances where the provision of compensation that is not fully tax deductible, including by reason of Section 162(m) of the Code, is more consistent with our compensation objectives. Our Compensation Committee retains discretion and flexibility to award non-deductible compensation to our NEOs as it deems appropriate and in furtherance of our compensation philosophy and objectives.
Another section of the Code, Section 409A, affects the manner by which deferred compensation opportunities are offered to our employees because Section 409A requires, among other things, that “non-qualified deferred compensation” be structured in a manner that limits employees’ abilities to accelerate or further defer certain kinds of deferred compensation. We intend to operate our existing compensation arrangements that are covered by Section 409A in accordance with the applicable rules thereunder, and we will continue to review and amend our compensation arrangements where necessary to comply with Section 409A.
Further, Section 280G of the Code disallows a tax deduction with respect to “excess parachute payments” to certain executive officers of companies that undergo a change in control. In addition, Section 4999 of the Code imposes a 20% excise tax penalty on the individual receiving the “excess parachute payment.” Parachute payments are compensation that is linked to or triggered by a change in control and may include, but are not limited to, bonus payments, severance payments, certain fringe benefits, and payments and acceleration of vesting from long-term incentive plans or programs and other equity-based compensation. “Excess parachute payments” are parachute payments that exceed a threshold determined under Section 280G of the Internal Revenue Code based on an executive officer’s prior compensation. In approving compensation arrangements for our NEOs, the Current Board
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considers all elements of the cost to us of providing such compensation, including the potential impact of Section 280G of the Code. However, the Current Board may, in its judgment, authorize compensation arrangements that could give rise to loss of deductibility of Section 280G of the Code and the imposition of excise taxes under Section 4999 of the Code when it believes that such arrangements are appropriate to attract and retain executive talent.
Accounting for Stock-Based Compensation
We follow ASC 718 for our equity-based compensation awards. ASC 718 requires companies to calculate the grant date “fair value” of their equity-based awards using a variety of assumptions. ASC 718 also requires companies to recognize the compensation cost of their equity-based awards in their income statements over the period that an associate is required to render service in exchange for the award. Future grants of stock options, restricted stock, performance-based or other restricted stock units and other equity-based awards under our equity incentive award plans will be accounted for under ASC 718. The Compensation Committee regularly considers the accounting implications of significant compensation decisions, especially in connection with decisions that relate to our equity incentive award plans and programs. As accounting standards change, we may revise certain programs to appropriately align accounting expenses of our equity awards with our overall executive compensation philosophy and objectives.
Summary Compensation Table
The following table sets forth certain information with respect to compensation paid to, awarded to or earned by our NEOs for the years ended December 31, 2022 and December 31, 2023.
| Name and Principal Position | Year | Salary ($)(1) | Bonus ($)(2) | Stock Awards ($)(3) | Non-Equity Incentive Plan Compensation ($)(4) | All Other Compensation ($)(5) | Total ($) | |||||||||||||||||||||||||||||||||||||
Mark McFarland,(6) | 2023 | 683,654 | — | 27,667,227 | 1,210,079 | 13,782 | 29,574,742 | |||||||||||||||||||||||||||||||||||||
| President and Chief Executive Officer | 2022 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Terry L. Nutt,(7) | 2023 | 253,846 | — | 9,860,313 | 720,304 | 9,335 | 10,843,798 | |||||||||||||||||||||||||||||||||||||
| Chief Financial Officer | 2022 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
| Brad Berryman, | 2023 | 541,660 | 665,106 | 7,729,289 | 1,251,994 | 40,498 | 10,228,547 | |||||||||||||||||||||||||||||||||||||
| Senior Vice President and Chief Nuclear Officer | 2022 | 520,530 | 251,964 | — | 1,197,227 | 20,753 | 1,990,474 | |||||||||||||||||||||||||||||||||||||
Andrew Wright,(8) | 2023 | 529,598 | 586,623 | 7,448,229 | 1,145,461 | 49,488 | 9,759,399 | |||||||||||||||||||||||||||||||||||||
| Chief Administrative Officer (Former General Counsel and Corporate Secretary) | 2022 | 501,136 | 210,124 | — | 1,034,590 | 21,414 | 1,767,264 | |||||||||||||||||||||||||||||||||||||
John Wander,(9) | 2023 | 285,578 | 250,000 | 7,729,289 | 720,304 | 3,881 | 8,989,052 | |||||||||||||||||||||||||||||||||||||
| General Counsel and Corporate Secretary | 2022 | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||
Alejandro Hernandez,(10) | 2023 | 499,847 | — | — | 2,122,155 | 7,528,830 | 10,150,832 | |||||||||||||||||||||||||||||||||||||
| Former Chief Executive Officer | 2022 | 1,254,683 | 612,500 | — | 5,428,248 | 1,807,975 | 9,103,406 | |||||||||||||||||||||||||||||||||||||
John Chesser,(11) | 2023 | 264,581 | 828,927 | 576,128 | 1,222,966 | 2,892,602 | ||||||||||||||||||||||||||||||||||||||
| Former Chief Financial Officer | 2022 | 516,473 | 416,667 | — | 1,328,182 | 28,355 | 2,289,677 | |||||||||||||||||||||||||||||||||||||
__________________
(1)The amounts in this column for 2023 reflect amounts actually earned by each NEO, as described under “—Compensation Discussion and Analysis—Elements of Compensation—Base Salary.”
(2)The amounts in this column reflect (i) the Emergence Bonuses paid to Messrs. Berryman, Wright and Chesser, (ii) payment under the CRIP made in 2023 to Mr. Chesser, (iii) payments under the Amended TRA earned in 2023 by Messrs. Berryman, Wright, Hernandez and Chesser, and (iv) the first installment of Mr. Wander’s signing bonus. For additional information about these bonus programs, see “—
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Compensation Discussion and Analysis—Elements of Compensation—Short-Term Incentives” and “—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Cash Incentives.”
(3)The amounts in this column reflect the aggregate grant date fair value of the RSUs and PSUs granted under the 2023 Equity Plan, calculated in accordance with ASC Topic 718 and using the assumptions discussed under “Stock-Based Compensation” in Note 2 to the Annual Financial Statements. Under ASC Topic 718, the grant date fair values of all PSUs shown in the table are $17,291,170 for Mr. McFarland, $6,559,516 for Mr. Nutt, $4,830,572 for Mr. Berryman, $4,654,928 for Mr. Wright, and $4,830,572 for Mr. Wander. The payout value of the PSUs calculated at maximum performance achievement earned at the end of the three-year performance period would equal $49,329,707 for Mr. McFarland, $13,781,062 for Messrs. Nutt, Berryman and Wander, and $13,279,970 for Mr. Wright. Because the grant date fair value is based on the date the awards were granted, amounts in this column may vary among NEOs who received similar-sized awards but on different dates.
(4)The amounts in this column for 2023, detailed for each NEO below, reflect the cash amounts (i) earned by our NEOs in 2023 as Advanced STI Bonuses under the Pre-Emergence STI Program with respect to the first quarter of 2023 (which were prepaid in 2022), (ii) earned by and paid to our NEOs in 2023 under the Pre-Emergence STI Program with respect to the second quarter of 2023, (iii) earned by our NEOs in 2023 under the Current STI Program with respect to the third and fourth quarters of 2023 (which were paid in 2024), (iv) earned by and paid to our NEOs in 2023 as Asset Sale Bonuses under the KEIP, and (v) earned by and paid to our NEOs in 2023 as Quarterly Performance Bonuses under the KEIP with respect to the first quarter of 2023.
(a)For Mr. McFarland, a $1,210,079 payment under the STI Program for 2023.
(b)For Mr. Nutt, a $720,304 payment under the STI Program for 2023.
(c)For Mr. Berryman, (i) a $879,180 payment under the STI Program for 2023, which includes a $129,761 pre-payment as an Advanced STI Bonus for the Q1 STI and a $137,500 payment for the Q2 STI, (ii) $116,776 in payouts for the Asset Sale Bonuses, and (iii) a $256,037 payment for the Q1 KEIP.
(d)For Mr. Wright, (i) $847,210 under the STI Program for 2023, which includes a $128,750 pre-payment as an Advanced STI Bonus for the Q1 STI and a $132,500 payment for the Q2 STI, (ii) $93,421 in payouts for the Asset Sale Bonuses, and (iii) a $204,830 payment for the Q1 KEIP.
(e)For Mr. Wander, a $720,304 payment under the STI Program for 2023.
(f)For Mr. Hernandez, (i) a $631,000 payment for the Q1 STI, (ii) $467,107 in payouts for the Asset Sale Bonuses, and (iii) a $1,024,048 payment for the Q1 KEIP.
(g)For Mr. Chesser, (i) a $128,750 payment for the Q1 STI, (ii) $140,132 in payouts for the Asset Sale Bonuses, and (iii) a $307,244 payment for the Q1 KEIP.
For additional information about these short-term incentive programs, see “—Compensation Discussion and Analysis—Elements of Compensation—Short-Term Incentives.”
(5)The amounts in this column for 2023 reflect the following perquisites received by our NEOs in the amounts set forth in the following table: (a) payments for the cost of premiums for a term life insurance policy paid by us, (b) an employer matching contribution to the 401(k) plan, (c) an employer discretionary contribution to the 401(k) Plan, (d) a contribution to the NEO’s health savings account, (e) expenses under the NEO’s lifestyle account, (f) payments for financial counseling services, (g) a payment for the cost of health and welfare benefits for the NEO’s dependent(s), and (h) other perquisites and payments (described further below).
| Name | Term Life Insurance Policy ($) | 401(k) Plan Matching Contribution($) | 401(k) Plan Discretionary Contribution($) | Health Saving Account ($) | Lifestyle Account ($) | Financial Counsel Services ($) | Dependent Health and Welfare ($) | Other Perquisites and Payments ($) | ||||||||||||||||||||||||||||||||||||||||||
| Mark McFarland | 1,614 | — | — | — | 2,293 | 9,875 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Terry L. Nutt | 415 | 4,231 | — | 554 | 2,500 | 1,635 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Brad Berryman | 2,498 | 13,200 | 6,100 | 1,200 | 2,500 | 15,000 | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Andrew Wright | 2,477 | 13,200 | 6,100 | 1,200 | 2,500 | 15,000 | 9,011 | — | ||||||||||||||||||||||||||||||||||||||||||
| John Wander | 1,389 | — | — | — | 2,500 | — | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Alejandro Hernandez | 723 | 13,200 | 6,100 | 508 | 2,428 | 15,000 | — | 7,490,871(x) | ||||||||||||||||||||||||||||||||||||||||||
| John Chesser | 465 | 11,488 | 6,100 | 646 | — | 8,014 | 4,820 | 1,191,433(y) | ||||||||||||||||||||||||||||||||||||||||||
__________________
(x)Mr. Hernandez received severance payments with an aggregate value of $6,035,776, comprised of (i) a $3,785,250 lump sum cash payment equal to the sum of his base salary and target annual bonus for 2023, (ii) $24,289 for reimbursement of his monthly premiums under COBRA (as defined below) for 12 months, (iii) a $76,449 lump sum cash payment equal to pro-rated Quarterly Performance Bonus under the KEIP for the second quarter of 2023, and (iv) accelerated vesting of his $2,149,788 Second TRA Installment payment. Amount also includes $1,455,095 to reflect the aggregate incremental cost of the personal security arrangements implemented following the security review described under “—Other Executive Benefits and Perquisites.”
(y)Mr. Chesser received severance payments with an aggregate value of $1,191,433, comprised of (x) a $1,173,325 lump sum cash payment equal to the sum of his base salary and target annual bonus for 2023, $15,000 for a financial advisory service, and $100,000 for post-Emergence services to the Company and (y) $18,108 for reimbursement of his monthly premiums under COBRA for 12 months.
(6)Mr. McFarland commenced employment as President and Chief Executive Officer of the Company, effective as of May 17, 2023.
(7)Mr. Nutt commenced employment as Chief Financial Officer of the Company, effective as of July 10, 2023.
(8)Mr. Wright was promoted to Chief Administrative Officer of the Company, effective as of June 28, 2023. He had previously served as the Company’s General Counsel and Corporate Secretary.
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(9)Mr. Wander commenced employment as General Counsel and Corporate Secretary on June 19, 2023.
(10)Mr. Hernandez ceased employment as Chief Executive Officer of the Company, effective as of May 17, 2023.
(11)Mr. Chesser ceased employment as Chief Financial Officer of the Company, effective as of July 7, 2023.
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Grants of Plan-Based Awards for Fiscal 2023
The following table sets forth information with respect to non-equity incentive plan awards, RSUs and PSUs awarded during fiscal 2023 to each of the NEOs, except Messrs. Hernandez and Chesser, who were not granted any such awards during 2023.
| Estimated Future Payouts Under Non-Equity Incentive Plan Awards | Estimated Future Payouts Under Equity Incentive Plan Awards | All Other Stock Awards: Number of Shares of Stock or Units (#) | Grant Date Fair Value of Stock and Option Awards ($) (2) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Name | Grant Type | Grant Date | Approval Date(1) | Threshold ($) | Target ($) | Maximum ($) | Threshold (#) | Target (#) | Maximum (#) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Mark McFarland | Q3 – Q4 STI (3) | — | — | — | $ | 948,699 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RSU (4) | 6/16/2023 | 6/16/2023 | 223,141 | $ | 10,376,057 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSU (5) | 6/16/2023 | 6/16/2023 | — | 334,711 | 669,422 | $ | 17,291,170 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Terry L. Nutt | Q3 – Q4 STI (3) | — | — | $ | 550,000 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RSU (4) | 7/10/2023 | 6/16/2023 | 62,338 | $ | 3,300,797 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSU (5) | 7/10/2023 | 6/16/2023 | — | 93,507 | 187,014 | $ | 6,559,516 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Brad Berryman | Q2 STI(6) | — | — | — | $ | 137,500 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Q3 – Q4 STI (3) | — | — | — | $ | 550,000 | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RSU (4) | 6/16/2023 | 6/16/2023 | 62,338 | $ | 2,898,717 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSU (5) | 6/16/2023 | 6/16/2023 | — | 93,507 | 187,014 | $ | 4,830,572 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Andrew Wright | Q2 STI(6) | — | — | — | $ | 132,500 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Q3 – Q4 STI (3) | — | — | — | $ | 530,000 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RSU (4) | 6/16/2023 | 6/16/2023 | 60,071 | $ | 2,793,302 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSU (5) | 6/16/2023 | 6/16/2023 | — | 90,107 | 180,214 | $ | 4,654,928 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| John Wander | Q3 – Q4 STI (3) | — | — | — | $ | 550,000 | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
RSU (4) | 6/16/2023 | 6/16/2023 | 62,338 | $ | 2,898,717 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
PSU (5) | 6/16/2023 | 6/16/2023 | — | 93,507 | 187,014 | $ | 4,830,572 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
__________________
(1)All awards were approved by the Compensation Committed on June 16, 2023. Awards granted to Terry L. Nutt were contingent on and effective as of the date of his commencement of employment with the Company.
(2)The amounts in this column reflect the grant date fair values of the RSUs and PSUs calculated in accordance with ASC Topic 718 and using the assumptions discussed under “Stock-Based Compensation” in Note 2 to the Annual Financial Statements.
(3)Amounts represent awards payable under our Current STI Program granted pursuant to each applicable NEO’s employment agreement. Amounts pay out based on a percentage of the applicable target value (which is a percentage of base salary) based on achievement of pre-determined performance criteria. Mr. McFarland’s short-term incentive opportunity is based on a target amount equal to 135% of his base salary, prorated based on his days of service for 2023. For additional information, see section entitled “—Compensation Discussion and Analysis—Elements of Compensation—Short-Term Incentives.”
(4)Amounts reflect the RSUs granted under the 2023 Equity Plan, the terms of which are summarized under “—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Equity Incentives.”
(5)Amounts reflect the PSUs granted under the 2023 Equity Plan, the terms of which are summarized under “—Compensation Discussion and Analysis—Elements of Compensation—Long-Term Equity Incentives.”
(6)Amounts represent awards payable under the Pre-Emergence STI Program with respect to the second quarter of 2023, which were paid out at target in August 2023. For additional information, see section entitled “—Compensation Discussion and Analysis—Elements of Compensation—Short-Term Incentives.”
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Outstanding Equity Awards at 2023 Fiscal Year End
The following table sets forth certain information with respect to outstanding equity awards of our NEOs for the year ended December 31, 2023. The market value of the shares in the following table reflects the fair market value of such shares as of December 31, 2023.
| Stock Awards | |||||||||||||||||||||||||||||
| Name | Number of Shares or Units of Stock That Have Not Vested (#) (1) | Market Value of Shares or Units of Stock That Have Not Vested ($) (2) | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) (3) | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) (2) | |||||||||||||||||||||||||
| Mark McFarland | 223,141 | 14,281,024 | 669,422 | 42,843,008 | |||||||||||||||||||||||||
| Terry L. Nutt | 62,338 | 3,989,632 | 187,014 | 11,968,896 | |||||||||||||||||||||||||
| Brad Berryman | 62,338 | 3,989,632 | 187,014 | 11,968,896 | |||||||||||||||||||||||||
| Andrew Wright | 60,071 | 3,844,544 | 180,214 | 11,533,696 | |||||||||||||||||||||||||
| John Wander | 62,338 | 3,989,632 | 187,014 | 11,968,896 | |||||||||||||||||||||||||
Alejandro Hernandez (4) | 70.66 | — | (5) | — | — | ||||||||||||||||||||||||
(1)Represents RSUs granted on June 16, 2023 (or for Mr. Nutt, July 10, 2023) that are eligible to vest in equal annual installments on the first, second and third anniversary of the vesting commencement date, subject to continued employment (except in certain scenarios as described in the section entitled “—Potential Payment upon Termination or Change in Control”). The vesting commencement date is (i) May 17, 2023 for the RSUs held by Messrs. McFarland, Berryman and Wright; (ii) July 10, 2023 for RSUs held by Mr. Nutt; and (iii) June 19, 2023 for RSUs held by Mr. Wander.
(2)Market values reported in the table are calculated based on the fair market value of the Company’s common stock as of December 31, 2023, $64.00.
(3)Represents PSUs granted on June 16, 2023 (or for Mr. Nutt, July 10, 2023) that are eligible to vest upon achievement of specified per‑share values of common stock, plus any dividends paid during the term of the award, as of the third anniversary of the vesting commencement date, subject to continued employment (except in certain scenarios as described in the section entitled “—Potential Payment Upon Termination or Change in Control”). The vesting commencement date for all the PSUs is May 17, 2023. As of the end of 2023, the performance for the PSUs was at 154% of target, based on our stock price of $64.00 as of December 31, 2023. Because performance for the PSUs exceeded the target level as of the end of 2023, the number of shares in this column represents the maximum level of performance.
(4)As part of the pre-Restructuring long-term incentive awards granted to NEOs, Mr. Hernandez previously received restricted interests, subject to certain vesting conditions, in Raven Power Holdings LLC (the “Raven Power Incentive Units”), which owned 56.6% of the voting equity of Talen MidCo LLC and approximately 28.9% of Talen directly as of the Company’s commencement of the Restructuring.
(5)Because the Raven Power Incentive Units are with respect to a private entity that holds a minority interest in Talen, there is no readily ascertainable market value for these units.
Options Exercised and Stock Vested
No equity awards fully vested with respect to our NEOs during the year ended December 31, 2023.
Pension Benefits
Our NEOs did not participate in or have account balances in pension plans sponsored by us.
Nonqualified Deferred Compensation
Our NEOs did not participate in or have account balances in nonqualified defined contribution plans or other nonqualified deferred compensation plans maintained by us. The Current Board or the Compensation Committee may elect to provide our executive officers and other employees with nonqualified defined contribution or other nonqualified deferred compensation benefits in the future if it determines that doing so is in our best interest.
Potential Payments Upon Termination or Change in Control
The following table provides information regarding potential payments to certain of our NEOs as of December 31, 2023 in connection with certain termination or change in control events. The payments set forth below for
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Messrs. Hernandez and Chesser represent the payments actually received upon termination of employment during 2023.
| Benefits and Payments upon Termination | Cash Severance ($) | Aggregate Value of Accelerated Equity Awards ($) (1) | COBRA Payments ($) | Total ($) | |||||||||||||||||||||||||||||||
| Mark McFarland | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 6,147,397 | (2) | $ | 14,281,024 | (7) | $ | — | $ | 20,428,421 | |||||||||||||||||||||||||
| Termination due to death or Disability | $ | 759,375 | (3) | $ | — | $ | — | $ | 759,375 | ||||||||||||||||||||||||||
| Change in Control (w/ or w/o termination) | $ | — | $ | 47,270,140 | (8) | $ | — | $ | 47,270,140 | ||||||||||||||||||||||||||
| Terry L. Nutt | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 1,100,000 | (4) | $ | 633,969 | (9) | $ | — | $ | 1,763,969 | |||||||||||||||||||||||||
| Termination due to death or Disability | $ | 275,000 | (3) | $ | — | $ | — | $ | 275,000 | ||||||||||||||||||||||||||
| Change in Control (w/ or w/o termination) | $ | — | $ | 13,205,682 | (8) | $ | — | $ | 13,205,682 | ||||||||||||||||||||||||||
| Brad Berryman | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 1,100,000 | (4) | $ | 830,718 | (9) | $ | — | $ | 1,930,718 | |||||||||||||||||||||||||
| Termination due to death or Disability | $ | 275,000 | (3) | $ | — | $ | — | $ | 275,000 | ||||||||||||||||||||||||||
| Change in Control (w/ or w/o termination) | $ | — | $ | 13,205,682 | (8) | $ | — | $ | 13,205,682 | ||||||||||||||||||||||||||
| Andrew Wright | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 1,060,000 | (4) | $ | 800,508 | (9) | $ | — | $ | 1,860,508 | |||||||||||||||||||||||||
| Termination due to death or Disability | $ | 265,000 | (3) | $ | — | $ | — | $ | 265,000 | ||||||||||||||||||||||||||
| Change in Control (w/ or w/o termination) | $ | — | $ | 12,725,490 | (8) | $ | — | $ | 12,725,490 | ||||||||||||||||||||||||||
| John Wander | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 1,100,000 | (4) | $ | 710,482 | (9) | $ | — | $ | 1,810,482 | |||||||||||||||||||||||||
| Termination due to death or Disability | $ | 212,500 | (3) | $ | — | $ | — | $ | 212,500 | ||||||||||||||||||||||||||
| Change in Control (w/ or w/o termination) | $ | — | $ | 13,205,682 | (8) | $ | — | $ | 13,205,682 | ||||||||||||||||||||||||||
| Alejandro Hernandez | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 5,935,038 | (5) | $ | — | $ | 24,289 | (10) | $ | 5,959,327 | |||||||||||||||||||||||||
| John Chesser | |||||||||||||||||||||||||||||||||||
| Termination w/o Cause or w/ Good Reason | $ | 1,173,325 | (6) | $ | — | $ | 18,108 | (10) | $ | 1,191,433 | |||||||||||||||||||||||||
__________________
(1)Amounts in this column are calculated based on the market value of the Company’s common stock as of December 31, 2023.
(2)Amount represents (i) cash payment equal to two-times the sum of Mr. McFarland’s base salary and target annual bonus for 2023 (which is based on a target amount equal to 135% of his base salary, prorated based on his days of service for 2023), payable over 24 months following the separation date and (ii) full accelerated vesting of Mr. McFarland’s $2,000,000 signing bonus, payable within 60 days following termination of employment.
(3)Upon termination of employment due to death or “Disability,” each NEO would be entitled to earn the unpaid portion of the annual bonus for 2023 (i.e., in respect of the third and fourth quarters of 2023) based on actual performance results for the third and fourth quarters of 2023, pro-rated based on days employed during such period. Because we cannot yet determine, as of the date of this filing, the actual amounts earned under the Current STI Program with respect to the third and fourth quarters of 2023, the amounts reported here are estimates based on pro-rated target annual bonus amount for 2023 for each NEO.
(4)For each NEO, amounts represent a cash payment equal to one-times the sum of their base salary and target annual bonus for the performance year in which the termination date occurs, payable over 12 months following the separation date.
(5)Amount represents (x) a lump sum payment made to Mr. Hernandez upon his separation from the Company equal to the sum of his base salary and target annual bonus at the time of such separation pursuant to Mr. Hernandez’s separation agreement (described below), (y) a lump sum cash payment equal to pro-rated Quarterly Performance Bonus under the KEIP for the second quarter of 2023, and (z) accelerated vesting of his $2,149,788 Second TRA Installment payment.
(6)Amount represents a lump sum payment made to Mr. Chesser upon his separation from the Company equal to the sum of his base salary and target annual bonus at the time of such separation, plus $15,000 for a financial advisory service, and $100,000 for post-Emergence services to the Company pursuant to Mr. Chesser’s separation agreement (described below).
(7)Amount represents the value of accelerated vesting of Mr. McFarland’s 223,141 unvested RSUs.
(8)For each NEO, represents the value of (i) accelerated vesting of all outstanding RSUs and (ii) accelerated vesting of the number of PSUs that would vest based on achievement of performance criteria as of such Change in Control (which, assuming a Change in Control that occurred on December 31, 2023, and using our stock price of $64.00 as of such date, would result in vesting at 154% of target). The table above does not reflect any excise tax on amounts that could be considered “excess parachute payments” as a result of Sections 280G or 4999 of the Code.
(9)For each NEO, represents the value of accelerated vesting of a pro rata portion of the next scheduled annual vesting tranche of each NEO’s outstanding RSUs, calculated based on the number of days from the vesting commencement date to the date of the NEO’s termination divided by 365 (and assuming a termination occurred on December 31, 2023).
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(10)Amounts represent the cost to the Company of reimbursement of the cost of the NEO’s COBRA coverage premiums for 12 months following the date of separation.
Severance Entitlements Under Current Employment Agreements
Under the employment agreements between the Company and each of Messrs. McFarland, Nutt, Berryman, Wright, and Wander (the “Current Employment Agreements”), if the Company terminates the NEO’s employment without “Cause” or the NEO terminates his employment for “Good Reason,” in each case, subject to timely execution of a release of claims and continued compliance with the restrictive covenant obligations set forth in the Current Employment Agreement, then (i) such NEO is entitled to a cash payment equal to one-times (or, for Mr. McFarland, two-times) the sum of his base salary and target annual bonus for the performance year in which such termination occurs, payable over 12 months (or, for Mr. McFarland, payable over 24 months) following the separation date, and (ii) for Mr. McFarland only, any unpaid portion of his signing bonus shall automatically vest and be paid within 60 days following the termination date.
Under the Current Employment Agreements, upon the applicable NEO’s termination of employment due to his death or Disability, such NEO is entitled to a pro rata portion of the NEO’s annual bonus for the year in which such termination occurs based on actual performance results for the applicable bonus year, prorated for the period of days beginning on January 1 (or, if later, the effective date of the Current Employment Agreement) and ending on the date of such termination of employment relative to the number of days in the applicable bonus year. Such prorated annual bonus is payable in cash at the same time corresponding annual bonuses are paid to similarly situated employees of the Company.
“Cause” is defined in each Current Employment Agreement as the NEO’s: (i) fraud or misconduct; (ii) violation of applicable law in connection with the management, operation or reputation of the Company or any other member of the Company Group (as defined therein) that results in (or could reasonably be expected to result in) material injury to the Company or any other member of the Company Group; (iii) material breach of the Current Employment Agreement or any other written agreement between the NEO and one or more members of the Company Group, including the NEO’s material breach of any representation, warranty or covenant made under any such agreement; (iv) act of theft, embezzlement or misappropriation of the property of the Company or any other member of the Company Group, in each case, that results in (or could reasonably be expected to result in) material financial or reputational harm to the Company or any other member of the Company Group; (v) breach of his duty of loyalty to the Company or violation of the Company’s policies (to the extent such policies have been clearly communicated in writing to NEO), including the Company’s code of conduct and business ethics (or similar policies), anti-harassment policy, anti-retaliation or policies related to age, sex or other prohibited discrimination in the workplace; or (vi) conviction or plea of nolo contendere to a felony or crime involving moral turpitude.
“Disability” is defined in each Current Employment Agreement as the NEO’s inability to perform the essential functions of his position (after accounting for reasonable accommodation, if applicable and required by applicable law), due to physical or mental impairment, that continues for a period in excess of 90 consecutive days or 180 days, whether or not consecutive (or for any longer period as may be required by applicable law), in any 12-month period (as determined in the reasonable opinion of a licensed physician).
“Good Reason” is defined in each Current Employment Agreement as the occurrence of any of the following, in each case without the NEO’s written consent and which the Company fails to cure within 30 days of receipt of notice: (i) a material adverse change in the NEO’s title, duties or responsibilities (including reporting responsibilities); (ii) a material reduction in the NEO’s base salary; (iii) a relocation of the NEO’s primary work location by a distance of more than 50 miles; or (iv) a material breach by the Company of any of its obligations under the respective Current Employment Agreement.
Treatment of Long-Term Equity Incentive Awards
Termination without Cause or with Good Reason; Death or Disability. Generally, for NEOs other than Mr. McFarland, (i) upon a termination of employment by the Company without “Cause” or a resignation by the recipient for “Good Reason” (each as defined in the applicable Current Employment Agreement) or (ii) upon a termination due to death or Disability (as defined in the applicable Current Employment Agreement) that occurs on or following
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the first anniversary of Emergence, (a) a pro rata portion of the RSUs that otherwise would have vested on the next scheduled vesting date will vest, with all other unvested RSUs being forfeited, and (b) the target number of PSUs subject to the award will be reduced pro-rata to reflect the portion of the performance period during which the recipient was employed with the Company (and will otherwise remain outstanding and eligible to vest based on actual performance). Upon termination by the Company or the holder for any other reason, all unvested RSUs and PSUs will be canceled and forfeited.
For RSUs and PSUs granted to Mr. McFarland, upon a termination due to Mr. McFarland’s death or “Disability,” his RSUs and PSUs will vest in the same manner as the RSUs and PSUs held by the other NEOs. In the case of a termination of Mr. McFarland’s employment by the Company without “Cause” or a resignation for “Good Reason,” (a) all of Mr. McFarland’s outstanding unvested RSUs will immediately vest and (b) all of Mr. McFarland’s outstanding PSUs will fully time-vest and will remain outstanding and eligible to vest based on actual performance.
Change in Control. Upon the occurrence of a “Change in Control” (as defined in the 2023 Equity Plan) all outstanding RSUs and PSUs held by the NEOs will fully vest (with PSUs vesting based on the implied Adjusted Equity Value in connection with such Change in Control), subject to the NEO’s continued employment through such Change in Control.
Raven Power Incentive Units. Mr. Hernandez had previously received and held as of the date of his termination of employment, restricted interests, subject to certain vesting conditions, in Raven Power Holdings LLC (the “Raven Power Incentive Units”), which owned approximately 28.9% of Talen directly as of the Company’s commencement of Restructuring. The Raven Power Incentive Units granted to Mr. Hernandez were subject to both time-vesting and performance-vesting conditions and were entitled to certain vesting acceleration treatment upon Mr. Hernandez’s termination of employment without cause. However, these equity interests had a value of $0 as of the date of Mr. Hernandez’s termination of employment, so he did not receive any payment or otherwise benefit from such vesting upon his termination of employment.
Amended TRA
Lapse of Clawback of TRA Payments. In the event an NEO’s employment with the Company terminates prior to the vesting of the Second TRA Installment payment due to the NEO’s death or permanent disability (as determined by the Company) or by the Company without “Cause” or by the NEO for “Good Reason” (each, as defined in the NEO’s Pre-Emergence Employment Agreement), the Second TRA Installment would vest in full, subject to the NEO’s timely execution of a release of claims.
Separation Agreements
Separation Agreement with Mr. Hernandez. In connection with Mr. Hernandez’s separation on May 17, 2023, Mr. Hernandez entered into a Separation Agreement and General Release of Claims, pursuant to which he was entitled to receive: (i) a cash payment equal to the sum of his base salary and target annual bonus for 2023, payable in a single lump sum payment, (ii) reimbursements of his monthly premiums under the Consolidated Omnibus Budget Reconciliation Act of 1985, as amended (“COBRA”), for 12 months, in each case subject to his non‑revocation of the general release of claims and continued abidance by the restrictive covenant obligations under his employment agreement, and (iii) a pro-rated portion of the Quarterly Performance Bonus under the KEIP for the second quarter of 2023.
Separation Agreement with Mr. Chesser. In connection with Mr. Chesser’s separation on July 7, 2023, Mr. Chesser entered into a Separation Agreement and General Release of Claims, pursuant to which he was entitled to receive: (i) a lump sum cash payment equal to the sum of his base salary and target annual bonus for 2023; (ii) a lump sum cash payment equal to $15,000 for financial advisory services; (iii) a lump sum cash payment equal to $100,000 for post-Emergence services to the Company; and (iv) reimbursements of his monthly premiums under COBRA for 12 months, in each case subject to his non-revocation of the general release of claims and continued abidance by the restrictive covenant obligations under the Non-Competition, Non-Solicitation and Confidentiality Agreement between Mr. Chesser and the Company.
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Director Compensation
The table below provides information on the compensation of our non-employee directors for service on the board of directors of either the Company or TES during the year ended December 31, 2023. As required by applicable SEC rules, the disclosure in this section covers all persons who at any time served as a director during 2023, other than Mr. Hernandez, who previously served as our President and Chief Executive Officer and Mr. McFarland, who currently serves as our Chief Executive Officer, neither of whom received additional compensation for serving as a director. For summary information on the provisions of the applicable plans and programs, refer to the discussion immediately following this table.
| Name | Fees Earned or Paid in Cash ($)(1) | Stock Awards ($)(2) | Total ($) | |||||||||||||||||
| Current Board | ||||||||||||||||||||
| Stephen Schaefer | $ | 150,000 | $ | 1,552,370 | $ | 1,702,370 | ||||||||||||||
Gizman Abbas(3) | $ | 109,375 | $ | 576,461 | $ | 685,836 | ||||||||||||||
Anthony Horton(4) | $ | 109,375 | $ | 576,461 | $ | 685,836 | ||||||||||||||
Karen Hyde(5) | $ | 106,250 | $ | 576,461 | $ | 682,711 | ||||||||||||||
Joseph Nigro(6) | $ | 101,563 | $ | 576,461 | $ | 678,024 | ||||||||||||||
Christine Benson Schwartzstein(7) | $ | 98,438 | $ | 576,461 | $ | 674,899 | ||||||||||||||
| Prior Board | ||||||||||||||||||||
Ralph Alexander(8) | — | — | — | |||||||||||||||||
Pierre Lapeyre, Jr.(8) | — | — | — | |||||||||||||||||
David Leuschen(8) | — | — | — | |||||||||||||||||
John Staudinger(8) | — | — | — | |||||||||||||||||
Carol Flaton(9) | $ | 187,500 | — | $ | 187,500 | |||||||||||||||
Gary Wojtaszek(9) | $ | 187,500 | — | $ | 187,500 | |||||||||||||||
__________________
(1)Our non-employee directors serving on the Current Board receive a base annual cash retainer of $100,000, paid quarterly in arrears. For 2023, because the non-employee directors of the Current Board began serving upon Emergence on May 17, 2023, their base annual cash retainer was pro-rated for the number of days served during 2023. Mr. Schaefer served as the Non-Executive Chair of the Current Board and, in such capacity, received an additional cash retainer of $100,000, which was also pro-rated for the number of days served in 2023. In addition, in December 2023, our non-employee directors serving on the Current Board received a special one-time cash payment of an additional $25,000 as compensation for increased demands in the second half of 2023. These amounts also include an additional $25,000 for additional off-cycle meetings held in 2023 (approved by the Board and paid in December 31, 2023).
(2)On June 16, 2023, our non-employee directors were awarded RSUs with a grant date fair value of $576,461 that are subject to time-vesting and will vest ratably on each of the first, second and third anniversaries of May 17, 2023 (the vesting commencement date for such awards). In addition, Mr. Schaefer as the Non-Executive Chair of the Current Board was awarded PSUs with a grant date value of $975,909 that are eligible to vest following the third anniversary of May 17, 2023 (the vesting commencement date for the PSUs) subject to achievement of certain performance goals. The amounts in this column reflect the aggregate grant date fair value of the RSUs and PSUs granted under the 2023 Equity Plan, calculated in accordance with ASC Topic 718 and using the assumptions discussed under “Stock-Based Compensation” in Note 2 to the Annual Financial Statements. Under ASC Topic 718, the grant date fair value of Mr. Shaefer’s PSUs shown in the table is $975,909. The payout value of the PSUs calculated at maximum performance achievement earned at the end of the three-year performance period would equal $2,784,156 for Mr. Schaefer.
(3)Mr. Abbas served as (i) the Chair of the Nominating and Governance Committee and received an additional cash retainer of $15,000 in such capacity, (ii) a member of the Audit Committee and received an additional cash retainer of $10,000 in such capacity, and (iii) a member of the Compensation Committee and received an additional cash retainer of $10,000 in such capacity, in each case, pro-rated based on the number of days served during 2023.
(4)Mr. Horton served as (i) the Chair of the Compensation Committee and received an additional cash retainer of $15,000 in such capacity, (ii) a member of the Audit Committee and received an additional cash retainer of $10,000 in such capacity, and (iii) a member of the Risk Committee and received an additional cash retainer of $10,000 in such capacity, in each case, pro-rated based on the number of days served during 2023.
(5)Ms. Hyde served as (i) the Chair of the Audit Committee and received an additional cash retainer of $20,000 in such capacity and (ii) a member of the Compensation Committee and received an additional cash retainer of $10,000 in such capacity, in each case, pro-rated based on the number of days served during 2023.
(6)Mr. Nigro served as (i) the Chair of the Risk Committee and received an additional cash retainer of $15,000 in such capacity and (ii) a member of the Nominating and Governance Committee and received an additional cash retainer of $7,500 in such capacity, in each case, pro-rated based on the number of days served during 2023.
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(7)Ms. Benson served as (i) a member of the Risk Committee and received an additional cash retainer of $10,000 in such capacity and (ii) a member of the Nominating and Governance Committee and received an additional cash retainer of $7,500 in such capacity, in each case, pro-rated based on the number of days served during 2023.
(8)Directors serving on the Prior Board and affiliated with Riverstone, our sole stockholder prior to the Restructuring, did not receive compensation for serving on the Prior Board.
(9)Our independent directors serving on the Prior Board received a monthly cash fee of $37,500 for each month of service during 2023, through and including May 2023.
Post-Emergence 2023 Director Compensation
Upon Emergence, the Current Board approved a new director compensation program for directors of the Company. Annual non-employee director fees for fiscal 2023 were set at $100,000 payable in cash quarterly in arrears. The Non-Executive Chair of the Current Board also receives an annual retainer in the amount of $100,000 (in addition to the standard annual non-employee director fees), payable in cash quarterly in arrears (or in restricted stock units with a one-year cliff). In addition, in the third quarter of 2023, the Current Board approved a special one-time payment of an additional $25,000 to each non-employee director as compensation for a number of additional off-cycle board and committee meetings in the second half of 2023, which was paid in cash in December 2023.
In addition to annual fees, non-employee directors serving on standing committees of the Current Board were paid as follows: an additional $10,000 Audit Committee members (or $20,000 for the Chair of the Audit Committee); an additional $10,000 for Compensation Committee members (or $15,000 for the Chair of the Compensation Committee); an additional $10,000 for Risk Oversight Committee members (or $15,000 for the Chair of the Risk Oversight Committee); and an additional $7,500 for Nominating and Corporate Governance Committee members (or $15,000 for the Chair of the Nominating and Corporate Governance Committee).
In addition to the fees above, each director serving on the Current Board as of Emergence received a grant of 12,397 RSUs under the 2023 Equity Plan, which will vest in equal annual installments over three years. In 2026, the Company intends to transition to annual equity grants for directors with one-year cliff vesting in an amount to be determined. Upon a termination of a non-employee director’s service on the Current Board for any reason, all unvested RSUs will be forfeited. Upon the occurrence of a “Change in Control” (as defined in the 2023 Equity Plan), all unvested RSUs held by non‑employee directors will immediately vest.
In addition to the fees and grant above, the Non-Executive Chair of the Current Board, Stephen Schaefer, also received a grant of 18,891 PSUs under the 2023 Equity Plan, which will vest on the same terms as PSU grants received by the Current NEOs (other than Mr. McFarland) described above, including provisions for accelerated vesting upon certain termination events, such as enhanced benefits in connection with a “Change in Control.” Upon a termination of his service on the Current Board without “Cause” (as defined in the 2023 Equity Plan), or upon a termination due to death or disability that occurs on or following the first anniversary of Emergence, the target number of PSUs subject to the award will be reduced pro-rata to reflect the portion of the performance period during which Mr. Schaefer was a director of the Company (and will otherwise remain outstanding and eligible to vest based on actual performance). Upon termination by the Company for any other reason, all unvested PSUs will be canceled and forfeited.
The non-employee directors may not sell or transfer any of the shares of common stock received upon vesting of RSUs (or, in the case of Mr. Schaefer, PSUs) until the earlier of a “Change in Control” or the third anniversary of Emergence.
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CERTAIN RELATIONSHIPS AND RELATED PARTY TRANSACTIONS
Other than compensation arrangements for our directors and executive officers, which are described elsewhere in this prospectus, the following are certain transactions, arrangements and relationships with our directors, executive officers or holders of more than 5% or more of our outstanding capital stock. Most of the arrangements disclosed herein are included due to our historical affiliation with Riverstone, whose affiliates owned 100% of the our common stock from December 2016 until Emergence, and, due to warrants issued pursuant to the Plan of Reorganization, continued to be deemed beneficial owners of more than 5% of our common stock until the warrants were repurchased in September 2023. Additionally, Riverstone affiliates owned more than 10% of the common equity units of Cumulus Digital Holdings from September 2022 until September 2023. Accordingly, arrangements disclosed include applicable transactions between us and affiliates of Riverstone, as well as applicable transactions between us and Cumulus Digital Holdings and its subsidiaries.
Riverstone Management Fees
Prior to the filing of the Restructuring, TES had customary agreements with affiliates of Riverstone for management services and reimbursement of expenses. Under these agreements, TES paid approximately $1.1 million for management services provided and expenses incurred from January to November 2021. In November 2021, Riverstone agreed to suspend payment of the management fees. The agreements were terminated and remaining fees were waived by Riverstone in connection with the Restructuring.
Employment of Independent Contractor
During 2021 and 2022, TES engaged the services of an immediate family member of an executive officer of the Company through an unaffiliated staffing services firm. TES paid $142,000 and $88,000 under this arrangement during the years ended December 31, 2021 and 2022, respectively. The arrangement ended in the second quarter of 2022.
Rubric Share Repurchase
On July 1, 2024, we agreed to the Rubric Share Repurchase for an aggregate purchase price of $280 million. The Rubric Share Repurchase was part of the Company’s share repurchase program.
Pattern Energy Joint Ventures
Subsidiaries of TES are currently party to three renewables joint ventures with Pattern Energy for the development of two solar projects in Pennsylvania totaling 280 MW and a 600-MW wind project in Montana. Affiliates of Riverstone indirectly own a substantial minority interest in Pattern Energy. The joint venture project companies are jointly controlled and indirectly owned either 49% or 50% by TES, respectively, and 51% or 50% by Pattern Energy, respectively. During the three months ended March 31, 2024, and the years ended December 31, 2023, 2022 and 2021, amounts invested by TES to these joint ventures were $1 million, $2 million, $5 million and $3 million, respectively.
Cumulus Investments
Cumulus Digital Holdings; Buyouts
TES owns certain indirect investments in Cumulus Digital Holdings, our non-wholly owned subsidiary in which Riverstone also owned a minority interest until September 2023. The carrying value of our investments in Cumulus Digital Holdings as of December 31, 2023 and 2022 was $152 million and $114 million, respectively. TES, directly and indirectly, and Riverstone initially became owners of common equity units of Cumulus Digital Holdings (the “Cumulus Digital Units”) in September 2022 in connection with the transactions contemplated by the Cumulus Term Sheet, with TES and Talen Growth receiving approximately 74% of the Cumulus Digital Units and affiliates of Riverstone receiving approximately 21%. Additionally, pursuant to the Cumulus Term Sheet, the then-Chairman of TEC, and the then-Chief Executive Officer of TES and TEC, each purchased Cumulus Digital Units from Riverstone in exchange for $1 million in cash. The remainder of the Cumulus Digital Units were held by Orion.
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From September 2022 through June 30, 2023, TES’s direct and indirect interest in Cumulus Digital Holdings increased to 81% as a result of incremental investments by TES, and Riverstone’s interest decreased to 14%.
In September 2023, Riverstone sold all of its Cumulus Digital Units to TES and Orion in exchange for $20 million in cash (the “Riverstone Buyout”). As a result of the Riverstone Buyout, TES’s direct and indirect interest increased to approximately 95%. Additionally, in September 2023 and following the Riverstone Buyout, Talen Growth was merged with and into TES, and, accordingly, at December 31, 2023, TES owned 95% of Cumulus Digital Holdings.
In March 2024, Orion sold all of its Cumulus Digital Units to TES in exchange for $36 million in cash. As a result, TES’s interest further increased to approximately 99.5%. Following TES’s purchase of the Orion equity, Cumulus Digital Holdings distributed approximately $109 million of the initial net proceeds from the Cumulus Data Campus Sale to its members, including approximately $108 million to TES. For additional information on the Cumulus Data Campus Sale, please see “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale.” Later in March 2024, TES acquired all of the Cumulus Digital Units held by the two former members of management in exchange for $3.4 million in cash. Following that transaction, TES now owns 100% of the equity of Cumulus Digital Holdings.
See the Annual Financial Statements and related notes thereto incorporated by reference into this prospectus for more information on Cumulus Digital Holdings.
Cumulus Coin Holdings
In the first and second quarters of 2022, an affiliate of Riverstone invested approximately $46.7 million in Cumulus Coin Holdings, a subsidiary of Cumulus Digital Holdings, in exchange for preferred equity units. During 2021 and 2022, TES, directly and indirectly through Talen Growth, invested $59 million in Cumulus Coin Holdings in exchange for preferred equity units. Pursuant to the Cumulus Term Sheet, these units were converted into common equity units of Cumulus Digital Holdings in September 2022.
Nautilus Joint Venture
Cumulus Coin holds a 75% equity interest in Nautilus, with TeraWulf as our joint venture partner owning the other 25%. Under the limited liability company agreement for Nautilus, Cumulus Coin is entitled to designate four of the five members of Nautilus’s board of managers as well as Nautilus’s chief executive officer, president and chief financial officer. TeraWulf is entitled to designate (i) one board member so long as its ownership percentage remains at or above 15%, and (ii) Nautilus’s chief operating officer so long as its ownership percentage remains at or above 25%. The board of managers has overall responsibility and authority for the management and operation of Nautilus, with the officers of Nautilus exercising day-to-day control and supervision of its operations. The limited liability agreement governing Nautilus does not have a specified term. Termination requires consent of Cumulus Coin but does not require consent of TeraWulf for so long as TeraWulf holds less than 33% of the interests of Nautilus.
Nautilus has no employees. TES, the indirect parent of Cumulus Coin, provides corporate and operational services to Nautilus. The Nautilus facility is located on land previously leased by Nautilus from Cumulus Data, but which was subsequently sold to AWS in the Cumulus Data Campus Sale. Under the terms of the lease, which was assigned to an unrelated party in the course of the Cumulus Data Campus Sale, among other things, Cumulus Data submetered up to 150 MW of electric power to Nautilus in exchange for supplemental rent payments. At the time of assignment, the lease had an initial term that expires on July 1, 2027, renewable at Nautilus’s option. The power was supplied to Cumulus Data by Talen Generation pursuant to the Coin PPA described under “—Energy Supply Agreements” below.
Nautilus is engaged in Bitcoin mining through a third-party, U.S.-based mining pool operator, Foundry USA. Nautilus owns its miners that are installed at its mining facility and does not host miners owned or operated by any other parties. Nautilus provides computing power from its miners to the mining pool operator, and in exchange is paid compensation in the form of Bitcoin on a daily basis. An immaterial fee is charged by the mining pool operator to Nautilus that is deducted from the Bitcoin earned by Nautilus. Nautilus recognizes revenue daily that is measured
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at fair value using the quoted price for Bitcoin in Nautilus’s principal market at the beginning of each day. See Note 2 in Notes to the Annual Financial Statements for more information on Nautilus revenue recognition. Bitcoin received by Nautilus is required to be exchanged for cash, as necessary, to fund ongoing operations, including a reserve determined by the Nautilus board. Revenues and power costs are allocated pro rata to Cumulus Coin based on the computing power (“hash rate”) and power consumption of miners contributed to Nautilus from Cumulus Coin. Cumulus Coin pays miner maintenance costs based on the number of miners contributed by Cumulus Coin, while other operational costs are paid based on Cumulus Coin’s ownership percentage. As of March 31, 2024, there were approximately 48,000 miners at the facility, with an average hash rate of approximately five exahash per second, that were all newly installed in 2023 and have an average service life of thirteen months. Since the start of operations in February 2023 through March 31, 2024, Nautilus mined a total of approximately 4,400 Bitcoin. Nautilus miners are insured up to the applicable limits under the Nautilus miner property policies.
Nautilus is party to broker and custodial agreements with Coinbase, Inc. and certain of its affiliates (collectively “Coinbase”) which provides Nautilus access to liquidate its mined Bitcoin to USD and permits Nautilus to store with Coinbase, on a short-term basis, any Bitcoin prior to liquidation or distribution. Nautilus generally liquidates Bitcoin to USD within one business day to meet its operating requirements and immediately transfers any USD proceeds to its FDIC insured financial institution. Excess Bitcoin available above operating requirements and any applicable reserve is required to be distributed to Cumulus Coin in the form of cash or Bitcoin, at its option, at least once every two weeks. Excess Bitcoin attributable to Cumulus Coin is converted to cash at Nautilus prior to the distribution to Cumulus Coin. Neither Cumulus Coin nor any other Talen affiliates hold any material amount of Bitcoin. Due to Nautilus’s requirement to liquidate Bitcoin to support its operations and its requirement to distribute excess Bitcoin or proceeds from excess Bitcoin sales to the joint venture owners, the Company does not expect to incur any material impairment losses or gains or losses on Bitcoin sales. Additionally, as Nautilus only has a short-term exposure to Bitcoin and Coinbase, it utilizes a “hot” wallet storage product and does not carry insurance on any of its Coinbase accounts. See Note 2 in Notes to the Annual Financial Statements for more information on re-measurement valuation of Bitcoin.
Energy Supply Agreements
Prior to the Cumulus Data Campus Sale, Cumulus Data was party to the following two separate agreements with Talen Generation for energy supply ultimately sourced from Susquehanna: (i) an agreement for up to 300 MW which supported submetered power to Nautilus under a ground lease agreement (the “Coin PPA”); and (ii) a separate option agreement for up to 650 MW which was intended to support Cumulus Data’s anticipated obligations to provide submetered power under lease agreements with data center tenants (the “Data PPA”). In connection with the Cumulus Data Campus Sale, the Coin PPA was assigned to an affiliate of AWS and the Data PPA was terminated. Prior to the Cumulus Data Campus Sale, Cumulus Data had elected to receive 150 MW under the Coin PPA and had not yet elected to receive any power under the Data PPA. Talen Generation’s obligation to supply power to Cumulus Data under each of the agreements was backstopped by wholesale energy supply agreements with Susquehanna on substantially the same terms as the Coin PPA and the Data PPA, respectively. The wholesale agreement supporting the Coin PPA was assigned to an affiliate of AWS in connection with the Cumulus Data Campus Sale, and the commitment for wholesale power to support the Data PPA was terminated. For additional information on the Cumulus Data Campus Sale, please see “Prospectus Summary—Recent Developments—Cumulus Data Campus Sale.”
Delivery of power under the Coin PPA, together with the five-year initial term of the agreement, commenced in February 2023.
Pursuant to the Coin PPA, Talen Generation sold the first 100 MW of power to Cumulus Data at a price of $28.81 per MWh of delivered energy, and the next 50 MW at a price of $44.05 per MWh of delivered energy.
Under the terms of the Data PPA, Cumulus Data had the option to purchase up to 650 MW of power from Talen Generation at a market-based fixed rate that was to have been determined at the time of election. Cumulus Data had until September 2026 to exercise the option, but the option had not been exercised prior to termination of the Data PPA, and no power was delivered.
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No energy was sold or payments made under the Data PPA during the years ended December 31, 2023, 2022 and 2021, and no energy was sold or payments made under the Coin PPA during the years ended December 31, 2022 and 2021. Talen Generation charged $7 million and $35 million to Cumulus Data under the Coin PPA for the three months ended March 31, 2024 and the year ended December 31, 2023, respectively, with corresponding payments over the same period from Talen Generation to Susquehanna for wholesale power supply.
Under the terms of the Plan of Reorganization and the TEC Global Settlement, affiliates of Riverstone received an additional 243,413 shares of common stock at Emergence, representing 25.00% of the estimated net present value of certain potential incremental energy revenues associated with the Coin PPA.
Additionally, affiliates of Riverstone also had the right under the Plan of Reorganization and the TEC Global Settlement to receive additional common stock (or, at TEC’s option, a cash payment) equal to 25.00% of the estimated net present value of certain potential incremental energy revenues under the Data PPA. This agreement was terminated contemporaneously with the closing of the Riverstone Buyout.
Corporate and Operational Services Agreement
Cumulus Digital and its subsidiaries have no employees. As a result, Cumulus Digital has contracted with TES to provide corporate, administrative and operational services under a Corporate and Operational Services Agreement (the “Cumulus Digital COSA”). TES’s services under the Cumulus Digital COSA include support of Cumulus Digital’s obligation to provide Nautilus with corporate and administrative services under a separate agreement.
In exchange for providing these services, TES is entitled to an annual management fee of $750,000, plus overhead charges approximating the cost of service at rates specified in the agreement, as well as the reimbursement of certain costs incurred in support of Cumulus Digital and its subsidiaries. The agreement terminates in September 2027, subject to earlier termination by Cumulus Digital upon 60 days’ prior notice or by TES upon 180 days’ prior notice. Prior to the Cumulus Data Campus Sale and associated repayment of the Cumulus Digital TLF, cash payment of fees and expenses under the agreement were required to be deferred until the earlier of: (i) two years from the commercial operation date of the Nautilus facility; and (ii) the date Cumulus Data and Cumulus Coin meet a minimum interest coverage threshold. TES had the option to receive payment for deferred fees and expenses in cash payments ratably over the next succeeding 24 months or in additional common units of Cumulus Digital Holdings, subject to certain caps. Fees and expenses payable to TES under the agreement for the three months ended March 31, 2024, and the years ended December 31, 2023 and 2022 were $3.2 million, $18.5 million and $14.6 million, respectively, of which $26.3 million was converted to additional common units in Cumulus Digital Holdings in June 2023.
Following the repayment of the Cumulus Digital TLF in March 2024, deferral of fees and expenses is no longer required and the remaining deferred fees and expenses were paid to TES.
Nautilus Facility Operations Agreement
In December 2022, Nautilus and TES executed a Facilities Operations Agreement (the “Nautilus FOA”) whereby TES agreed to provide, or arrange for Nautilus, certain infrastructure, construction, operations and maintenance and administrative services necessary to build out and operate the Nautilus facility and support Nautilus’s ongoing business at the Nautilus facility. The services were previously provided to Nautilus under an agreement with an affiliate of TeraWulf, our unaffiliated joint venture partner in Nautilus, which was terminated upon execution of the Nautilus FOA with TES. TES is entitled to reimbursement of its costs (including direct personnel costs) incurred in performing the services on a monthly basis but is not otherwise entitled to a management fee. The Nautilus FOA expires in December 2025. Amounts payable by Nautilus to TES under the Nautilus FOA were $700 thousand, $5 million, and $45 thousand for the three months ended March 31, 2024, and the years ended December 31, 2023 and 2022, respectively.
Letters of Credit Supporting Cumulus Digital TLF and Reimbursement Agreement
As of December 31, 2023, TES provided $50 million in LCs to support certain of Cumulus Digital’s obligations under the Cumulus Digital TLF. Cumulus Digital agreed to reimburse TES for fees associated with the LCs in the
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form of cash payments or additional common units of Cumulus Digital Holdings, subject to certain caps. Prior to the Cumulus Data Campus Sale and associated repayment of the Cumulus Digital TLF, payment of cash fees was deferred until the earlier of: (i) two years from the commercial operation date of the Nautilus facility; and (ii) the date Cumulus Data and Cumulus Coin meet a minimum interest coverage threshold. Fees and expenses payable to TES under the agreement for the three months ended March 31, 2024, and the years ended December 31, 2023 and 2022 were $0.6 million, $3.3 million and $2.6 million, respectively, of which $3.7 million was converted to additional common units in Cumulus Digital Holdings in June 2023.
In connection with the Cumulus Data Campus Sale, on March 1, 2024, the Cumulus Digital TLF was repaid in full and terminated, and the LCs provided by TES to support Cumulus Digital’s obligations under the Cumulus Digital TLF were terminated.
Following repayment of the Cumulus Digital TLF, deferral of fees and expenses is no longer required and the remaining deferred fees and expenses were paid to TES.
Guaranty of Cumulus Digital TLF
Prior to the consummation of the Cumulus Data Campus Sale, TEC had provided a guarantee to the lenders under the Cumulus Digital TLF for certain shortfalls in principal and interest payments by Cumulus Digital (up to a maximum of 23% of the principal amount of outstanding loans under the Cumulus Digital TLF). In connection with the Cumulus Data Campus Sale, the Cumulus Digital TLF was repaid in full and the guarantees TEC provided to the lenders thereof were terminated.
Tax Indemnity Agreement
In September 2022, upon the Bankruptcy Court’s approval of the transactions contemplated by the Cumulus Term Sheet, Riverstone agreed to indemnify the Company (or, at our option, TES) for:
•certain federal and state income taxes that may be owed as a result of certain of the transactions contemplated by the Cumulus Term Sheet; and
•the tax-effected value of federal income tax attributes of TES in excess of $33 million, if any, utilized to reduce our income tax obligations which, absent such tax attributes, would have otherwise been payable in connection with such transactions.
The TIA was terminated contemporaneously with the closing of the Riverstone Buyout.
Registration Rights Agreement and Stockholders Agreement
In connection with Emergence, we entered into (i) a registration rights agreement (the “Registration Rights Agreement”) with certain designated holders of our common stock and warrants to purchase our common stock and the other holders from time to time party thereto (each, a “Reg Rights Holder”) and (ii) a stockholders agreement (the “Stockholders Agreement”) with all of the holders of our common stock as of Emergence, which also applies to their respective transferees (the “Holders”). Under the Registration Rights Agreement, the Reg Rights Holders were granted customary registration rights that may be exercised after the consummation of an initial public offering, including customary shelf registration rights and piggyback rights.
Pursuant to the Stockholders Agreement, the Holders have certain limited information rights, drag-along rights and tag-along rights, and certain Holders holding 5% or more of common stock have the right to designate a representative to an offering committee (the “Offering Committee”) and so long as the aggregate Company ownership represented on the Offering Committee is at least 20%. Although the Offering Committee has not been established, it would, if established, have the right to request that the Company pursue and use its reasonable best efforts to consummate an underwritten initial public offering. In connection with such underwritten initial public offering, the Offering Committee has certain consent rights, including over the selection of a lead underwriter, structure of the offering, terms and conditions of material transaction documents, selection of a stock exchange, valuation matters, timing and pricing terms. Additionally, any holder that beneficially owns at least 3% of the Company’s common stock is entitled to participate in any secondary component of an underwritten initial public
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offering. The Stockholders Agreement terminates automatically upon the effectiveness of a registration statement in connection with an underwritten public offering of the Company’s common stock, so the Stockholders Agreement will remain in effect following the effectiveness of this registration statement. The Stockholders Agreement also terminates upon the written consent of the Company and the Holders that beneficially own at least two-thirds of the Company’s outstanding common stock; provided that the Stockholders Agreement may not be terminated with respect to any Holder without such Holder’s consent if such termination would adversely affect such Holder.
Riverstone Warrant Cancellation
Pursuant to the Plan of Reorganization and the TEC Global Settlement, at Emergence, affiliates of Riverstone received warrants to acquire an additional 3,106,781 shares of common stock. In August 2023, TEC, TES and the Riverstone affiliates agreed that (i) the warrants would be surrendered and the Riverstone affiliates would waive their right to receive additional common stock in connection with the Data PPA and (ii) the TIA would be terminated in exchange for a $40 million cash payment by TES. The transactions were consummated in September 2023 contemporaneously with the closing of the Riverstone Buyout.
Review, Approval or Ratification of Transactions with Related Persons
Our Board of Directors has adopted a related party transactions policy pursuant to which we will review any future transaction, arrangement or relationship in which the Company, is or will be a participant, in which the aggregate amount involved will or may be expected to exceed $120,000 in any fiscal year and any of the following has or will have a direct or indirect material interest:
•any director, director nominee, executive officer or executive officer appointee;
•any shareholder that beneficially owns more than 5% of any class of our voting securities;
•any immediate family member of any such person described in clauses (i) and (ii); or
•any firm, corporation or other entity in which any of such persons described in clauses (i) through (iii), is employed or is a general partner or principal or in a similar position or in which such person has a 10% or greater beneficial ownership interest (such a transaction, a “Related Party Transaction”).
Our General Counsel is primarily responsible for the development and implementation of processes and controls to obtain information from directors, director nominees, executive officers and executive officer appointees with respect to potential Related Party Transactions, including information provided to management in the annual director and officer questionnaires. Upon learning of a potential Related Party Transaction, our General Counsel refers the matter for consideration and final determination by the audit committee, who consider the fairness of the transaction to the Company, as well as other factors bearing upon its appropriateness. In all such matters, any director having a conflicting interest abstains from participating in any discussion or voting on the matters.
All of the transactions described in this section were entered into prior to the adoption of this policy.
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PRINCIPAL AND SELLING STOCKHOLDERS
The following table sets forth certain information with respect to the beneficial ownership of our capital stock as of July 1, 2024 for:
•each of our named executive officers;
•each of our directors;
•all of our executive officers and directors as a group;
•each person or group of affiliated persons known by us to beneficially own 5% or more of any class of our voting securities; and
•the number of shares of common stock held by and being registered for resale by means of this prospectus for the Selling Stockholders.
The Selling Stockholders include (i) our affiliates and certain other stockholders with “restricted securities” (as defined in Rule 144 under the Securities Act) and their pledgees, donees, transferees, assignees or other successors-in-interest who, because of their status as affiliates pursuant to Rule 144 or because they acquired their shares of common stock from an affiliate or from us within the prior 12 months, would be unable to sell their securities pursuant to Rule 144 until we have been subject to the reporting requirements of Section 13 or Section 15(d) of the Exchange Act for a period of at least 90 days and (ii) our non-executive officer service providers and their pledgees, donees, transferees, assignees or other successors-in-interest who acquired shares from us within the prior 12 months under Rule 701 and hold “restricted securities” (as defined in Rule 144 under the Securities Act). The Selling Stockholders and their pledgees, donees, transferees, assignees or other successors-in-interest may, or may not, elect to sell their shares of common stock covered by this prospectus, as and to the extent they may determine. Such sales, if any, will be made through brokerage transactions on Nasdaq at prevailing market prices. As such, we will have no input if and when any Selling Stockholder may, or may not, elect to sell their shares of common stock or the prices at which any such sales may occur. See the section titled “Plan of Distribution.”
Information concerning the Selling Stockholders may change from time to time and any changed information will be set forth in supplements to this prospectus, if and when necessary. Because the Selling Stockholders may sell all, some or none of the shares of common stock covered by this prospectus, we cannot determine the number of such shares of common stock that will be sold by the Selling Stockholders, or the amount or percentage of shares of common stock that will be held by the Selling Stockholders upon consummation of any particular sale. In addition, the Selling Stockholders listed in the table below may have sold, transferred, or otherwise disposed of, or may sell, transfer, or otherwise dispose of, at any time and from time to time, shares of common stock in transactions exempt from the registration requirements of the Securities Act, after the date on which they provided the information set forth in the table below. The Selling Stockholders do not have, nor have they within the past three years had, any position, office or other material relationship with us, other than as disclosed in this prospectus. See the sections titled “Management” and “Certain Relationships and Related Party Transactions” for further information regarding the Selling Stockholders.
After the listing of our common stock on Nasdaq, certain of the Selling Stockholders are entitled to registration rights with respect to their shares of our capital stock, as described in the section titled “Description of Capital Stock—Registration Rights.”
We are not party to any arrangement with any Selling Stockholder or any broker-dealer with respect to sales of the shares of common stock by the Selling Stockholders.
We have determined beneficial ownership in accordance with the rules and regulations of the SEC, and the information is not necessarily indicative of beneficial ownership for any other purpose. Except as indicated by the footnotes below, we believe, based on information furnished to us, that the persons and entities named in the table below have sole voting and sole investment power with respect to all shares that they beneficially own, subject to applicable community property laws.
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Applicable percentage ownership is based on 50,841,161 shares of common stock outstanding as of July 1, 2024, taking into account the Rubric Share Repurchase. In computing the number of shares beneficially owned by a person and the percentage ownership of such person, we deemed to be outstanding all shares subject to options held by the person that are currently exercisable, or exercisable within 60 days of July 1, 2024 or issuable pursuant to RSUs that vest within 60 days of July 1, 2024. However, except as described above, we did not deem such shares outstanding for the purpose of computing the percentage ownership of any other person. The information set forth in the table below regarding the beneficial ownership after resale of the shares of common stock is based upon the assumption that the Selling Stockholders will sell all of the shares of common stock beneficially owned by them that are covered by this prospectus.
Unless otherwise indicated, the address of each beneficial owner listed below is c/o 2929 Allen Pkwy, Suite 2200, Houston, Texas 77019.
| Name of Beneficial Owner | Shares Beneficially Owned | Percent of Total Voting Power(1) | Shares of Common Stock Being Registered | Shares Beneficially Owned After Offering(2) | ||||||||||||||||||||||||||||||||||
| Common Stock | Common Stock | |||||||||||||||||||||||||||||||||||||
| Shares | % | Shares | % | |||||||||||||||||||||||||||||||||||
| 5% Stockholders | ||||||||||||||||||||||||||||||||||||||
Entities Affiliated with Rubric Capital Management LP(3) | 11,368,614 | 22.4 | % | 22.4 | % | 11,368,614 | — | — | ||||||||||||||||||||||||||||||
Monarch Alternative Capital LP(4) | 4,708,594 | 9.3 | % | 9.3 | % | 4,708,594 | — | — | ||||||||||||||||||||||||||||||
Entities Affiliated with Capital Research and Management Company(5) | 3,306,750 | 6.5 | % | 6.5 | % | 3,306,750 | — | — | ||||||||||||||||||||||||||||||
| Named Executive Officers and Directors | ||||||||||||||||||||||||||||||||||||||
Mark “Mac” McFarland(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Stephen Schaefer(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Gizman Abbas(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Anthony Horton(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Karen Hyde(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Joseph Nigro(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Christine Benson Schwartzstein(6) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Alejandro Hernandez(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
John Chesser(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Terry L. Nutt(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
John Wander(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Andrew Wright(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
Brad Berryman(7) | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| All directors and executive officers as a group (11 persons) | — | * | * | — | — | * | ||||||||||||||||||||||||||||||||
| Other Selling Stockholders | ||||||||||||||||||||||||||||||||||||||
Sachem Head Capital Management LP(8) | 2,440,000 | 4.8 | % | 4.8 | % | 2,440,000 | — | — | ||||||||||||||||||||||||||||||
Mirabella Financial Services LLP(9) | 1,630,851 | 3.2 | % | 3.1 | % | 1,630,851 | ||||||||||||||||||||||||||||||||
Oaktree Capital Management, L.P.(10) | 1,528,075 | 3.0 | % | 3.0 | % | 1,528,075 | — | — | ||||||||||||||||||||||||||||||
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Sculptor Capital Management, Inc.(11) | 1,254,008 | 2.5 | % | 2.5 | % | 1,254,008 | — | — | ||||||||||||||||||||||||||||||
Parsifal Capital Management, LP(12) | 1,186,638 | 2.3 | % | 2.3 | % | 1,186,638 | — | — | ||||||||||||||||||||||||||||||
Glendon Capital Management, L.P.(13) | 1,070,711 | 2.1 | % | 2.1 | % | 1,070,711 | — | — | ||||||||||||||||||||||||||||||
FIG LLC(14) | 1,049,012 | 2.1 | % | 2.1 | % | 1,049,012 | — | — | ||||||||||||||||||||||||||||||
Entities Affiliated with Riverstone Holdings LLC(15) | 833,701 | 1.6 | % | 1.6 | % | 833,701 | — | — | ||||||||||||||||||||||||||||||
Atalan Capital Partners, LP(16) | 730,120 | 1.4 | % | 1.4 | % | 730,120 | — | — | ||||||||||||||||||||||||||||||
Carronade Capital Management, LP(17) | 619,115 | 1.2 | % | 1.2 | % | 619,115 | — | — | ||||||||||||||||||||||||||||||
Aventail Capital Group, LP(18) | 534,142 | 1.1 | % | 1.0 | % | 534,142 | ||||||||||||||||||||||||||||||||
Brown Advisory LLC(19) | 519,376 | 1.0 | % | 1.0 | % | 519,376 | ||||||||||||||||||||||||||||||||
Solar Projects LLC(20) | 500,607 | * | * | 500,607 | — | — | ||||||||||||||||||||||||||||||||
P. Schoenfeld Asset Management LP(21) | 459,959 | * | * | 459,959 | — | — | ||||||||||||||||||||||||||||||||
Philosophy Capital Management, LLC(22) | 406,420 | * | * | 406,420 | — | — | ||||||||||||||||||||||||||||||||
Hartree Partners GP, LLC(23) | 400,000 | * | * | 400,000 | — | — | ||||||||||||||||||||||||||||||||
Two Seas Capital LP(24) | 397,183 | * | * | 397,183 | — | — | ||||||||||||||||||||||||||||||||
Nuveen Asset Management LLC(25) | 356,571 | * | * | 356,571 | — | — | ||||||||||||||||||||||||||||||||
Aristeia Capital, L.L.C.(26) | 295,000 | * | * | 295,000 | — | — | ||||||||||||||||||||||||||||||||
Entities Affiliated with DG Capital Management, LLC(27) | 276,244 | * | * | 276,244 | — | — | ||||||||||||||||||||||||||||||||
J. Rothschild Capital Management Limited(28) | 272,837 | * | * | 272,837 | — | — | ||||||||||||||||||||||||||||||||
PointState Capital LP(29) | 221,422 | * | * | 221,422 | — | — | ||||||||||||||||||||||||||||||||
Lee Jamieson(30) | 126,422 | * | * | 126,422 | — | — | ||||||||||||||||||||||||||||||||
Entities Affiliated with Purpose Investments Inc.(31) | 114,399 | * | * | 114,399 | — | — | ||||||||||||||||||||||||||||||||
Franklin Advisers, Inc.(32) | 93,154 | * | * | 93,154 | — | — | ||||||||||||||||||||||||||||||||
Yost Capital Management, LP(33) | 43,843 | * | * | 43,843 | — | — | ||||||||||||||||||||||||||||||||
Livello Capital Management LP(34) | 43,250 | * | * | 43,250 | — | — | ||||||||||||||||||||||||||||||||
FourWorld Capital Management LLC(35) | 9,598 | * | * | 9,598 | — | — | ||||||||||||||||||||||||||||||||
CSS, LLC(36) | 7,892 | * | * | 7,892 | ||||||||||||||||||||||||||||||||||
ACR Alpine Capital Research, LLC(37) | 7,149 | * | * | 7,149 | — | — | ||||||||||||||||||||||||||||||||
Comeg Trust LLC(38) | 7,000 | * | * | 7,000 | — | — | ||||||||||||||||||||||||||||||||
Corbin Capital Partners, L.P.(39) | 4,352 | * | * | 4,352 | — | — | ||||||||||||||||||||||||||||||||
DPA Trust No. 1 LLC(40) | 2,674 | * | * | 2,674 | — | — | ||||||||||||||||||||||||||||||||
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*Represents beneficial ownership of less than 1%.
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(1)Percentage of voting power represents voting power with respect to all shares of our common stock held beneficially as a single class. The holders of our common stock will be entitled to one vote per share.
(2)Assumes the Selling Stockholder sells all of the shares of common stock offered pursuant to this prospectus.
(3)Consists of (i) 7,628,709 shares held by Rubric Capital Master Fund LP, (ii) 2,617,400 shares held by Rubric BSR Fund LLC, (iii) 802,383 shares of common stock held by Blackstone CSP-MST FMAP Fund and (iv) 320,121 shares held by BEMAP Master Fund Ltd. (collectively, the “Rubric Funds”). The Rubric Funds are managed or sub-managed by Rubric Capital Management LP, as applicable. The sole general partner of Rubric Capital Management LP is Rubric Capital Management GP LLC. The managing member of Rubric Capital Management GP LLC is David Rosen. Mr. Rosen may be deemed to have shared voting and investment power of the securities managed or sub-managed, as applicable, by Rubric Capital Management LP. Mr. Rosen disclaims beneficial ownership of such securities, except to the extent of his pecuniary interest therein. The address of the Rubric Funds is 155 E. 44th Street, New York, NY 10017.
(4)Consists of (i) 1,845,224 shares held by Monarch Capital Master Partners V LP, (ii) 1,701,498 shares held by Monarch Capital Master Partners VI LP, (iii) 54,828 shares held by Monarch Customized Opportunistic Fund – Series 1 LP, (iv) 510,303 shares held by Monarch Debt Recovery Master Fund Ltd and (v) 497,541 shares held by Monarch V Select Opportunities Master Fund LP, and (vi) 99,200 shares held by Monarch Capital Master Partners V-A LP (collectively, the “Monarch Funds”). Monarch Alternative Capital LP is the beneficial owner of the Company’s common stock and has been delegated the power to vote and dispose of the shares on behalf of the Monarch Funds. MDRA GP LP, Monarch GP LLC shares beneficial ownership with Monarch Alternative Capital LP by virtue of the fact that MDRA GP LP is the general partner of Monarch Alternative Capital LP and Monarch GP LLC is the general partner of MDRA GP LP. The address of the Monarch Funds is c/o Monarch Alternative Capital LP, 535 Madison Avenue, 22nd Floor, New York, NY 10022. Investing and voting decisions made by such funds rest with the portfolio managers of Monarch - Michael Weinstock, Andrew Herenstein, Christopher Santana and Adam Sklar - each of whose address is c/o Monarch Alternative Capital LP. 535 Madison Avenue, New York, NY 10022. Such portfolio managers make decisions by consensus, and as such, each such individual disclaims beneficial ownership of these shares.
(5)Consists of (i) 1,065,383 shares held by American High-Income Trust; (ii) 1,363,759 shares held by SMALLCAP World Fund, Inc.; (iii) 176,882 shares held by American Funds Multi-Sector Income Fund; (iv) 175,287 shares held by The Income Fund of America; (v) 359,752 shares held by The New Economy Fund; (vi) 52,138 shares held by American Funds Insurance Series - American High-Income Trust; (vii) 92,500 shares held by American Funds Insurance Series - Global Small Capitalization Fund; (viii) 9,955 shares held by Capital Group New Economy Fund (LUX); (ix) 4,633 shares held by Capital Group U.S. High-Yield Trust (US); (x) 6,226 shares held by Capital Group New Economy Trust (US); and (xi) 235 shares held by Capital Group Sustainable Global Opportunities Fund (LUX). Capital Research and Management Company (“CRMC”) is the investment adviser for American High-Income Trust, SMALLCAP World Fund, Inc., American Funds Multi-Sector Income Fund, The Income Fund of America, The New Economy Fund, American Funds Insurance Series - American High-Income Trust, American Funds Insurance Series - Global Small Capitalization Fund, Capital Group New Economy Fund (LUX), Capital Group U.S. High-Yield Trust (US), Capital Group New Economy Trust (US) and Capital Group Sustainable Global Opportunities Fund (LUX) (collectively, the “CRMC Funds”). CRMC, Capital Research Global Investors (“CRGI”), Capital World Investors (“CWI”) and Capital International Investors (“CII”) may be deemed to be the beneficial owner of the shares held by each CRMC Fund; however, each of CRMC, CRGI, CWI and CII expressly disclaims that it is, in fact, the beneficial owner of such securities. Tom Chow, David A. Daigle, Tara L. Torrens and Shannon Ward, as portfolio managers, have voting or investment control over the shares held by American High-Income Trust, American Funds Insurance Series - American High-Income Trust and Capital Group U.S. High-Yield Trust (US). Julian N. Abdey, Peter Eliot, Brady L. Enright, Bradford F. Freer, Peter Gusev, Leo Hee, M. Taylor Hinshaw, Roz Hongsaranagon, Akira Horiguchi, Shlok Melwani, Dimitrije M. Mitrinovic, Aidan O’Connell, Samir Parekh, Piyada Phanaphat, Andraz Razen, Renaud H. Samyn, Arun Swaminathan, Thatcher Thompson and Gregory W. Wendt, as portfolio managers, have voting or investment control over the shares held by SMALLCAP World Fund, Inc. Xavier Goss, Damien J. McCann, Kirstie Spence, Scott Sykes and Shannon Ward, as portfolio managers, have voting or investment control over the shares held by American Funds Multi-Sector Income Fund. Hilda L. Applbaum, Pramod Atluri, David A. Daigle, Dimitrije M. Mitrinovic, John R. Queen, Caroline Randall, Anirudh Samsi, Andrew B. Suzman, Justin Toner and Shannon Ward, as portfolio managers, have voting or investment control over the shares held by The Income Fund of America. Paul Benjamin, Mathews Cherian, Tomoko Fortune, Caroline Jones, Harold H. La, Reed Lowenstein, Lara Pellini and Richmond Wolf, as portfolio managers, have voting or investment control over the shares held by The New Economy Fund, Capital Group New Economy Fund (LUX) and Capital Group New Economy Trust (US). Bradford F. Freer, M. Taylor Hinshaw, Shlok Melwani, Aidan O'Connell, Renaud H. Samyn and Gregory W. Wendt, as portfolio managers, have voting or investment control over the shares held by American Funds Insurance Series - Global Small Capitalization Fund. Julian N. Abdey, Tomoko Fortune, Emme Kozloff and Carlos A. Schonfeld, as portfolio managers, have voting or investment control over the shares held by Capital Group Sustainable Global Opportunities Fund (LUX). The address of American High-Income Trust, The New Economy Fund, American Funds Insurance Series - American High-Income Trust and American Funds Insurance Series - Global Small Capitalization Fund is 333 South Hope Street, Los Angeles, California 90071, USA. The address of SMALLCAP World Fund, Inc., American Funds Multi-Sector Income Fund, The Income Fund of America, Capital Group U.S. High-Yield Trust (US) and Capital Group New Economy Trust (US) is 6455 Irvine Center Drive, Irvine, California 92618, USA. The address of Capital Group New Economy Fund (LUX) and Capital Group Sustainable Global Opportunities Fund (LUX) is 6C Route de Treves, Senningerbeg, L-2633, Luxembourg.
(6)Director of the Company.
(7)Named executive officer of the Company.
(8)Consists of (i) 1,228,023 shares held by Sachem Head LP, (ii) 816,977 shares held by Sachem Head Master LP and (iii) 395,000 shares held by SH Stony Creek Master Ltd. (collectively, the “Sachem Head Funds”). Sachem Head Capital Management LP (“SHCM”), as the investment adviser to the Sachem Head Funds, may be deemed to have the shared power to vote or direct the vote of (and the shared power to dispose or direct the disposition of) the shares of common stock held by the Sachem Head Funds. As the general partner of SHCM, Uncas GP LLC (“Uncas”) may be deemed to have the shared power to vote or direct the vote of (and the shared power to dispose or direct the disposition of) the shares of common stock held by the Sachem Head Funds. As the general partner of Sachem Head LP and Sachem Head Master LP, Sachem Head GP LLC (“Sachem Head GP”) may be deemed to have the shared power to vote or to direct the vote of (and the shared power to dispose or direct the disposition of) the shares of common stock held by Sachem Head LP and Sachem Head Master LP. As the manager of SH Stony Creek Master Ltd., SH Stony Creek GP LLC (“Stony Creek GP”) may be deemed to have the shared power to
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vote or to direct the vote of (and the shared power to dispose or direct the disposition of) the shares of common stock held by SH Stony Creek Master Ltd. By virtue of Scott D. Ferguson’s position as the managing partner of SHCM and the managing member of Uncas, Sachem Head GP, and Stony Creek GP, Scott D. Ferguson may be deemed to have the shared power to vote or direct the vote of (and the shared power to dispose or direct the disposition of) the shares of common stock held by the Sachem Head Funds. The business address of each of the Sachem Head Funds is c/o Sachem Head Capital Management LP, 250 West 55th Street, 34th Floor, New York, NY 10019.
(9)Consists of (i) 1,214,744 shares held by Deltroit Directional Opportunities Master Fund Limited (“Deltroit”) and (ii) 416,107 shares held by BIWA Fund Limited (“BIWA”). Deltroit and BIWA are each managed by Mirabella Financial Services LLP (“Mirabella”), the regulatory host and Accredited Fiduciary Investment Manager. Mirabella has been delegated voting and dispositive power over the shares of common stock identified above as beneficially owned by Deltroit and BIWA. Lord Michael Hintze, a senior portfolio manager at Deltroit Asset Management (UK) LLP (seconded to Mirabella), has the ultimate voting and dispositive power at Mirabella with respect to the shares of common stock beneficially owned by Deltroit and BIWA. Mirabella and Lord Michael Hintze may be deemed to share beneficial ownership of the securities reported herein, but they disclaim any such beneficial ownership of securities not held of record by them, except to the extent they have a pecuniary interest therein. The business address of each of Deltroit and BIWA is PO Box 309, Ugland House, KY1-1104, Georgetown, KY.
(10)Consists of (i) 1,197,485 shares held by Oaktree Value Opportunities Fund Holdings, L.P. (“Oaktree Value Opportunities Fund Holdings”), (ii) 191,628 shares held by Boston Patriot Arlington St LLC (“Boston Patriot”) and (iii) 138,962 shares held by Oaktree Phoenix Investment Fund, L.P. (“Oaktree Phoenix”). These shares of common stock being registered herein are beneficially owned by (i) Oaktree Value Opportunities Fund Holdings, as a result of its direct ownership of 1,197,485 shares of common stock, (ii) Boston Patriot, as a result of its direct ownership of 191,628 shares of common stock, (iii) Oaktree Phoenix, as a result of its direct ownership of 138,962 shares of common stock, (iv) Oaktree Value Opportunities Fund GP, L.P. (“Oaktree Value Opportunities Fund GP LP”), solely in its capacity as the general partner of Oaktree Value Opportunities Fund Holdings, (v) Oaktree Value Opportunities Fund GP Ltd. (“Oaktree Value Opportunities Fund GP”), solely in its capacity as the general partner of Oaktree Value Opportunities Fund Holdings GP LP, (vi) Oaktree Phoenix Investment Fund GP, L.P. (“Oaktree Phoenix GP LP”), solely in its capacity as the general partner of Oaktree Phoenix, (vii) Oaktree Phoenix Investment Fund GP Ltd. (“Oaktree Phoenix GP”), solely in its capacity as the general partner of Oaktree Phoenix GP LP, and (viii) Oaktree Capital Management, L.P., solely in its capacities as (A) the director of Oaktree Value Opportunities Fund GP, (B) the director of Oaktree Phoenix GP, and (C) investment manager of Boston Patriot. The address of each of the foregoing is 333 South Grand Avenue, 28th Floor, Los Angeles, CA 90071. Each of Oaktree Value Opportunities Fund Holdings, Boston Patriot and Oaktree Phoenix may be deemed to be an affiliate of a registered broker-dealer and has represented to the Company that its shares of common stock being offered for resale hereby were purchased in the ordinary course of business and that, at the time of purchase of such shares, it did not have any arrangements or understandings, directly or indirectly, with any person to distribute such shares.
(11)Consists of 1,254,008 shares held by Sculptor Master Fund, Ltd., a Cayman Islands company (“SCMD”). Sculptor Capital LP (“Sculptor”), a Delaware limited partnership, is the investment manager to SCMD. Sculptor Capital Holding Corporation (“SCHC”), a Delaware corporation, serves as the general partner of Sculptor. Sculptor Capital Management, Inc. (“SCU”), a Delaware corporation is the sole shareholder of SCHC. Rithm Capital Corp. (“RITM”), a Delaware corporation that is publicly traded on the New York Stock Exchange (NYSE: RITM), is the sole shareholder of SCU and the ultimate parent company of Sculptor. Accordingly, Sculptor, SCHC, SCU and RITM may be deemed to be beneficial owners of SCMD. The address of each of SCMD, Sculptor, SCHC and SCU is 9 West. 57th Street, 40th Floor, New York, NY 10019.
(12)Consists of (i) 794,418 shares held directly by Parsifal Master Fund Ltd. (“Parsifal Master”), (ii) 162,530 shares held directly by Parsifal Co-Invest I, LP. (“Parsifal Co-Invest”) and (iii) 229,690 shares held directly by an account managed (the “Managed Account”) by Parsifal Capital Management, LP (“Parsifal Capital”). Parsifal Capital serves as the investment manager to each of Parsifal Master and Parsifal Co-Invest. David Zorub (“Mr. Zorub”) serves as the Managing Member of Parsifal Capital Management GP, LLC, the general partner of Parsifal Capital, and may be deemed to hold voting and dispositive power with respect to the shares held by each of Parsifal Master, Parsifal Co-Invest and the Managed Account (collectively, the “Parsifal Entities and Account”). The business address of each of the Parsifal Entities and Account and Mr. Zorub is c/o Parsifal Capital Management, LP, One Fawcett Place, Suite 130, Greenwich, CT 06830.
(13)Consists of (i) 549,636 shares held by Glendon Opportunities Fund II, L.P. and (ii) 521,075 shares held by Glendon Opportunities Fund III, L.P. (collectively, the “Glendon Funds”). Glendon Capital Management L.P. (“GCM”) serves as the investment manager for the Glendon Funds and thus may be deemed to beneficially own the shares of common stock identified above. Mr. Brian Berman is a partner of GCM and has been delegated authority by GCM to direct the voting and disposition of the shares of common stock identified above, and thus is deemed to share voting power for the shares beneficially owned by GCM and the Glendon Funds. The address of each of the Glendon Funds is 2425 Olympic Blvd, Suite 500E, Santa Monica, CA 90404.
(14)Consists of (i) 350,942 shares held by CF TLNE LP and (ii) 698,070 shares held by CF TLNE 2023 LP (together with CF TLNE LP, the “CF TLNE Entities”). Interests in CF TLNE LP are owned by each of CF TLNE Offshore Holdings L.P., DBO TLNE Ltd., a Cayman Islands exempted company, Fortress Credit Opportunities Fund V (A) L.P., a Cayman Islands exempted limited partnership (“Fund A”), Fortress Credit Opportunities Fund V (B) L.P., a Cayman Islands exempted limited partnership (“Fund B”), Fortress Credit Opportunities Fund V (E) LP, a Delaware limited partnership (“Fund E”), Drawbridge Special Opportunities Fund LP, a Delaware limited partnership, FCO MA Centre Street II (ER) LP, a Delaware limited partnership, FCO MA Centre Street II (PF) LP, a Delaware limited partnership, FCO MA Centre Street II (TR) LP, a Delaware limited partnership, FCO MA MI II L.P., a Cayman Islands exempted limited partnership, FCO MA V UB Securities LLC, a Delaware limited liability company, and FCO V LSS SubCo LP, a Delaware limited partnership, as the members (the “CF TLNE Members”). The general partner of CF TLNE LP is CF TLNE GP LLC, a Delaware limited liability company. CF TLNE GP LLC is owned by the CF TLNE Members. CF TLNE Offshore Holdings L.P., is owned by Fortress Credit Opportunities Fund V (C) L.P., a Cayman Islands exempted limited partnership (“Fund C”), Fortress Credit Opportunities Fund V (D) L.P., a Cayman Islands exempted limited partnership (“Fund D”), Fortress Credit Opportunities Fund V (G) L.P., a Cayman Islands exempted limited partnership (“Fund G”, and together with Fund A, Fund B, Fund C, Fund D and Fund E, collectively, the “FCO V Funds”), FTS SIP II L.P., a Jersey limited partnership, FCO MA J5 L.P., a Cayman Islands exempted limited partnership, and Super FCO MA III L.P., a Cayman Islands exempted limited partnership, as the partners. FCO V Fund GP LLC, a Delaware limited liability company is the general partner of each of the FCO V Funds. Fortress Credit Opportunities V-C Advisors LLC, a Delaware limited liability company, is the investment manager of Fortress Credit Opportunities Fund V (C) L.P. and Fortress Credit Opportunities V Advisors LLC, a Delaware limited liability company, is
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the investment manager of each other FCO V Fund. The general partner of each of the FCO V Funds is FCO Fund V GP LLC. Hybrid GP Holdings (Cayman) LLC, a Cayman Islands limited liability company (“Hybrid Cayman”), is the owner of all of the issued and outstanding interests of FCO Fund V GP LLC. Hybrid GP Holdings LLC, a Delaware limited liability company (“Hybrid Holdings”), is the owner of all of the issued and outstanding interests of Hybrid GP Holdings (Cayman) LLC. Fortress Operating Entity I LP, a Delaware limited partnership (“FOE I”), is the managing member of Hybrid Holdings. FIG Corp., a Delaware corporation (“FIG Corp.”), is the general partner of FOE I. Fortress Investment Group LLC, a Delaware limited liability company, is the holder of all of the issued and outstanding shares of FIG Corp. FCO BT GP LLC, a Delaware limited liability company, is the general partner of FTS SIP II L.P. The owner of all of the issued and outstanding interests of FCO BT GP LLC is Hybrid GP Holdings. Fortress Credit Opportunities MA Advisors LLC is the investment manager of FTS SIP II L.P. FCO Fund V GP LLC is the general partner of FCO MA J5 L.P. FCO MA JS Advisors LLC is the investment manager of FCO MA J5 L.P. FCO MA SUP GP III LLC is the general partner of Super FCO MA III L.P. Hybrid Cayman is the owner of all of the issued and outstanding interests of FCO MA SUP GP III LLC. FCO MA Sup Advisors LLC is the investment manager of FCO MA SUP GP III LLC. DBO TLNE Ltd., is owned by Drawbridge Special Opportunities Fund Ltd., a Cayman Islands exempted company. Drawbridge Special Opportunities Intermediate Fund L.P., a Cayman islands exempted limited partnership, is the owner of all of the issued and outstanding interests of Drawbridge Special Opportunities Fund Ltd. Drawbridge Special Opportunities Offshore Fund Ltd., a Cayman Islands exempted company, is the owner of all of the issued and outstanding interests of Drawbridge Special Opportunities Intermediate Fund L.P. Drawbridge Special Opportunities Offshore GP LLC, a Delaware limited liability company is the general partner of Drawbridge Special Opportunities Intermediate Fund L.P. FOE I LP is the owner of all of the issued and outstanding membership interests in Drawbridge Special Opportunities Offshore GP LLC. Drawbridge Special Opportunities Advisors LLC (“DBSO Advisors”), is the investment manager of Drawbridge Special Opportunities Offshore Fund Ltd., Drawbridge Special Opportunities Intermediate Fund L.P., and Drawbridge Special Opportunities Fund Ltd. Drawbridge Special Opportunities Fund GP LLC is the General Partner of Drawbridge Special Opportunities Fund LP. Fortress Principal Investment Holdings IV LLC, a Delaware limited liability company, is the managing member of Drawbridge Special Opportunities Fund GP LLC. FOE I is the owner of all of the issued and outstanding membership interests in Fortress Principal Investment Holdings IV LLC. DBSO Advisors LLC is the investment manager to Drawbridge Special Opportunities Fund LP. FCO MA Centre II GP LLC, a Delaware limited liability company, is the general partner of, and FCO MA Centre II Advisors LLC, a Delaware limited liability company, is the investment manager of, each of FCO MA Centre Street (ER) LP, FCO MA Centre Street II (PF) LP and FCO MA Centre Street II (TR) LP. Hybrid Holdings is the owner of all of the issued and outstanding interests of FCO MA Centre II GP LLC. FCO MA MI II GP LLC, a Delaware limited liability company, is the general partner of FCO MA MI II L.P. Hybrid Holdings is the owner of all of the issued and outstanding interests of FCO MA MI II GP LLC. Fortress Credit Opportunities MA II Advisor LLC is the investment manager of FCO MA MI II L.P. FCO MA V UB Securities LLC, a Delaware limited liability company, is owned by FCO MA V L.P., a Cayman Islands exempted limited partnership. The general partner of FCO MA V L.P. is FCO MA V GP LLC, a Delaware limited liability company. Hybrid Cayman is the owner of all of the issued and outstanding interests of FCO MA V GP LLC. FCO MA V Advisors LLC, a Delaware limited liability company, is the investment manager of FCO MA V L.P. FCO V LSS SubCo GP LLC, a Delaware limited liability company, is the general partner of FCO V LSS SUBCO LP. Hybrid Holdings is the owner of all of the issued and outstanding interests of FCO V LSS SubCo GP LLC. FCO V LSS SubCo Advisors LLC, a Delaware limited liability company, is the investment manager of FCO V LSS SubCo LP. FIG LLC, a Delaware limited liability company, is the holder of all of the issued and outstanding interests of each of the investment managers listed above. The CF TLNE Entities hold and beneficially own all of the shares of common stock, and on the basis of the relationships described herein, each of the other foregoing persons may be deemed to beneficially own the shares of common stock held by the CF TLNE Entities. As the Co-Chief Investment Officers of the CF TLNE Entities (through advisory and general partner entities) each of Peter L. Briger, Jr., Dean Dakolias, Andrew A. McKnight and Joshua Pack participates in the voting and investment decisions with respect to the shares of common stock held by the CF TLNE Entities, but each of them disclaims beneficial ownership thereof. The address of each of the CF TLNE Entities is Corporation Trust Center, 1209 Orange Street, Wilmington, DE 19801. Each of the CF TLNE Entities is an affiliate of a registered broker-dealer and has represented to the Company that its shares of common stock being offered for resale hereby were purchased in the ordinary course of business and that, at the time of purchase of such shares, it did not have any arrangements or understandings, directly or indirectly, with any person to distribute such shares.
(15)Consists of 389,539 shares held of record by Raven Power Holdings LLC, 145,577 shares held of record by Riverstone V Coin Holdings, L.P., 48,804 shares held of record by Sapphire Power Holdings LLC and 249,781 shares held of record by C/R Energy Jade, LLC. Pierre F. Lapeyre, Jr. and David M. Leuschen are the managing directors of Riverstone Management Group, L.L.C., which is the general partner of Riverstone/Gower Mgmt Co Holdings, L.P., which is the sole member of Riverstone Holdings LLC, which is the sole shareholder of Riverstone Energy GP V Corp., which is the sole member of Riverstone Energy GP V, LLC, which is the general partner of Riverstone Energy Partners V, L.P., which is the general partner of Riverstone V Raven Holdings, L.P., which is the managing member of Raven Power Holdings LLC. As a result of these relationships, each of these entities and individuals may be deemed to share beneficial ownership of the securities held of record by Raven Power Holdings LLC. Riverstone Energy Partners V, L.P. is also the general partner of Riverstone V Coin Holdings, L.P. As a result of these relationships, David M. Leuschen, Pierre F. Lapeyre, Jr., Riverstone Management Group, L.L.C., Riverstone/Gower Mgmt Co Holdings, L.P., Riverstone Holdings LLC, Riverstone GP V Corp., Riverstone Energy GP V, LLC and Riverstone Energy Partners V, L.P. may be deemed to share beneficial ownership of the securities held of record by Riverstone V Coin Holdings, L.P. Riverstone Holdings LLC is also the sole member of R/C Renewable Energy GP II, L.L.C., which is the general partner of Riverstone/Carlyle Renewable Energy Partners II, L.P., which is the general partner of R/C Sapphire Power IP, L.P., which is the managing member of Sapphire Power Holdings LLC. As a result of these relationships, each of these entities, Pierre F. Lapeyre, Jr., David M. Leuschen, Riverstone Management Group, L.L.C. and Riverstone/Gower Mgmt Co Holdings, L.P. may be deemed to share beneficial ownership of the securities held of record by Sapphire Power Holdings LLC. Riverstone Holdings LLC is also the sole member of Riverstone Investment Group LLC, which is a member with voting rights to appoint members of the managing committee of C/R Energy GP III, LLC, which is the general partner of Carlyle/Riverstone Energy Partners III, L.P., which is the general partner of Carlyle/Riverstone Global Energy and Power Fund III, L.P., which is the controlling member of C/R Energy Jade LLC. As a result of these relationships, each of these entities, Pierre F. Lapeyre, Jr., David M. Leuschen, Riverstone Management Group, L.L.C. and Riverstone/Gower Mgmt Co Holdings, L.P. may be deemed to share beneficial ownership of the securities held of record by C/R Energy Jade, LLC. The Carlyle Group Inc., which is a publicly traded entity listed on Nasdaq, is the sole shareholder of Carlyle Holdings I GP Inc., which is the sole member of Carlyle Holdings I GP Sub L.L.C., which is the general partner of Carlyle Holdings I L.P., which, with respect to the securities reported
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herein, is the managing member of CG Subsidiary Holdings L.L.C., which is the managing member of TC Group, L.L.C., which is the managing member of Carlyle Investment Management L.L.C., which is also a member with voting rights to appoint members of the managing committee of C/R Energy GP III, LLC. As a result of these relationships, each of these entities may be deemed to share beneficial ownership of the securities held of record by C/R Energy Jade LLC. The address for The Carlyle Group Inc., Carlyle Holdings I GP Inc., Carlyle Holdings I GP Sub L.L.C., Carlyle Holdings I L.P., CG Subsidiary Holdings L.L.C., TC Group, L.L.C., TC Group Sub L.P. and TC Group-Energy LLC is c/o The Carlyle Group, 1001 Pennsylvania Avenue, NW, Suite 220 South, Washington, D.C. 20004. The address for each of the other entities and individuals named in this footnote is c/o Riverstone Holdings LLC, 712 Fifth Avenue, 36th Floor, New York, NY 10019. Each of the Raven Power Holdings LLC, Riverstone V Coin Holdings, L.P., Sapphire Power Holdings LLC and C/R Energy Jade, LLC is an affiliate of a registered broker-dealer and has represented to the Company that its shares of common stock being offered for resale hereby were purchased in the ordinary course of business and that, at the time of purchase of such shares, it did not have any arrangements or understandings, directly or indirectly, with any person to distribute such shares.
(16)Consists of 735,120 shares held by Atalan Master Fund, LP (“AMF”). Atalan Capital Partners, LP (“ACP”), is the investment manager of AMF. Atalan Capital Partners (GP), LLC (“ACPGP”) is the general partner of ACP. Atalan GP, LLC’s (“AGP”) the general partner of AMF. David R. Thomas is the managing member of ACPGP and AGP and may be deemed to have sole voting and investment power with respect to these shares of common stock. AMF disclaims beneficial ownership of these shares of common stock. The address of each of AMF, ACP, ACPGP, AGP and Mr. Thomas is 140 East 45th Street, 17th Floor, New York, NY 10017.
(17)Consists of 619,115 shares held by Carronade Capital Master, LP. Carronade Capital Master, LP, a Cayman Islands exempted limited partnership, is managed by Carronade Capital Management, LP, is a registered investment adviser. Carronade Capital Management, LP is a registered investment adviser with the SEC. The general partner of Carronade Capital Management, LP is Carronade Capital Management GP, LLC whose managing member and majority owner is Dan Gropper. Mr. Gropper, as the managing member and majority owner of Carronade Capital Management GP, LLC, may be deemed to have shared power to vote and/or shared power to dispose of the securities held by Carronade Capital Master, LP. The address of Carronade Capital Master, LP is c/o Walkers Corporate Limited, 190 Elgin Avenue, George Town, Grand Cayman KY1-9008, Cayman Islands.
(18)Consists of (i) 357,806 shares held by Aventail Energy Master Fund, LP, (ii) 44,723 shares held by Compass SAV II LLC, (iii) 101,798 shares held by Crown/Aventail Segregated Portfolio and (iv) 29,815 shares held by Compass Offshore SAV II PCC Limited (collectively, the “Aventail Funds”). Aventail Capital Group, LP (“Aventail”) serves as the investment manager for the Aventail Funds and thus may be deemed to beneficially own the shares of common stock identified above. Aventail, as well as Sameer Sethna and Sean Grant, the managing members of Aventail, have authority to direct the voting and disposition of the shares of common stock identified above, and thus are deemed to share voting power for the shares beneficially owned by the Aventail Funds. Aventail, Sameer Sethna and Sean Grant disclaim any such beneficial ownership of securities not held of record by them, except to the extent they have a pecuniary interest therein. The address of each of the Aventail Funds is 1370 Avenue of the Americas, 27th Floor, New York, NY 10019.
(19)Consists of (i) 324,072 shares held by Brown Advisory Small-Cap Fundamental Value Fund, LP, (ii) 20,778 shares held by Brown Advisory U.S. Small-Cap Blend Fund and (iii) 174,526 shares held by stockholders affiliated with Brown Advisory LLC. Brown Advisory Incorporated is the manager of Brown Advisory Management, LLC, which is the sole member of Brown Advisory LLC (“Brown”), which serves as the investment manager for the Brown Advisory Funds, Brown Advisory Funds plc, and investors via separately managed accounts, and thus may be deemed to beneficially own the shares of common stock identified above. J. David Schuster, portfolio manager of Brown, and Brown have authority to direct the voting and disposition of the shares of common stock identified above, and thus are deemed to share voting power for the shares beneficially owned. J. David Schuster and Brown disclaim any such beneficial ownership of securities not held of record by them, except to the extent they have a pecuniary interest therein. The address of each of the Brown Advisory affiliated stockholders is 901 S. Bond Street, Suite 400, Baltimore, MD 21231.
(20)Consists of 500,607 shares held by Solar Projects LLC, a Delaware limited liability company (“Solar Projects”). Solar Projects is disregarded and wholly owned by Solar Trust No. 2, a Delaware non-grantor trust (“Solar Trust”). Solar Trust is managed by First Republic Trust Company of Delaware (“First Republic”) and Daniel Scott Gimbel (“Mr. Gimbel”). Each of the First Republic and Mr. Gimbel may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent each has a pecuniary interest therein. The business address of each of First Republic and Mr. Gimbel is 1201 North Market Street, Suite 1002, Wilmington, DE 19801.
(21)Consists of (i) 138,411 shares held by PSAM WorldArb Master Fund Ltd, (ii) 47,993 shares held by Rebound Portfolio Ltd, (iii) 124,748 shares held by Lumyna Specialist Funds - PSAM Credit Opportunities Fund, (iv) 148,807 shares held by Lumyna Funds - Lumyna - PSAM Global Event UCITS Fund. (collectively, the “PSAM Funds”). P. Schoenfeld Asset Management LP (“PSAM”), is the investment manager, sub-investment manager, or sub-adviser of each of the PSAM Funds. Peter Schoenfeld is the CEO of PSAM. PSAM and Peter Schoenfeld have voting and investment power over the shares held directly by the PSAM Funds. Each of PSAM and Peter Schoenfeld disclaim beneficial ownership of the securities reported herein except to the extent of their pecuniary interest therein. The address of each of PSAM WorldArb Master Fund Ltd, Rebound Portfolio Ltd, Lumyna Specialist Funds - PSAM Credit Opportunities Fund, Lumyna Funds - Lumyna - PSAM Global Event UCITS Fund is c/o P. Schoenfeld Asset Management LP, 1350 Avenue of the Americas, 21st Floor, New York, NY 10019.
(22)Consists of (i) 104,423 shares held by Blackwell Partners LLC - Series A, (ii) 92,852 shares held by Cassini Partners, L.P., (iii) 162,071 Philosophy Capital Partners, LP and (iv) 47,074 shares held by Star V Partners, LLC (collectively, the “Philosophy Funds”). Philosophy Capital Management LLC is the general partner and investment adviser of private investment funds and the investment adviser to the Philosophy Funds and may be deemed to share beneficial ownership of the securities reported herein, but disclaims any such beneficial ownership of the securities not held of record by it, except to the extent it has a pecuniary interest therein. The address of each of the Philosophy Funds is 3201 Danville Boulevard, Suite 100, Alamo, CA 94507.
(23)Consists of 400,000 shares held by Hartree Partner, LP (“Hartree”). Hartree is managed by Hartree Partners GP, LLC (“Hartree GP”) as the general partner of Hartree. The management committee of Hartree GP establishes the trading guidelines of Hartree and holds voting and dispositive power over the shares held by Hartree. Such management committee is comprised of the following six members: Stephen Hendel, Stephen Semlitz, Jonathan Merison, Robert O’Leary, Brook Hinchman and Jordan Mikes. The address of Hartree, Hartree GP and Messrs. Hendel, Semlitz, and Merison is 1185 Avenue of the Americas, New York, New York 10036. The address of Messrs. O’Leary, Hinchman and Mikes is 333 South Grand Avenue, 28th Floor, Los Angeles, California 90071.
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(24)Consists of 397,183 shares held by Two Seas Global (Master) Fund LP. Two Seas Global (Master) Fund LP (the “Two Seas Fund”) has delegated to Two Seas Capital LP (“TSC”) sole voting and investment power over the securities held by the Two Seas Fund pursuant to its Investment Management Agreement with TSC. As a result, each of TSC, Two Seas Capital GP LLC (“TSC GP”), as the general partner of TSC, and Mr. Sina Toussi, as Chief Investment Officer of TSC and Managing Member of TSC GP, may be deemed to exercise voting and investment power over the securities directly held by the Two Seas Fund. The Two Seas Fund specifically disclaims beneficial ownership of the securities directly held by it by virtue of its inability to vote or dispose of such securities as a result of its Investment Management Agreement with TSC. The address of the Two Seas Fund is c/o Two Seas Capital LP, 32 Elm Place, 3rd Floor, Rye, NY 10580.
(25)Consists of (i) 6,469 shares held by Nuveen All-American Municipal Bond Fund, (ii) 4,311 shares held by Nuveen Enhanced High Yield Municipal Bond Fund, (iii) 15,927 shares held by Nuveen High Yield Municipal Opportunities Fund LP, (iv) 3,911 shares held by Nuveen Dynamic Municipal Opportunities Fund, (v) 270,869 shares held by Nuveen High Yield Municipal Bond Fund, (vi) 18,229 shares held by Nuveen Municipal Credit Opportunities Fund, (vii) 19,318 shares held by Nuveen Short Duration High Yield Municipal Bond Fund, (viii) 2,590 shares held by Nuveen Strategic Municipal Opportunities Fund, (ix) 119 shares held by Nuveen AMT-Free Municipal Value Fund and (x) 14,828 shares held by Nuveen AMT-Free Municipal Credit Income Fund (collectively, the “Nuveen Funds”). Nuveen Asset Management, LLC is the registered investment adviser to the Nuveen Funds that own the shares of common stock being registered hereby, and may be deemed to be a beneficial owner of the shares of common stock owned separately by the Nuveen Funds. The business address of each of the Nuveen Funds is c/o Nuveen Asset Management LLC, 333. W. Wacker Drive, Chicago, IL 60606.
(26)Consists of (i) 195,440 shares held by Aristeia Master, L.P. (“Aristeia Master”), (ii) 10,459 shares held by ASIG International Limited (“ASIG”), (iii) 75,968 shares held by Blue Peak Limited (“Blue Peak”), (iv) 7,873 shares held by DS Liquid Div RVA ARST LLC (“DS Liquid”) and (v) 5,260 shares held by Windermere Cayman Fund Limited (“Windermere”). Aristeia Capital, L.L.C. and Aristeia Advisors, L.L.C. (collectively, “Aristeia”) may be deemed the beneficial owners of the securities described herein in their capacity as the investment manager and/or general partner, as the case may be, of Aristeia Master, ASIG, Blue Peak, DS Liquid, and Windermere (each, an “Aristeia Fund” and collectively, the “Aristeia Funds”), which are the holders of such securities, as indicated above. As investment manager and/or general partner of each Aristeia Fund, Aristeia has voting and investment control with respect to the securities held by each Aristeia Fund. Anthony M. Frascella and William R. Techar are the co-Chief Investment Officers of Aristeia. Each of Aristeia and such individuals disclaims beneficial ownership of the securities referenced herein except to the extent of its or his direct or indirect economic interest in the Aristeia Funds. The address of Aristeia and each of the Aristeia Funds is c/o Aristeia Capital, L.L.C., One Greenwich Plaza, Suite 300, Greenwich, CT 06830.
(27)Consists of (i) 21,895 shares held by DG Value Partners, LP (“GVP”), (ii) 242,951 shares held by DG Value Partners II Master Fund, LP (“DGVP II”), (iii) 1,432 shares held by Yakar Alternatives LLC (“Yakar”), (iv) 3,379 shares held by Yakar Alternatives CLAT LLC (“Yakar CLAT”), (v) 1,334 shares held by PPG Hedge Fund Holdings LLC (“PPG”) and (vi) 5,253 shares held by MACYRC LLC (“MACYRC”). DGVP is controlled by DG Capital Partners, LLC (“DG Capital Partners”), its general partner. DGVP II is controlled by DG Capital Partners II, LLC (“DG Capital Partners II”), its general partner. Each of Yakar, Yakar CLAT, PPG and MACYRC is controlled by DG Capital Advisors, LLC (“DG Capital Advisors” and, together with DGVP, DGVP II, Yakar, Yakar CLAT, PPG, MACYRC, DG Capital Partners and DG Capital Partners II, the “DG Capital Entities”), each such entity’s investment manager. Each of DG Capital Partners, DG Capital Partners II and DG Capital Advisors is controlled by Dov Gertzulin, each such entity’s managing member. Each of the DG Capital Entities and Mr. Gertzulin may be deemed to share beneficial ownership of the securities reported herein. The address of each of the DG Capital Entities and Mr. Gertzulin is c/o DG Capital Management, LLC, 460 Park Avenue, 22nd Floor, New York, NY 10022.
(28)Consists of 272,837 shares held by RIT Capital Partners plc. RIT Capital Partners plc has delegated investment management to J. Rothschild Capital Management Limited, a private limited company, incorporated in England and Wales with company number 02201053, which is regulated in the United Kingdom by the Financial Conduct Authority. J. Rothschild Capital Management Limited may be deemed to share beneficial ownership of the shares of common stock reported herein, but disclaims any such beneficial ownership of shares of common stock not held of record by it, except to the extent it has pecuniary interest therein. The address of RIT Capital Partners plc is Spencer House, 27 St. James’s Place, London, SW1A 1NR.
(29)Consists of 221,422 shares held by SteelMill Master Fund LP (“SteelMill”). PointState Holdings LLC (“PointState Holdings”) serves as the general partner of SteelMill. PointState Capital LP (“PointState”) serves as the investment manager to SteelMill. PointState Capital GP LLC (“PointState GP”) serves as the general partner of PointState. Zachary J. Schreiber serves as the managing member of PointState Holdings and PointState GP. Each of PointState GP and Mr. Schreiber may be deemed to have shared power to vote and/or shared power to dispose of the securities held by SteelMill. The address of SteelMill is, PO Box 309, Ugland House, Grand Cayman KY1-1104, Cayman Islands.
(30)Consists of 126,422 shares held Lee Jamieson, a natural person (“Jamieson”). The business address of Jamieson is 1255 Tam O’Shanter, Bakersfield, CA 93309.
(31)Consists of (i) 77,406 shares held by Purpose Credit Opportunities Fund (“Purpose Credit”) and (ii) 36,993 shares held by Purpose Strategic Yield Fund (“Purpose Strategic”). Purpose Investment Partners Inc. (“Purpose Investment Partners”) is the investment manager of Purpose Credit and the sub-advisor to Purpose Strategic. Purpose Investments Inc. (“Purpose Investments” and, together with Purpose Investment Partners, the “Purpose Managers”) is the investment manager of Purpose Strategic and the sub-advisor to Purpose Credit. Sandy Liang is the lead portfolio manager of each of Purpose Credit and Purpose Strategic. Each of the Purpose Managers and Mr. Liang may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent each has a pecuniary interest therein. The business address of each of Purpose Credit, Purpose Strategic, the Purpose Managers and Mr. Liang is 130 Adelaide St. West, Suite 3100, Toronto, Ontario, Canada.
(32)Consists of (i) 4,216 shares held by Franklin Universal Trust, (ii) 58,650 shares held by Franklin High Income Trust-Franklin High Income Fund, (iii) 21,342 shares held by Franklin Templeton Investment Funds-Franklin High Yield Fund, (iv) 4,438 shares held by Franklin Limited Duration Income Trust and (v) 4,508 shares held by Franklin Templeton ETF Trust-Franklin High Yield Corporate ETF (collectively, the “Franklin Funds”). The securities are beneficially owned by the Franklin Funds that are investment management clients of Franklin Advisers, Inc. (“FAV”) which is a subsidiary of Franklin Resources Inc. (“FRI”). FRI has delegated to FAV investment discretion or voting power over the securities listed, and FRI treats FAV as having sole investment discretion or voting authority, as the case may be, unless the agreement specifies otherwise. Accordingly, FAV reports on filings with the SEC (“FAV SEC filings”), including on Schedule 13G that it has sole investment discretion and voting authority over the securities covered by any such investment management agreement, unless otherwise noted. As a result, for purposes of Rule 13d-3 under the Securities Act, FAV may be deemed to be the beneficial owners of
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the securities reported in such FAV SEC filings. The address of each of the Franklin Funds is c/o Franklin Advisers, Inc., One Franklin Parkway, San Mateo, CA 94403. Each of the Franklin Funds is an affiliate of a registered broker-dealer and has represented to the Company that its shares of common stock being offered for resale hereby were purchased in the ordinary course of business and that, at the time of purchase of such shares, it did not have any arrangements or understandings, directly or indirectly, with any person to distribute such shares.
(33)Consists of (i) 36,762 shares held by Yost Partners, L.P. and (ii) 7,081 shares held by Yost Focused Long Fund, L.P. (collectively, the “Yost Funds”). Tomcat Management, L.P., a Texas limited partnership (“Tomcat Management”), serves as the general partner of Yost Partners, L.P. (“Yost Partners”) and Yost Focused Long Fund, L.P. (“Yost Focused”). Tomcat Advisors, L.L.C., a Texas limited liability company (“Tomcat Advisors”) serves as the general partner of Yost Management, LP, a Texas limited partnership (“Yost Management”), which serves as the investment manager of Yost Partners. Carson Yost is the Manager of Tomcat Advisors. Tomcat Management, Tomcat Advisors, Yost Management and Carson Yost may each be deemed to have beneficial ownership of shares held by the Yost Funds and each disclaims beneficial ownership of these shares except to the extent of any pecuniary interest therein. The address of each of the Yost Funds is 4550 Post Oak Place Drive, Suite 301, Houston, TX 77027.
(34)Consists of 43,250 shares held by Livello Capital Special Opportunities Fund LP (“Livello”). Livello is managed by Livello Capital Management LP (“Livello Management”), which is wholly owned by Philip Giordano (“Mr. Giordano”). Each of Livello Management and Mr. Giordano may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent they have a pecuniary interest therein. The business address of Livello Management is 104 West 40th Street, 19th Floor, New York, NY 10018.
(35)Consists of (i) 835 shares held by Boothbay Absolute Return Strategies, LP, (ii) 631 shares held by Boothbay Diversified Alpha Master Fund LP, (iii) 3,613 shares held by FW Deep Value Opportunities Fund I, (iv) 383 shares held by FourWorld Event Opportunities, LP and (v) 4,136 shares held by FourWorld Global Opportunities Fund, Ltd. (collectively, the “FW Funds”). FourWorld Capital Management LLC (“FWCM”) is the investment manager of the FW Funds. FWCM may be deemed beneficial owner of the Company securities being registered hereby for the sale of the FW Funds. John Addis, as the Chief Investment Officer of FWCM, makes voting and investment decisions for the FW Funds, but disclaims beneficial ownership of the shares held by them. The address of each of the FW Funds is 7 World Trade Center, Floor 46, New York, NY 10007.
(36)Consists of 7,892 shares held by CSS, LLC, an Illinois limited liability company (“CSS”). CSS is managed by Brian Bentley (“Mr. Bentley”), Glenn McMillan (“Mr. McMillan”) and Clayton Struve (“Mr. Struve”). Each of Mr. Bentley, Mr. McMillan and Mr. Struve may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent each has a pecuniary interest therein. The business address of each of Mr. Bentley, Mr. McMillan and Mr. Struve is 175 W. Jackson Boulevard, Suite 440, Chicago, IL 60604.
(37)Consists of 7,149 shares held by ACR Strategic Credit LP (“ASC LP”). ACR Alpine Capital Research, LLC (“ACR”) is the investment manager for ASC LP. Nicholas Tompras holds a controlling interest in ACR and ACR CV LLC, the general partner of ASC LP. ACR and Nicholas Tompras may be deemed to beneficially own the securities held by ASC LP. ACR and Nicholas Tompras each disclaim beneficial ownership of such securities except to the extent of their pecuniary interests therein. The address of ASC LP is 190 Carondelet Plaza, Suite 1300, St. Louis, MO 63105.
(38)Consists of 7,000 shares held Comeg Trust LLC, a Delaware limited liability company (“Comeg”). Comeg is disregarded and wholly owned by Comeg Trust, a Delaware non-grantor trust (“Comeg Trust”). Comeg Trust is managed by the Bryn Mawr Trust Company of Delaware (“Bryn Mawr”) and Daniel Scott Gimbel (“Mr. Gimbel”). Each of the Bryn Mawr and Mr. Gimbel may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent each has a pecuniary interest therein. The business address of each of Bryn Mawr and Mr. Gimbel is 20 Montchanin Road, Suite 100, Greenville, DE 19807.
(39)Consists of (i) 731 shares held by Corbin Opportunity Fund, L.P. and (ii) 3,621 shares held by Corbin ERISA Opportunity Fund, Ltd. (collectively, the “Corbin Funds”). Corbin Capital Partners, L.P. (“CCP”) is the investment manager of each of the Corbin Funds. CCP and its general partner, Corbin Capital Partners GP, LLC, may be deemed beneficial owners of the Company securities being registered hereby for sale by the Corbin Funds. Craig Bergstrom is the Chief Investment Officer of Corbin Capital Partners, L.P. and directs the voting and investment decisions with respect to the reported shares held by the Corbin Funds, but disclaims beneficial ownership of such shares. The address of each of the Corbin Funds is 575 Madison Avenue, 21st Floor, New York, NY 10022.
(40)Consists of 2,674 shares held by DPA Trust No. 1 LLC, a Delaware limited liability company (“DPA LLC”). DPA LLC is disregarded and wholly owned by DPA Trust No. 1, a Delaware non-grantor trust (“DPA Trust”). DPA Trust is managed by Bryn Mawr Trust Company of Delaware (“Bryn Mawr”) and Alexander Salciccia (“Mr. Salciccia”). Each of the Bryn Mawr and Mr. Salciccia may be deemed to share beneficial ownership of the securities reported herein, but each disclaims any such beneficial ownership of securities not held of record by them, except to the extent each has a pecuniary interest therein. The business address of each of Bryn Mawr and Mr. Salciccia is 20 Montchanin Road, Suite 100, Greenville, DE 19807.
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DESCRIPTION OF CAPITAL STOCK
General
The following is a summary of the rights of our capital stock and certain provisions of our Charter, our Bylaws, the Registration Rights Agreement, the Stockholders Agreement and relevant provisions of the DGCL. The descriptions herein are qualified in their entirety by reference to our Charter, Bylaws, Registration Rights Agreement and Stockholders Agreement copies of which have been filed as exhibits to the registration statement of which this prospectus is a part, as well as the relevant provisions of the DGCL.
Authorized Capital Stock
Our Charter authorizes us to issue up to 400,000,000 shares of capital stock, consisting of (i) 350,000,000 shares of our common stock, par value $0.001 per share; and (ii) 50,000,000 shares of preferred stock, par value $0.01 per share (our “preferred stock”). As of July 1, 2024, there were 50,841,161 shares of our common stock outstanding held by three stockholders of record, and no shares of preferred stock were issued and outstanding. Pursuant to our Charter, our Board of Directors has the authority, without stockholder approval, except as required by the listing standards of Nasdaq, to issue additional shares of our common stock.
Common Stock
All issued and outstanding shares of our common stock are duly authorized, validly issued, fully paid and non-assessable. All authorized but unissued shares of our common stock are available for issuance by our Board of Directors without any further stockholder action, except as required by the listing standards of Nasdaq.
The rights, preferences and privileges of holders of common stock are subject to and may be adversely affected by the rights of the holders of shares of any series of preferred stock that we may designate and issue in the future.
Voting Rights
All shares of our common stock have identical rights and privileges. The holders of shares of our common stock are entitled to vote on all matters submitted to a vote of our stockholders, including the election of directors. On all matters to be voted on by holders of shares of our common stock, the holders will be entitled to one vote for each share of our common stock held of record and will have no cumulative voting rights.
Dividend Rights
Subject to limitations under applicable Delaware law, preferences that may apply to any outstanding shares of our preferred stock and contractual restrictions, holders of our common stock are entitled to receive dividends or other distributions ratably, when, as and if declared by the Board of Directors. The ability of the Board of Directors to declare dividends with respect to our common stock, however, will be subject to such limitations, preferences and restrictions and the availability of sufficient funds under the DGCL to pay such dividends.
Right to Receive Liquidation Distributions
In the event of a voluntary or involuntary liquidation, dissolution or winding up of Talen, after payment or provision for payment of the debts and other liabilities of Talen, and subject to the rights of the holders of preferred stock in respect thereof, the remaining assets of Talen will be distributed ratably to the holders of shares of our common stock.
Other Matters
Holders of shares of our common stock do not have preemptive, subscription, redemption or conversion rights.
Warrants
Pursuant to that certain Employment Agreement, dated December 12, 2022, by and between TES and Leonard LoBiondo, at Emergence, Mr. LoBiondo acquired warrants to purchase up to 457,142 shares of our common stock
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with a tenor of seven years and a strike price of $43.75, subject to adjustment in certain circumstances, the terms of which are set forth in the that certain Warrant Certificate No. L-1, dated May 17, 2023, issued by TEC.
Registration Rights
At Emergence, TEC entered into the Registration Rights Agreement with the Reg Rights Holders that, among other things, granted customary registration rights to the Reg Rights Holders and certain of their permitted transferees, including customary shelf registration rights and piggyback rights, which may be exercised after the consummation of an initial public offering. For additional information about the Registration Rights Agreement, please see “Certain Relationships and Related Party Transactions—Registration Rights Agreement and Stockholders Agreement.”
Stockholders Agreement
At Emergence, TEC also entered into the Stockholders Agreement with the Holders. Pursuant to the Stockholders Agreement, the Holders have certain limited information rights, drag-along rights and tag-along rights. The Stockholders Agreement also provides that certain Holders have rights to require TEC to pursue an initial public offering and consent to certain key elements of the initial public offering structure. Such right of the Offering Committee to require TEC to pursue and consummate an initial public offering will cease to exist upon the consummation of such initial public offering. For additional information about the Stockholders Agreement, please see “Certain Relationships and Related Party Transactions—Registration Rights Agreement and Stockholders Agreement.”
Anti-Takeover Effects of Delaware Law and Our Charter and Bylaws
Some provisions of Delaware law and our Charter and our Bylaws contain provisions that could make the following transactions more difficult: an acquisition of us by means of a tender offer; an acquisition of us by means of a proxy contest or otherwise; or the removal of our incumbent officers and directors. It is possible that these provisions could make it more difficult to accomplish or could deter transactions that stockholders may otherwise consider to be in their best interest or in our best interests, including transactions which provide for payment of a premium over the market price for our shares.
These provisions, summarized below, are intended to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our Board of Directors. We believe that the benefits of the increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging these proposals because negotiation of these proposals could result in an improvement of their terms.
Preferred Stock
Subject to limitations under applicable Delaware law, our Board of Directors have the authority, without further action by our stockholders, to issue up to 50,000,000 shares of unissued preferred stock with rights and preferences, including voting rights, designated from time to time by our Board of Directors. The existence of authorized but unissued shares of preferred stock enables our Board of Directors to render more difficult or to discourage an attempt to obtain control of us by means of a merger, tender offer, proxy contest or other means.
Removal of Directors
Our Charter provides that members of our Board of Directors may be removed from office, with or without cause, by an affirmative vote of the holders of at least a majority of the outstanding shares of capital stock entitled to vote thereon.
Section 203 of the DGCL
In our Charter, we have elected not to be governed by Section 203 of the DGCL, as permitted under and pursuant to subsection (b)(3) of Section 203. Section 203 prohibits a publicly held Delaware corporation from
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engaging in a business combination, such as a merger, with a person or group owning 15% or more of the corporation’s outstanding voting stock for a period of three years following the date the person became an interested stockholder, unless (with certain exceptions) the business combination or the transaction in which the person became an interested stockholder is approved in a prescribed manner. Accordingly, we are currently not subject to any anti-takeover effects of Section 203, although no assurance can be given that we will not elect to be governed by Section 203 of the DGCL in the future.
Board Vacancies and Board Size
Our Charter and Bylaws provide that any vacant directorships, including newly created directorships, may only be filled by a majority of the directors then in office, even if less than a quorum, or by a sole remaining director. The number of directors constituting the full Board of Directors is set by a resolution of the Board of Directors.
Special Stockholder Meetings
Except as required by the DGCL or the terms of any class or series of preferred stock issued in the future, special meetings of our stockholders may be called only by (a) the Chair of the Board of Directors, (b) the Board of Directors pursuant to a resolution adopted by a majority of a quorum of the Board of Directors or (c) the Board of Directors upon the delivery of a written request complying with the procedures outlined in our Bylaws by the holders of at least 15% of the voting power of the then outstanding shares of capital stock entitled to vote on the matters to be submitted to stockholders at such meeting.
Requirements for Advance Notification of Stockholder Nominations and Proposals
Stockholders must provide timely notice when seeking to:
•bring business before an annual meeting of stockholders;
•bring business before a special meeting of stockholders (if contemplated and permitted by the notice of a special meeting); or
•nominate candidates for election to the Board of Directors at an annual meeting of stockholders or at a special meeting of stockholders called for the purpose of electing one or more directors to the Board of Directors.
To be timely, a stockholders notice generally must be received by the Secretary of Talen at our principal executive offices:
•in the case of an annual meeting:
◦not later than the close of business on the 90th day nor earlier than the close of business on the 120th day prior to the first anniversary of the date of the immediately preceding year’s annual meeting, or
◦if the annual meeting is called for a date that is more than 30 days before or more than 60 days after the first anniversary of the date of the immediately preceding year’s annual meeting, or if no annual meeting was held in the immediately preceding year, not earlier than the opening of business on the 120th day prior to such annual meeting and not later than the earlier of (A) the close of business on the later of the 90th day prior to the annual meeting and (B) the 10th day following the day on which the first public announcement of the date of the annual meeting is made by Talen; or
•in the case of a special meeting, not earlier than the opening of business on the 120th day and not later than the close of business on the later of the 90th day prior to the special meeting and the 10th day following the day on which public announcement is first made of the date of the special meeting and the nominees proposed by the Board of Directors.
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Our Charter and Bylaws also specify requirements as to the form and content of the stockholder’s notice. These provisions may preclude stockholders from bringing matters before or proposing director nominees to an annual meeting or a special meeting of stockholders.
Stockholders Not Entitled to Cumulative Voting
The DGCL provides that stockholders are not entitled to cumulate votes in the election of directors unless a corporation’s certificate of incorporation provides otherwise. Our Charter does not provide for cumulative voting.
Amendment of Bylaws Provision
The Bylaws may be amended, altered or repealed, or new bylaws made, by vote of (a) a majority of the directors present at a meeting at which a quorum of the Board of Directors is present or (b) the holders of a majority of the voting power of all outstanding shares of capital stock of Talen entitled to thereon, voting together as a single class.
Exclusive Forum
Our Charter provides that, unless we consent to the selection of an alternative forum, the sole and exclusive forum for: (a) any derivative action or proceeding brought on our behalf; (b) any action asserting a claim of breach of a fiduciary duty owed by any of our current or former directors, officers, other employees or stockholders to us or to our stockholders; (c) any action asserting a claim arising pursuant to the DGCL, our Charter or Bylaws, or as to which the DGCL confers jurisdiction on the Court of Chancery of the State of Delaware; or (d) any action asserting a claim governed by the internal affairs doctrine shall be the Court of Chancery of the State of Delaware (or, if the Court of Chancery does not have, or declines to accept, jurisdiction, another state court or a federal court located within the State of Delaware that does have jurisdiction).
Our Charter further provides that, unless we consent in writing to the selection of an alternative forum, the federal district courts of the United States of America are the sole and exclusive forum for the resolution of any complaint asserting a cause of action arising under the Securities Act against us or any of our directors or officers, except to the extent such jurisdiction is contrary to law. We note that investors cannot waive compliance with the federal securities laws and the rules and regulations thereunder. Although we believe the provision benefits us by providing increased consistency in the application of Delaware law in the types of lawsuits to which it applies, the provision may have the effect of discouraging lawsuits against our directors and officers. Additionally, the Company cannot be certain that a court will decide that these provisions are either applicable or enforceable, and if a court were to find the choice of forum provisions contained in our Charter to be inapplicable or unenforceable in an action, we may incur additional costs associated with resolving such action in other jurisdictions, which could harm the business, operating results and financial condition of the Company.
Section 27 of the Exchange Act creates exclusive federal jurisdiction over all suits brought to enforce any duty or liability created by the Exchange Act or the rules and regulations thereunder. As a result, the exclusive forum provision in our Charter will not apply to suits brought to enforce any duty or liability created by the Exchange Act or any other claim for which the federal courts have exclusive jurisdiction.
Transfer Restrictions
Due to regulatory authorization requirements imposed by federal law and implemented by the Federal Energy Regulatory Commission, our Charter requires prior written consent of the Board of Directors in any case where an acquisition or other transfer of voting securities would cause the holdings of the transferee, together with those of its “affiliates” (as such term is defined in 18 C.F.R. §35.36(a)(9)), directly or indirectly, to either (i) equal or exceed 10% of our outstanding voting securities or (ii) equal or exceed 10% of the outstanding voting securities in any Talen public utility subsidiary after accounting for both our voting securities and the voting securities of the public utility subsidiary held other than indirectly as a result of holding our voting securities. This restriction also applies to the ability of any existing 10% holder to acquire additional shares of our common stock, but does not apply to certain secondary market purchases or sales of our common stock made by third-party investors on Nasdaq that are outside of our control, do not directly involve us and are made without prior notice to us.
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Authorized but Unissued Shares
Delaware law does not require stockholder approval for any issuance of authorized shares. Pursuant to our Charter, our Board of Directors has the authority, without stockholder approval, except as required by the listing standards of Nasdaq, to issue authorized but unissued shares of our common stock.
Limitations on Liability and Indemnification of Directors and Officers
As permitted by Section 145 of the DGCL, our Bylaws provide that:
•we shall indemnify our directors and executive officers to the fullest extent permitted by the DGCL, subject to limited exceptions, and that we may indemnify other officers, employees or other agents;
•we shall advance expenses to our directors and executive officers in connection with a legal proceeding to the fullest extent permitted by the DGCL, subject to limited exceptions; and
•the rights provided in our Bylaws are not exclusive.
Any amendment to, or repeal of, these provisions will not eliminate or reduce the effect of these provisions in respect of any act, omission or claim that occurred or arose prior to that amendment or repeal. If the DGCL is amended to provide for further limitations on the personal liability of directors or officers of corporations, then the personal liability of our directors and officers will be further limited to the fullest extent permitted by the DGCL.
Transfer Agent and Registrar
The transfer agent and registrar for our common stock will be Equiniti Trust Company, LLC. The transfer agent and registrar’s address is 48 Wall Street, Floor 23, New York, New York 10005.
Exchange Listing
Our common stock is currently not listed on any securities exchange. We have applied to have our common stock listed on Nasdaq under the symbol “TLN.”
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SHARES ELIGIBLE FOR FUTURE SALE
Future issuances or sales of substantial amounts of our common stock in the public market, or the perception that such issuances or resales may occur, could adversely affect the prevailing market price of our common stock. No prediction can be made as to the effect, if any, future issuances or resales of shares, or the availability of shares for future sales, will have on the market price of our common stock prevailing from time to time. See “Risk Factors—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.”
As of July 1, 2024, we have a total of 50,841,161 shares of common stock issued and outstanding (after taking into account the 8,187,682 shares of the Company’s common stock the Company has repurchased under its share repurchase program, inclusive of our recent tender offer and the Rubric Share Repurchase). Of the 59,028,843 shares of common stock issued and outstanding at Emergence, 15,135,955 shares were issued in reliance on the exemption from registration provided by Section 1145 of the Bankruptcy Code (the “1145 Shares”) on an unrestricted CUSIP and 43,892,888 shares were issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act (the “4(a)(2) Shares”) on a restricted CUSIP. In May 2024, each of the outstanding 4(a)(2) Shares were exchanged for an unrestricted share on the unrestricted CUSIP. Please see “Prospectus Summary—Recent Developments—Mandatory Share Exchange” for additional information. Our outstanding shares are freely tradable without restriction or further registration under the Securities Act, except that any shares held by any affiliates, as that term is defined under Rule 144 of the Securities Act, will be considered control securities and may be sold only in compliance with the limitations described below.
We plan to file a registration statement on Form S-8 under the Securities Act to register shares of our common stock or securities convertible into or exchangeable for shares of common stock issued pursuant to our 2023 Equity Plan. Any such Form S-8 registration statement will automatically become effective upon filing. Accordingly, subject to applicable vesting restrictions or lock-up restrictions and except for shares held by affiliates, shares to be registered under any such registration statement will be available for sale in the open market.
Rule 144
Affiliate Resales
In general, a person who is an affiliate of ours, or who was an affiliate at any time during the 90 days before a sale, would be entitled to sell in “broker’s transactions” or certain “riskless principal transactions” or to market makers, a number of shares within any three-month period that does not exceed the greater of:
•1% of the number of shares of our common stock then outstanding, which will equal approximately 532,600 shares upon the effectiveness of the registration statement of which this prospectus forms a part; or
•the average weekly trading volume in our common stock on Nasdaq during the four calendar weeks preceding the filing of a notice on Form 144 with respect to such sale.
Affiliate resales under Rule 144 are also subject to the availability of current public information about us. In addition, if the number of shares being sold under Rule 144 by an affiliate during any three-month period exceeds 5,000 shares or has an aggregate sale price in excess of $50,000, the seller must file a notice on Form 144 with the SEC concurrently with either the placing of a sale order with the broker or the execution of a sale directly with a market maker.
Non-Affiliate Resales
In general, a person who is not an affiliate of ours at the time of sale, or has not been an affiliate at any time during the three months preceding a sale, is entitled to sell such shares subject only to the availability of current public information about us. If such person has held our shares for at least one year, such person can resell under
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Rule 144(b)(1) without regard to any Rule 144 restrictions, including the 90-day public company requirement and the current public information requirement.
Non-affiliate resales are not subject to the manner of sale, volume limitation or notice filing provisions of Rule 144.
Rule 701
In general, under Rule 701, any of our employees, directors, officers, consultants or advisors who purchases shares from us in connection with a compensatory stock or option plan or other written agreement before the effective date of a registration statement under the Securities Act is entitled to sell such shares 90 days after such effective date in reliance on Rule 144. Securities issued in reliance on Rule 701 are restricted securities and, subject to the contractual restrictions described above, beginning 90 days after the date of this prospectus, may be sold by persons other than “affiliates,” as defined in Rule 144, subject only to the manner of sale provisions of Rule 144 and by “affiliates” under Rule 144 without compliance with its one-year minimum holding period requirement.
Form S-8 Registration Statement
We intend to file one or more registration statements on Form S-8 under the Securities Act to register all shares of our common stock, PSUs and RSUs subject to outstanding stock options under our 2023 Equity Plan. We expect to file the registration statement covering shares offered pursuant to these stock plans shortly after the date of this prospectus, permitting the resale of such shares by non-affiliates in the public market without restriction under the Securities Act and the sale by affiliates in the public market subject to compliance with the resale provisions of Rule 144.
Registration Rights
Holders of at least three percent of our outstanding common stock will be entitled to various rights with respect to the registration of these shares under the Securities Act upon the effectiveness of the registration statement of which this prospectus forms a part. Registration of these shares under the Securities Act would result in these shares becoming freely tradable without restriction under the Securities Act immediately upon the effectiveness of the registration, except for shares purchased by affiliates. See the section titled “Description of Capital Stock—Registration Rights” for additional information.
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MATERIAL U.S. FEDERAL INCOME TAX CONSEQUENCES TO NON-U.S. HOLDERS OF OUR COMMON STOCK
The following is a general discussion of the material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock purchased pursuant to this offering by a non-U.S. holder. For the purpose of this discussion, a non-U.S. holder is any beneficial owner of our common stock that is an individual, corporation, estate or trust and that is not for U.S. federal income tax purposes any of the following:
•an individual citizen or resident of the U.S.;
•a corporation (or other entity treated as a corporation for U.S. federal income tax purposes) created or organized in the U.S. or under the laws of the United States or any state thereof, or the District of Columbia;
•a partnership (or other entity or arrangement treated as a partnership or other pass-through entity for U.S. federal income tax purposes);
•an estate, the income of which is subject to U.S. federal income tax regardless of its source; or
•a trust that (x) is subject to the primary supervision of a U.S. court within the United States and has one or more U.S. persons (within the meaning of Section 7701(a)(30) of the Code, as defined for U.S. federal income tax purposes) who have the authority to control all substantial decisions of the trust or (y) has made a valid election under applicable U.S. Treasury Regulations to be treated as a U.S. person.
If a partnership (or an entity treated as a partnership for U.S. federal income tax purposes) holds our common stock, the tax treatment of a partner in the partnership will generally depend on the status of the partner and upon the activities of the partnership. Accordingly, if you are treated as a partner of a partnership that holds our common stock you should consult your own tax advisor as to the particular U.S. federal income tax consequences applicable to you.
This discussion assumes that a non-U.S. holder will hold our common stock purchased pursuant to this offering as a capital asset within the meaning of Section 1221 of the Code (generally, property held for investment). This discussion does not address all aspects of U.S. federal taxation (including alternative minimum, gift and estate tax or any Medicare taxes imposed on net investment income) or any aspects of state, local or non-U.S. taxation. It does not consider any U.S. federal income tax considerations that may be relevant to non-U.S. holders that may be subject to special treatment under U.S. federal income tax laws, including, without limitation, U.S. expatriates, former citizens or long-term residents of the U.S., life insurance companies, real estate investment trusts, regulated investment companies, tax-exempt or governmental organizations, “qualified foreign pension funds” (within the meaning of Section 897(l)(2) of the Code and entities all of the interests of which are held by qualified foreign pension funds), tax-qualified retirement plans, brokers or dealers in securities or currency, banks or other financial institutions, “passive foreign investment companies,” “controlled foreign corporations,” investors that hold our common stock as part of a hedge, straddle, constructive sale, redemption, conversion transaction or other risk reduction strategy or integrated investment and, except as otherwise provided below, persons who at any time hold more than 5% of the fair market value of any class of our stock. Furthermore, the following discussion is based on current provisions of the Code, Treasury Regulations and administrative and judicial interpretations thereof, all as in effect on the date hereof, and all of which are subject to change, possibly with retroactive effect. We have not sought, and will not seek, any ruling from the IRS or any opinion of counsel with respect to the tax consequences discussed herein, and there can be no assurance that the IRS will not take a position contrary to the tax consequences discussed below or that any position taken by the IRS would not be sustained.
We urge each prospective investor to consult a tax advisor regarding the U.S. federal, state, local and non-U.S. income and other tax consequences of acquiring, holding and disposing of shares of our common stock.
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Distributions
If, in the discretion of the Board of Directors, we make distributions of cash or property on our common stock, those payments will constitute dividends to the extent paid from our current or accumulated earnings and profits, as determined under U.S. federal income tax principles. To the extent those distributions exceed our current and accumulated earnings and profits, the distributions will first constitute non-taxable returns of capital and reduce (but not below zero) a non-U.S. holder’s adjusted tax basis in its common stock (determined on a share-by-share basis), and then will be treated as gain from the sale of the common stock (subject to the rules discussed below under “— Gain on Disposition of Common Stock”). Any such distributions will also be subject to the discussion below under the section entitled “—Additional Withholding Tax Relating to Foreign Accounts.”
Subject to the discussion below on backup withholding and FATCA, any dividends (i.e., any distributions out of earnings and profits) paid to a non-U.S. holder of our common stock that are not effectively connected with a U.S. trade or business conducted by the non-U.S. holder generally will be subject to U.S. withholding tax either at a rate of 30% of the gross amount of the dividend or such lower rate as may be specified by an applicable tax treaty. Non-U.S. holders should consult their tax advisors regarding their entitlement to benefits under an applicable income tax treaty and the requirements for and manner of claiming the benefits of such treaty (including, without limitation, the need to obtain a U.S. taxpayer identification number). To receive the benefit of a reduced treaty rate, a non-U.S. holder must generally provide us or our paying agent with a valid IRS Form W-8BEN-E, W-8BEN or other appropriate version of IRS Form W-8 certifying qualification for the reduced rate prior to the payment of any dividend and otherwise comply with all other applicable legal requirements (including periodically updating such forms).
Dividends received by a non-U.S. holder that are effectively connected with a U.S. trade or business conducted by the non-U.S. holder (and, if provided by an applicable treaty, that are attributable to a U.S. permanent establishment of such non-U.S. holder) are exempt from such U.S. withholding tax (provided that the non-U.S. holder complies with certain certification and disclosure requirements). Non-U.S. holders should consult their tax advisors regarding their entitlement to the exemption from withholding on dividends effectively connected with such holder’s U.S. trade or business and the requirements for and manner of claiming the benefits of such exemption. To obtain this exemption, the non-U.S. holder must generally provide us or our paying agent with a valid IRS Form W-8ECI properly certifying such exemption and otherwise comply with all other applicable legal requirements (including, without limitation, periodically updating such form). Such effectively connected dividends, although not subject to withholding tax, will be subject to U.S. federal income tax on a net income basis at the same graduated rates generally applicable to U.S. persons, subject to any applicable tax treaty providing otherwise. In addition to the income tax described above, dividends received by corporate non-U.S. holders that are effectively connected with a U.S. trade or business of the corporate non-U.S. holder may be subject to a branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable tax treaty).
A non-U.S. holder of our common stock may obtain a refund of any excess amounts withheld if the non-U.S. holder is eligible for a reduced rate of U.S. withholding tax and an appropriate claim for refund is timely filed with the IRS.
Gain on Disposition of Common Stock
Subject to the discussion of backup withholding and of FATCA, below, a non-U.S. holder generally will not be subject to U.S. federal income tax on any gain realized upon the sale or other disposition of our common stock unless:
•the gain is effectively connected with a U.S. trade or business of the non-U.S. holder and, if required by an applicable tax treaty, is attributable to a U.S. permanent establishment maintained by such non-U.S. holder;
•the non-U.S. holder is an individual who is present in the United States for a period or periods aggregating 183 days or more during the calendar year in which the sale or disposition occurs and certain other conditions are met; or
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•our common stock constitutes a “U.S. real property interest” by reason of our status as a U.S. real property holding corporation (a “USRPHC”) within the meaning of Section 897(c)(2) of the Code at any time within the shorter of the five-year period preceding the disposition or the non-U.S. holder’s holding period for our common stock.
Unless an applicable tax treaty provides otherwise, gain described in the first bullet point above will be recognized in an amount equal to the excess of the amount of cash and the fair market value of any other property received for the common stock over the non-U.S. holder’s basis in the common stock. Such gain or loss generally will be subject to U.S. federal income tax on a net income basis at the same graduated rates applicable to U.S. persons. In the case of a non-U.S. holder that is a foreign corporation, such gain may also be subject to a branch profits tax at a rate of 30% (or such lower rate as may be specified by an applicable tax treaty).
Gain described in the second bullet point above (which may be offset by U.S. source capital losses of such non-U.S. holder, provided that the non-U.S. holder has timely filed U.S. federal income tax returns with respect to such losses) will be subject to a flat 30% U.S. federal income tax (or such lower rate as may be specified by an applicable tax treaty).
With respect to the third bullet point above, we believe we are not currently, and we do not expect to become, a USRPHC. However, because the determination of whether we are a USRPHC depends on the fair market value of our U.S. real property relative to the fair market value of our other business assets and our interests in real property located outside the United States and because the definition of U.S. real property is not entirely clear, there can be no assurance that we are not a USRPHC now or will not become one in the future. Even if we were to become a USRPHC, however, as long as our common stock is “regularly traded” on an established securities market (as to which there can be no assurance), such common stock will be treated as U.S. real property interests only if the non-U.S. holder actually or constructively holds or held more than five percent of such regularly traded common stock at any time during the applicable period described in the third bullet point above.
Non-U.S. holders should consult a tax advisor regarding potentially applicable income tax treaties that may provide for different rules.
Backup Withholding and Information Reporting
Generally, we must report annually to the IRS the amount of dividends paid to each non-U.S. holder, the name and address of the recipient, and the amount, if any, of tax withheld with respect to those dividends. These information reporting requirements apply even if withholding was not required or was otherwise reduced or eliminated. This information also may be made available under a specific treaty or agreement with the tax authorities of the country in which the non-U.S. holder resides or is established. Payment of the proceeds of a sale of our common stock within the United States or through certain U.S. financial intermediaries is also subject to information reporting, and depending on the circumstances may be subject to backup withholding unless the non-U.S. holder, certifies that it is a non-U.S. holder or furnishes an IRS Form W-8.
Payments of dividends to a non-U.S. holder may be subject to backup withholding (at the applicable rate) unless the non-U.S. holder establishes an exemption, for example, by properly certifying its non-U.S. status on an IRS Form W-8BEN-E or W-8BEN or another appropriate version of IRS Form W-8. Notwithstanding the foregoing, backup withholding may apply if either we or our paying agent has actual knowledge, or reason to know, that the beneficial owner is a U.S. person that is not an exempt recipient.
U.S. information reporting and backup withholding generally will not apply to a payment of proceeds from a disposition of common stock where the transaction is effected outside the United States through a non-U.S. office of a non-U.S. broker. However, information reporting requirements, but generally not backup withholding, generally will apply to such a payment if the broker is (i) a U.S. person; (ii) a foreign person that derives 50% or more of its gross income for certain periods from the conduct of a trade or business in the United States; (iii) a controlled foreign corporation as defined in the Code; (iv) a foreign partnership with certain U.S. connections; or (v) a U.S. branch of a foreign bank or foreign insurance company or a “territory financial institution” (as specially defined) in each case meeting certain requirements, unless the broker has documentary evidence in its records that the holder is a non-U.S. holder and certain conditions are met or the holder otherwise establishes an exemption.
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Backup withholding is not an additional tax. Any amounts withheld under the backup withholding rules may be claimed as a refund or a credit against a non-U.S. holder’s U.S. federal income tax liability, provided that the required information is timely furnished to the IRS. Non-U.S. holders should consult their own tax advisors regarding the application of backup withholding in their particular circumstances and the availability of, and procedures for, obtaining an exemption from backup withholding.
Additional Withholding Tax Relating to Foreign Accounts
Withholding taxes may be imposed under Sections 1471 to 1474 of the Code, the Treasury Regulations promulgated thereunder and other official guidance (commonly referred to as “FATCA”) on certain types of payments made to non-U.S. financial institutions and certain other non-U.S. entities. Specifically, a 30% withholding tax may be imposed on dividends on, or gross proceeds from the sale or other disposition of, our common stock paid to “foreign financial institutions” or “non-financial foreign entities” (each as defined in the Code), unless those entities comply with certain requirements under the Code and applicable U.S. Treasury regulations, which requirements may be modified by an “intergovernmental agreement” entered into between the United States and an applicable foreign country.
Proposed U.S. Treasury Regulations have indefinitely suspended FATCA withholding on the gross proceeds from a sale or other disposition of our common stock and may be relied upon by taxpayers until final regulations are issued.
Prospective investors should consult their tax advisors regarding the potential application of withholding under FATCA to their investment in our common stock.
The foregoing discussion is only a summary of certain material U.S. federal income tax consequences of the acquisition, ownership and disposition of our common stock by non-U.S. holders. Each prospective investor should consult its own tax advisor with respect to the particular tax consequences of the acquisition, ownership and disposition of our common stock, including the effect of any U.S. federal, state, local and non-U.S. or other tax laws and any applicable income tax treaty.
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PLAN OF DISTRIBUTION
We are registering the resale of shares of our common stock covered by this prospectus by the Selling Stockholders from time to time after the date of this prospectus. We will not receive any of the proceeds of any such resale of shares of our common stock. The aggregate proceeds to the Selling Stockholders from the resales of shares or our common stock will be the purchase price of the shares less any discounts and commissions.
The Selling Stockholders or their pledgees, donees, transferees or any of their successors in interest selling shares received from a named Selling Stockholder as a gift, partnership distribution or other non-sale-related transfer after the date of this prospectus (some or all of whom may be Selling Stockholders), may sell some or all of the shares of common stock covered by this prospectus from time to time on any stock exchange or automated interdealer quotation system on which the securities are listed or quoted, in the over-the-counter market, in privately negotiated transactions or otherwise, at fixed prices that may be changed, at market prices prevailing at the time of sale, at prices related to prevailing market prices, at prices determined at the time of sale, or at prices otherwise negotiated. The Selling Stockholders may sell the shares by one or more of the following methods, without limitation:
•one or more underwritten offerings on a firm commitment or best efforts basis;
•block trades in which the broker or dealer so engaged will attempt to sell the shares as agent but may position and resell a portion of the block as principal to facilitate the transaction;
•crosses in which the same broker or dealer acts as an agent on both sides of the trades;
•purchases by a broker or dealer as principal and resale by the broker or dealer for its own account pursuant to this prospectus;
•an exchange distribution in accordance with the rules of any stock exchange on which the shares are listed;
•brokerage transactions and transactions in which the broker solicits purchases;
•privately negotiated transactions;
•short sales, either directly or with a broker-dealer or affiliate thereof;
•through the writing of options on the shares (including the issuance by the Selling Stockholder of derivative securities), whether or not the options are listed on an options exchange or otherwise;
•through loans or pledges of the shares to a broker-dealer or an affiliate thereof;
•by entering into transactions with third parties who may (or may cause others to) issue securities convertible or exchangeable into, or the return of which is derived in whole or in part from the value of, our common stock;
•through the distribution of the shares by any Selling Stockholder to its partners, members or stockholders;
•“at the market” to or through market makers or into an existing market for the securities;
•by pledge to secure debts and other obligations (including obligations associated with derivatives transactions);
•in other ways not involving market makers or established trading markets, including direct sales to purchasers or sales effected through agents;
•any combination of any of these methods of sale; and
•any other method permitted pursuant to applicable law.
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We do not know of any arrangements by the Selling Stockholders for the sale of any of these shares. Upon our notification by a Selling Stockholder that any material arrangement has been entered into with an underwriter or broker-dealer for the sale of shares through a block trade, special offering, exchange distribution, secondary distribution or a purchase by an underwriter, dealer or agent, we will file a post-effective amendment and supplement to this prospectus, as appropriate and required, pursuant to the Securities Act, disclosing certain material information, including the number of shares being offered, the name or names of any underwriters, dealers or agents, any public offering price, any underwriting discounts and other items constituting compensation to underwriters, dealers or agents.
For example, the Selling Stockholders may engage brokers and dealers and any brokers or dealers may arrange for other brokers or dealers to participate in effecting sales of the shares. These brokers, dealers or underwriters may act as principals or as agents of a Selling Stockholder. Broker-dealers may agree with a Selling Stockholder to sell a specified number of the shares at a stipulated price per security. If the broker-dealer is unable to sell shares acting as agent for a Selling Stockholder, it may purchase as principal any unsold shares at the stipulated price. Broker-dealers who acquire shares as principals may thereafter resell the shares from time to time in transactions on any stock exchange or automated interdealer quotation system on which the shares are then listed, at prices and on terms then prevailing at the time of sale, at prices related to the then-current market price, at prices determined at the time of sale, or at prices otherwise negotiated. Broker-dealers may use block transactions and sales to and through broker-dealers, including crosses and other transactions of the nature described above.
From time to time, one or more of the Selling Stockholders may pledge, hypothecate or grant a security interest in some or all of the shares owned by them. The pledgees, secured parties or persons to whom the shares have been hypothecated will, upon foreclosure in the event of default, be deemed to be Selling Stockholders. As and when a Selling Stockholder takes such actions, the number of shares offered under this prospectus on behalf of such Selling Stockholder will decrease. The plan of distribution for such Selling Stockholder’s shares will otherwise remain unchanged.
A Selling Stockholder may, from time to time, sell the shares short, and in those instances, this prospectus may be delivered in connection with the short sales and the shares offered under this prospectus may be used to cover short sales. A Selling Stockholder may enter into hedging transactions with broker-dealers and the broker-dealers may engage in short sales of the shares in the course of hedging the positions they assume with that Selling Stockholder, including, without limitation, in connection with distributions of the shares by those broker-dealers. A Selling Stockholder may enter into options or other transactions with broker-dealers that involve the delivery of the shares offered hereby to the broker-dealers, who may then resell or otherwise transfer those shares. A Selling Stockholder may also loan the shares offered hereby to a broker-dealer and the broker-dealer may sell the loaned shares pursuant to this prospectus.
A Selling Stockholder may enter into derivative transactions with third parties, or sell shares not covered by this prospectus to third parties in privately negotiated transactions. If the applicable prospectus supplement indicates, in connection with those derivatives, the third parties may sell shares covered by this prospectus and the applicable prospectus supplement, including in short sale transactions. If so, the third-party may use shares pledged by the Selling Stockholder or borrowed from the Selling Stockholder or others to settle those sales or to close out any related open borrowings of stock and may use shares received from the Selling Stockholder in settlement of those derivatives to close out any related open borrowings of stock. The third-party in such sale transactions will be an underwriter and, if not identified in this prospectus, will be identified in the applicable prospectus supplement (or a post-effective amendment to the registration statement of which this prospectus forms a part).
To the extent required under the Securities Act, the names of the Selling Stockholders, aggregate amount of Selling Stockholders’ shares being offered and the terms of the offering, the names of any agents, dealers or underwriters and any applicable compensation with respect to a particular offer will be set forth in an accompanying prospectus supplement. Any underwriters, dealers or agents participating in the distribution of the shares may receive compensation in the form of underwriting discounts, concessions, commissions or fees from a Selling Stockholder and/or purchasers of Selling Stockholders’ shares for whom they may act (which compensation as to a particular broker-dealer might be in excess of customary commissions). Pursuant to a FINRA requirement, the maximum commission or discount to be received by any FINRA member or independent broker-dealer may not be
162
greater than 8% of the gross proceeds received by the Selling Stockholders for the sale of any shares of common stock being offered by this prospectus and any applicable prospectus supplement.
The shares of common stock offered hereby were originally issued to the Selling Stockholders pursuant to an exemption from the registration requirements of the Securities Act. We agreed to register resales of such shares under the Securities Act and to keep the registration statement of which this prospectus is a part effective for a specified period of time. We have agreed to pay certain expenses in connection with certain resales of the shares registered pursuant to the registration statement of which this prospectus is a part, including the fees and expenses of one counsel retained by the Selling Stockholders. In addition, we have agreed to indemnify in certain circumstances certain of the Selling Stockholders against certain liabilities, including liabilities under the Securities Act. Certain of the Selling Stockholders have agreed to indemnify us in certain circumstances against certain liabilities, including liabilities under the Securities Act. We have also agreed to pay substantially all of the expenses incidental to the registration of resales of shares of our common stock, including the payment of federal securities law and state “blue sky” registration fees but excluding underwriting discounts and commissions relating to the sale of common stock. See “Certain Relationships and Related Party Transactions—Registration Rights Agreement and Stockholders Agreement.”
We cannot assure you that the Selling Stockholders will sell all or any portion of the shares offered hereby. Further, we cannot assure you that any such Selling Stockholder will not transfer, devise or gift the common stock by other means not described in this prospectus. In addition, any common stock covered by this prospectus that qualifies for sale under Rule 144 or Regulation D of the Securities Act may be sold under Rule 144 or Regulation D, as applicable, rather than under this prospectus. The common stock covered by this prospectus may also be sold to non-U.S. persons outside the United States in accordance with Regulation S under the Securities Act rather than under this prospectus. The common stock may be resold in some states only through registered or licensed brokers or dealers. In addition, in some states the common stock may not be resold unless it has been registered or qualified for resale or an exemption from registration or qualification is available and complied with.
163
LEGAL MATTERS
The validity of the shares of common stock offered by this prospectus will be passed upon for us by Kirkland & Ellis LLP, Houston, TX.
EXPERTS
The consolidated financial statements of Talen Energy Corporation (Successor) as of December 31, 2023 and for the period from May 18, 2023 through December 31, 2023 included in this prospectus have been so included in reliance on the report (which contains an explanatory paragraph relating to the Company’s emergence from bankruptcy and adoption of fresh start accounting on May 17, 2023 as described in Note 3 in Notes to the Annual Financial Statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
The consolidated financial statements of Talen Energy Supply, LLC (Predecessor) as of December 31, 2022, and for the period from January 1, 2023 through May 17, 2023 and for each of the two years in the period ended December 31, 2022 included in this prospectus have been so included in reliance on the report (which contains an explanatory paragraph relating to the Company’s petition on May 9, 2022 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code, and emergence from bankruptcy and adoption of fresh start accounting on May 17, 2023 as described in Note 3 in Notes to the Annual Financial Statements) of PricewaterhouseCoopers LLP, an independent registered public accounting firm, given on the authority of said firm as experts in auditing and accounting.
WHERE YOU CAN FIND ADDITIONAL INFORMATION
We have filed with the SEC a registration statement on Form S-1, including exhibits and schedules, under the Securities Act, with respect to the shares of common stock being offered by this prospectus. This prospectus, which constitutes part of the registration statement, does not contain all of the information in the registration statement and its exhibits. For further information with respect to us and the common stock offered by this prospectus, we refer you to the registration statement and its exhibits. Statements contained in this prospectus as to the contents of any contract or any other document referred to are not necessarily complete, and in each instance, we refer you to the copy of the contract or other document filed as an exhibit to the registration statement. Each of these statements is qualified in all respects by this reference.
You can read our SEC filings, including the registration statement, over the internet at the SEC’s website at www.sec.gov.
Upon the effectiveness of the registration statement of which this prospectus forms a part, we will be subject to the information reporting requirements of the Exchange Act, and we will file reports, proxy statements and other information with the SEC. These reports, proxy statements and other information will be available for inspection and copying at the website of the SEC referred to above. We also maintain a website at www.talenenergy.com, at which, following the effectiveness of the registration statement of which this prospectus forms a part, you may access these materials free of charge as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. Information contained on or accessible through our website is not a part of this prospectus and the inclusion of our website address in this prospectus is an inactive textual reference only.
164
TALEN ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Unaudited Financial Statements for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Condensed Consolidated Statements of Operations for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Condensed Consolidated Statements of Comprehensive Income (Loss) for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Condensed Consolidated Balance Sheets for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Condensed Consolidated Statements of Cash Flows for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Condensed Consolidated Statements of Equity for the Three-month Periods Ending March 31, 2024 (Successor) and March 31, 2023 (Predecessor) | |||||
Audited Financial Statements for the Period from January 1, 2023 through May 17, 2023 (Predecessor), for the Period from May 18, 2023 through December 31, 2023 (Successor), and for the Years Ended December 31, 2022 and 2021 (Predecessor) | |||||
Consolidated Statements of Operations for the Period from January 1, 2023 through May 17, 2023 (Predecessor), for the Period from May 18, 2023 through December 31, 2023 (Successor), and the Two Years Ended December 31, 2022 and 2021 (Predecessor) | |||||
Consolidated Statements of Comprehensive Income for the Period from January 1, 2023 through May 17, 2023 (Predecessor), for the Period from May 18, 2023 through December 31, 2023 (Successor), and the Two Years Ended December 31, 2022 and 2021 (Predecessor) | |||||
Consolidated Statements of Cash Flows for the Period from January 1, 2023 through May 17, 2023 (Predecessor), for the Period from May 18, 2023 through December 31, 2023 (Successor), and the Two Years Ended December 31, 2022 and 2021 (Predecessor) | |||||
Consolidated Statements of Equity for the Period from January 1, 2023 through May 17, 2023 (Predecessor), for the Period from May 18, 2023 through December 31, 2023 (Successor), and the Year Ended December 31, 2022 (Predecessor) | |||||
F-1
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars, except share data) | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 45 | $ | 66 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Energy and other revenues | 572 | 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), net | 75 | 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), net | 23 | 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 interest | 25 | (2) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 294 | $ | 48 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Per Common Share (Successor) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | 5.00 | N/A | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | $ | 4.84 | N/A | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 58,807 | N/A | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 60,716 | N/A | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-2
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||
Net Income (Loss) | $ | 319 | $ | 46 | ||||||||||||||||||||||||||||||||||||||||
| Other Comprehensive Income (Loss) | ||||||||||||||||||||||||||||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | — | 10 | ||||||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | — | (4) | ||||||||||||||||||||||||||||||||||||||||||
Gains (losses) arising during the period, net of tax | — | 6 | ||||||||||||||||||||||||||||||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net | (7) | 6 | ||||||||||||||||||||||||||||||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | — | (1) | ||||||||||||||||||||||||||||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net | — | 1 | ||||||||||||||||||||||||||||||||||||||||||
| Income tax (benefit) expense | 3 | (3) | ||||||||||||||||||||||||||||||||||||||||||
Reclassifications from AOCI, net of tax | (4) | 3 | ||||||||||||||||||||||||||||||||||||||||||
Total Other Comprehensive Income (Loss) | (4) | 9 | ||||||||||||||||||||||||||||||||||||||||||
Comprehensive Income (Loss) | 315 | 55 | ||||||||||||||||||||||||||||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | 25 | (2) | ||||||||||||||||||||||||||||||||||||||||||
Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 290 | $ | 57 | ||||||||||||||||||||||||||||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-3
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| Successor | |||||||||||||||||
| March 31, | December 31, | ||||||||||||||||
| (Millions of Dollars, except share data) | 2024 | 2023 | |||||||||||||||
| Assets | |||||||||||||||||
| Cash and cash equivalents | $ | 597 | $ | 400 | |||||||||||||
| Restricted cash and cash equivalents (Note 16) | 483 | 501 | |||||||||||||||
| Accounts receivable, net (Note 4) | 126 | 137 | |||||||||||||||
| Inventory, net (Note 6) | 279 | 375 | |||||||||||||||
| Derivative instruments (Notes 3 and 12) | 14 | 89 | |||||||||||||||
| Assets held for sale (Note 17) | 215 | — | |||||||||||||||
| Other current assets (Note 17) | 383 | 52 | |||||||||||||||
Total current assets | 2,097 | 1,554 | |||||||||||||||
| Property, plant and equipment, net (Note 8) | 3,359 | 3,839 | |||||||||||||||
| Nuclear decommissioning trust funds (Notes 7 and 12) | 1,642 | 1,575 | |||||||||||||||
| Derivative instruments (Notes 3 and 12) | 4 | 6 | |||||||||||||||
| Other noncurrent assets | 163 | 147 | |||||||||||||||
Total Assets | $ | 7,265 | $ | 7,121 | |||||||||||||
| Liabilities and Equity | |||||||||||||||||
| Long-term debt, due within one year (Notes 11 and 12) | 9 | 9 | |||||||||||||||
| Accrued interest | 61 | 32 | |||||||||||||||
| Accounts payable and other accrued liabilities | 177 | 344 | |||||||||||||||
| Derivative instruments (Notes 3 and 12) | 98 | 32 | |||||||||||||||
| Liabilities held for sale (Note 17) | 17 | — | |||||||||||||||
| Other current liabilities | 98 | 69 | |||||||||||||||
Total current liabilities | 460 | 486 | |||||||||||||||
| Long-term debt (Notes 11 and 12) | 2,619 | 2,811 | |||||||||||||||
| Derivative instruments (Notes 3 and 12) | 4 | 11 | |||||||||||||||
| Postretirement benefit obligations (Note 13) | 367 | 368 | |||||||||||||||
| Asset retirement obligations and accrued environmental costs (Note 9) | 471 | 469 | |||||||||||||||
| Deferred income taxes (Note 5) | 460 | 407 | |||||||||||||||
| Other noncurrent liabilities | 118 | 35 | |||||||||||||||
Total Liabilities | 4,499 | 4,587 | |||||||||||||||
| Commitments and Contingencies (Note 10) | |||||||||||||||||
| Stockholders’ Equity (Successor) | |||||||||||||||||
Common stock ($0.001 par value, 350,000,000 shares authorized) (a) (b) | — | — | |||||||||||||||
| Treasury stock | (39) | — | |||||||||||||||
| Additional paid-in capital | 2,339 | 2,346 | |||||||||||||||
| Accumulated retained earnings (deficit) | 428 | 134 | |||||||||||||||
| Accumulated other comprehensive income (loss) | (27) | (23) | |||||||||||||||
Total Stockholders’ Equity (Successor) | 2,701 | 2,457 | |||||||||||||||
Noncontrolling interests | 65 | 77 | |||||||||||||||
Total Equity | 2,766 | 2,534 | |||||||||||||||
Total Liabilities and Equity | $ | 7,265 | $ | 7,121 | |||||||||||||
__________________
(a)Shares as of March 31, 2024 (Successor) were: (i) 59,028,843 issued; (ii) 58,535,843 outstanding; and (iii) 493,000 held as treasury stock.
(b)As of December 31, 2023 (Successor): 59,028,843 shares issued and outstanding.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-4
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| Successor | Predecessor | ||||||||||||||||||||||
| (Millions of Dollars) | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | |||||||||||||||||||||
| Operating Activities | |||||||||||||||||||||||
| Net income (loss) | $ | 319 | $ | 46 | |||||||||||||||||||
| Non-cash reconciliation adjustments: | |||||||||||||||||||||||
| Unrealized (gains) losses on derivative instruments | 128 | (28) | |||||||||||||||||||||
| (Gain) loss on Cumulus Data Center Campus sale | (324) | — | |||||||||||||||||||||
| Nuclear fuel amortization | 35 | 24 | |||||||||||||||||||||
| Depreciation, amortization and accretion | 74 | 138 | |||||||||||||||||||||
| Impairments | — | 365 | |||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) | (64) | (37) | |||||||||||||||||||||
| Deferred income taxes | 57 | — | |||||||||||||||||||||
| Other | (42) | (22) | |||||||||||||||||||||
| Changes in assets and liabilities: | |||||||||||||||||||||||
| Accounts receivable, net | 11 | 205 | |||||||||||||||||||||
| Inventory, net | 89 | (6) | |||||||||||||||||||||
| Other assets | (1) | 103 | |||||||||||||||||||||
| Accounts payable and accrued liabilities | (154) | (72) | |||||||||||||||||||||
| Accrued interest | 29 | 13 | |||||||||||||||||||||
| Other liabilities | 16 | 15 | |||||||||||||||||||||
Net cash provided by (used in) operating activities | 173 | 744 | |||||||||||||||||||||
| Investing Activities | |||||||||||||||||||||||
| Property, plant and equipment expenditures | (25) | (84) | |||||||||||||||||||||
| Nuclear fuel expenditures | (41) | (46) | |||||||||||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds | 553 | 598 | |||||||||||||||||||||
| Nuclear decommissioning trust funds investment purchases | (564) | (608) | |||||||||||||||||||||
| Proceeds from Cumulus Data Center Campus Sale | 339 | — | |||||||||||||||||||||
| Proceeds from the sale of non-core assets | 1 | 29 | |||||||||||||||||||||
| Other investing activities | 2 | (7) | |||||||||||||||||||||
Net cash provided by (used in) investing activities | 265 | (118) | |||||||||||||||||||||
F-5
| Successor | Predecessor | ||||||||||||||||||||||
| (Millions of Dollars) | Three Months Ended March 31, 2024 | Three Months Ended March 31, 2023 | |||||||||||||||||||||
| Financing Activities | |||||||||||||||||||||||
| LMBE-MC TLB payments | — | (7) | |||||||||||||||||||||
| Cumulus Digital TLF payments | (182) | — | |||||||||||||||||||||
| Share repurchases | (30) | — | |||||||||||||||||||||
| Repurchase of noncontrolling interest | (39) | — | |||||||||||||||||||||
| Derivatives with financing elements | — | (20) | |||||||||||||||||||||
| Other | (8) | (1) | |||||||||||||||||||||
Net cash provided by (used in) financing activities | (259) | (28) | |||||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents | 179 | 598 | |||||||||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | 901 | 988 | |||||||||||||||||||||
End of period cash and cash equivalents and restricted cash and cash equivalents | $ | 1,080 | $ | 1,586 | |||||||||||||||||||
See Note 16 for supplemental cash flow information.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-6
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Treasury stock | Member’s Equity | Non controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||||
December 31, 2022 (Predecessor) | — | $ | — | $ | — | $ | — | $ | — | $ | (573) | $ | 91 | $ | (482) | |||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | 48 | (2) | 46 | ||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | 9 | — | 9 | ||||||||||||||||||||||||||||||||||||||||||
Non-cash contributions (b) | — | — | — | — | — | — | 38 | 38 | ||||||||||||||||||||||||||||||||||||||||||
Non-cash distributions, net (c) | — | — | — | — | — | — | (2) | (2) | ||||||||||||||||||||||||||||||||||||||||||
March 31, 2023 (Predecessor) | — | $ | — | $ | — | $ | — | $ | — | $ | (516) | $ | 125 | $ | (391) | |||||||||||||||||||||||||||||||||||
December 31, 2023 (Successor) | 59,029 | $ | 2,346 | $ | 134 | $ | (23) | $ | — | $ | — | $ | 77 | $ | 2,534 | |||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | 294 | — | — | — | 25 | 319 | ||||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | (4) | — | — | — | (4) | ||||||||||||||||||||||||||||||||||||||||||
| Share repurchases | (493) | — | — | — | (39) | — | — | (39) | ||||||||||||||||||||||||||||||||||||||||||
Purchase of noncontrolling interests (d) | — | (15) | — | — | — | — | (24) | (39) | ||||||||||||||||||||||||||||||||||||||||||
Cash distribution (e) | — | — | — | — | — | — | (1) | (1) | ||||||||||||||||||||||||||||||||||||||||||
Non-cash distributions (c) | — | — | — | — | — | — | (12) | (12) | ||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | 8 | — | — | — | — | — | 8 | ||||||||||||||||||||||||||||||||||||||||||
March 31, 2024 (Successor) | 58,536 | $ | 2,339 | $ | 428 | $ | (27) | $ | (39) | $ | — | $ | 65 | $ | 2,766 | |||||||||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Relates to contributions of cryptocurrency mining machines by TeraWulf to Nautilus.
(c)Relates primarily to distributions of cryptocurrency mining machines or Bitcoin to TeraWulf.
(d)TES acquisition of remaining noncontrolling interests in Cumulus Digital Holdings. See Note 17 for additional information.
(e)Distribution to noncontrolling interest owners of Cumulus Digital Holdings.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-7
TALEN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO THE INTERIM FINANCIAL STATEMENTS
Capitalized terms and abbreviations appearing in these Notes to the Interim Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted. References to the “Annual Financial Statements” are to the audited Talen Energy Corporation 2023 Annual Financial Statements and Notes thereto.
“TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. 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 to TES and its consolidated subsidiaries, unless the context clearly indicates otherwise. See “Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition” in Note 2 for information on an accounting reverse acquisition that occurred at Emergence.
This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary.
1. Organization and Operations
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, Texas, 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. As of March 31, 2024 (Successor), our generation capacity was 12,374 MW (summer rating). Talen is headquartered in Houston, Texas. See Note 17 for information on the recent sale of our generation assets in Texas.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Interim Financial Statements, which are prepared in accordance with GAAP, include: (i) the accounts of all controlled subsidiaries; (ii) elimination adjustments for intercompany transactions between controlled subsidiaries; (iii) any undivided interests in jointly owned facilities consolidated on a proportionate basis; and (iv) all adjustments considered necessary for a fair presentation of the information set forth. All adjustments are of a normal recurring nature except as otherwise disclosed. Certain information and note disclosures have been condensed or omitted from the Interim Financial Statements in accordance with GAAP. The Consolidated Balance Sheet as of December 31, 2023 (Successor) is derived from the 2023 Consolidated Balance Sheet in the Annual Financial Statements. The Interim Financial Statements and Notes thereto should be read in conjunction with the Annual Financial Statements and Notes thereto. The results of operations presented in our Interim Financial Statements are not necessarily indicative of the results to be expected for the full year or for other future periods because interim period results can be disproportionately influenced by operational developments, seasonality, and other various factors.
Assets Held for Sale. In March 2024, the Company entered into an agreement to sell its Texas generation assets located within the ERCOT market. The assets and liabilities associated with the sale are presented as ‘held for sale’ on the Consolidated Balance Sheet as of March 31, 2024 (Successor). The sale closed on May 1, 2024. See Note 17 for additional information.
F-8
Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition. In May 2022, TES and 71 of its subsidiaries filed voluntary petitions seeking relief under Chapter 11 of the U.S. Bankruptcy Code. In December 2022, TEC became an additional debtor in the Restructuring in order to facilitate certain transactions contemplated by the Plan of Reorganization. The Plan of Reorganization was approved by the requisite parties in November 2022, was confirmed by the Bankruptcy Court in December 2022, and was consummated and became effective in May 2023, when TEC, TES and the other debtors emerged from the Restructuring.
Upon commencement of the Restructuring, TES was deconsolidated from TEC for financial reporting purposes because TEC no longer controlled TES. TEC regained control of TES at Emergence, which resulted in TEC’s reconsolidation of TES. The combination was accounted for as a reverse acquisition in which TEC was the legal acquirer and TES was the accounting acquirer. Accordingly, our Interim Financial Statements are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer.
After Emergence, TES applied fresh start accounting, which resulted in a new basis of accounting as the Company became a new financial reporting entity. As a result of the application of fresh start accounting and the implementation of the Plan of Reorganization, our financial position and results of operations beginning after Emergence are not comparable to our financial position or results of operations prior to that date. The financial results are presented for: (i) the Predecessor period from January 1 through March 31, 2023; and (ii) the Successor period from January 1 through March 31, 2024. The Interim Financial Statements and Notes thereto have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
See Notes 2, 3, and 4 in Notes to the Annual Financial Statements for additional information on the reverse acquisition, the legal structure of the Restructuring transactions, and the impacts of fresh start accounting.
Summary of Significant Accounting Policies
Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity or cash flows.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Treasury Stock. Share repurchases are accounted for under the cost method, which recognizes the entire cost of the acquired stock, including transaction costs, as a reduction in additional paid-in-capital and are presented as “Treasury stock” on the Consolidated Balance Sheets. Share repurchases made by third party brokers on our behalf are recognized on a trade date basis when we are contractually obligated to pay the broker for their purchase costs.
Nuclear PTCs. The Nuclear PTC program provides qualified nuclear power generation facilities with transferable credits for electricity produced and sold to an unrelated party during each tax year. These credits, which are accounted for by analogy to income-based grants under international accounting standards for government grants and disclosure of government assistance, are recognized when there is reasonable assurance that the Company will comply with the applicable conditions and that the credit will be received, which is generally over the period of production. As the credits that are generated each tax year are based on annual gross receipts and production volumes, the measurement of the credit value is estimated at each period until the final value can be determined at the end of the year, which may be different than the estimated amount. The credit value includes a five-times multiplier (up to $15 per MWh) for meeting prevailing wage requirements. Accordingly, Nuclear PTCs are recognized based on production volumes generated during the period and measured at the credit value for the tax year. See Note 4 for amounts recognized, which are presented as “Energy and other revenues” on the Consolidated Statements of Operations and “Other current assets” on the Consolidated Balance Sheets. Credits that are utilized to reduce federal income taxes payable are presented as a reduction of “Other current liabilities” on the Consolidated Balance Sheets. There have been no transfers of Nuclear PTCs to third parties during the first quarter 2024. Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value received.
F-9
See Note 2 in Notes to the Annual Financial Statements for additional information on significant accounting policies.
3. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk and interest rate risk. The hedging and optimization strategies deployed by our commercial organization manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors (including the risk committee) and management have established procedures to monitor, measure and manage hedging activities and credit risk in accordance with the risk policy.
Key risk control activities, which are designed to ensure compliance with the risk policy include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power generation markets provides uncertainty in the future performance and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: seasonal changes in demand; weather conditions; available regional load-serving supply; regional transportation and (or) transmission availability; market liquidity; and federal, regional and state regulations.Within the parameters of our risk policy, we generally utilize conventional first lien, exchange-traded and over-the-counter traded derivative instruments, and in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives as of March 31, 2024 (Successor) range in maturity through 2026. The net notional volumes of open commodity derivatives were:
| Successor | |||||||||||||||||
March 31, 2024 (a) | December 31, 2023 (a) | ||||||||||||||||
| Power (MWh) | (28,145,612) | (27,557,871) | |||||||||||||||
| Natural gas (MMBtu) | 45,959,800 | 8,314,060 | |||||||||||||||
| Emission allowances (tons) | — | 500,000 | |||||||||||||||
__________________
(a)The volumes may be less than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
F-10
Open interest rate derivatives as of March 31, 2024 (Successor) range in maturity dates through 2026. The net notional volumes of open interest rate derivatives were:
| Successor | |||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||
Interest rate (in millions) (a) | $ | 290 | $ | 290 | |||||||
__________________
(a)Value as of March 31, 2024 (Successor) and December 31, 2023 (Successor) relates to interest rate derivatives for the TLB indebtedness.
Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, derivative instruments and accounts receivable. The maximum amount of credit exposure associated with financial assets is equal to the carrying value. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default and executing master netting arrangements which permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, letters of credit and credit insurance may be employed to mitigate credit risk.
Cash and cash equivalents are placed in depository accounts or high-quality short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of March 31, 2024 (Successor) and December 31, 2023 (Successor).
As of March 31, 2024 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, letters of credit and any allowances for doubtful collections, was $299 million and its credit exposure net of such effects was $66 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements are subject to applicable market controls, the ten largest single net credit exposures account for approximately 68% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, letters of credit or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in our credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of March 31, 2024 (Successor) and December 31, 2023 (Successor).
F-11
Derivative Instrument Presentation
Balance Sheet Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
| Successor | |||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | ||||||||||||||||||||
Commodity contracts (a) | $ | 15 | $ | 98 | $ | 88 | $ | 32 | |||||||||||||||
| Interest rate contracts | 2 | — | 1 | — | |||||||||||||||||||
Total current derivative instruments | 17 | 98 | 89 | 32 | |||||||||||||||||||
| Commodity contracts | 4 | 3 | 6 | 5 | |||||||||||||||||||
| Interest rate contracts | — | 1 | — | 6 | |||||||||||||||||||
Total non-current derivative instruments | $ | 4 | $ | 4 | $ | 6 | $ | 11 | |||||||||||||||
__________________
(a)As of March 31, 2024 (Successor), commodity contracts assets include $3 million presented as “Assets held for sale” on the Consolidated Balance Sheets. See Note 17 for additional information on the ERCOT divestiture.
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. See Note 12 for additional information on fair value.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of March 31, 2024 (Successor) and December 31, 2023 (Successor).
The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:
| Gross Derivative Instruments | Eligible for Offset | Net Derivative Instruments | Collateral (Posted) Received | Net Amounts | |||||||||||||||||||||||||||||||
| March 31, 2024 (Successor) | |||||||||||||||||||||||||||||||||||
Assets (a) | $ | 172 | $ | (151) | $ | 21 | $ | — | $ | 21 | |||||||||||||||||||||||||
| Liabilities | 305 | (151) | 154 | (52) | 102 | ||||||||||||||||||||||||||||||
| December 31, 2023 (Successor) | |||||||||||||||||||||||||||||||||||
| Assets | 295 | (198) | 97 | (2) | 95 | ||||||||||||||||||||||||||||||
| Liabilities | 300 | (198) | 102 | (59) | 43 | ||||||||||||||||||||||||||||||
__________________
(a)Commodity contracts assets include $3 million of ERCOT positions that are presented as “Assets held for sale” on the Consolidated Balance Sheets. See Note 17 for additional information on the ERCOT divestiture.
F-12
Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||
| Realized gain (loss) on commodity contracts | ||||||||||||||||||||||||||||||||
Energy revenues (a) | $ | 158 | $ | 579 | ||||||||||||||||||||||||||||
Fuel and energy purchases (a) | 1 | (21) | ||||||||||||||||||||||||||||||
| Unrealized gain (loss) on commodity contracts | ||||||||||||||||||||||||||||||||
Operating revenues (b) | (108) | 145 | ||||||||||||||||||||||||||||||
Energy expenses (b) | (27) | (114) | ||||||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | ||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | 7 | — | ||||||||||||||||||||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.
4. Revenue
The disaggregation of our operating revenues for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 45 | $ | 66 | ||||||||||||||||||||||||||||||||||||||||||||||
| Electricity sales and ancillary services, ISO/RTO | 265 | 196 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Physical electricity sales, bilateral contracts, other | 64 | 49 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Other revenue from customers | 42 | 9 | ||||||||||||||||||||||||||||||||||||||||||||||||
Total revenue from contracts with customers | 416 | 320 | ||||||||||||||||||||||||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | 57 | 753 | ||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear PTC and other revenue (a) | 36 | — | ||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 509 | $ | 1,073 | ||||||||||||||||||||||||||||||||||||||||||||||
__________________
(a)See Note 5 for the tax impact of the Nuclear PTC.
Accounts Receivable
“Accounts receivable, net” presented on the Consolidated Balance Sheets were:
| Successor | |||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||
| Customer accounts receivable | $ | 45 | $ | 52 | |||||||
| Other accounts receivable | 81 | 85 | |||||||||
Accounts receivable, net | $ | 126 | $ | 137 | |||||||
During the three months ended March 31, 2024 (Successor) and 2023 (Predecessor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 3 for additional information on Talen's credit risk on the carrying value of its receivables.
F-13
Deferred Revenue
Deferred revenues that were: (i) presented as a liability on the Consolidated Balance Sheets as of March 31, 2024 (Successor) and December 31, 2023 (Successor); or (ii) recognized as revenue on the Consolidated Statements of Operations were not material for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor).
Future Performance Obligations
In the normal course of business, Talen has future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements.
As of March 31, 2024 (Successor), the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
2024 (a) | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||||||||
| Expected capacity revenues | $ | 146 | $ | 84 | $ | 3 | $ | 3 | $ | 1 | |||||||||||||||||||||||||
__________________
(a)For the period from April 1, 2024 through December 31, 2024.
The PJM capacity auctions for the 2025/2026 PJM Capacity Year and for any years thereafter have not yet been held. See Note 10 for additional information on the PJM RPM and auctions.
5. Income Taxes
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | $ | 388 | $ | 60 | ||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (69) | (14) | ||||||||||||||||||||||||||||||||||||
Effective tax rate | 17.8 | % | 23.3% | |||||||||||||||||||||||||||||||||||
| Federal income tax statutory tax rate | 21% | 21% | ||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | $ | (82) | $ | (13) | ||||||||||||||||||||||||||||||||||
| Income tax increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||||
| State income taxes, net of federal benefit | (11) | (2) | ||||||||||||||||||||||||||||||||||||
| Change in valuation allowance | 20 | 13 | ||||||||||||||||||||||||||||||||||||
| Production tax credits | 8 | — | ||||||||||||||||||||||||||||||||||||
| Other permanent differences | 7 | — | ||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust taxes | (11) | (9) | ||||||||||||||||||||||||||||||||||||
| Transaction costs | — | (5) | ||||||||||||||||||||||||||||||||||||
| Reorganization adjustments | — | 2 | ||||||||||||||||||||||||||||||||||||
Income tax benefit (expense) | $ | (69) | $ | (14) | ||||||||||||||||||||||||||||||||||
The effective tax rate for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor) differed from the statutory rate primarily due to the change in valuation allowance, additional 20% trust tax on NDT income, and permanent differences including production tax credits.
F-14
6. Inventory
| Successor | ||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||
| Coal | $ | 131 | $ | 152 | ||||||||||
| Oil products | 67 | 75 | ||||||||||||
Fuel inventory for electric generation | 198 | 227 | ||||||||||||
| Materials and supplies, net | 72 | 72 | ||||||||||||
| Environmental products | 9 | 76 | ||||||||||||
Inventory, net (a) | $ | 279 | $ | 375 | ||||||||||
__________________
(a)As of March 31, 2024 (Successor), $7 million of inventory is presented as “Assets held for sale” on the Consolidated Balance Sheet.
Inventory net realizable value and obsolescence charges on coal and fuel oil inventories are presented as "Other operating income (expense), net" on the Consolidated Statements of Operations. Such non-cash charges were non-material for the three months ended March 31, 2024 (Successor) and were $13 million for the three months ended March 31, 2023 (Predecessor).
Inventory net realizable value and obsolescence charges on materials and supplies inventories are presented as "Operation and maintenance" on the Consolidated Statements of Operations. Such non-cash charges were non-material for the three months ended March 31, 2024 (Successor) and were $11 million for the three months ended March 31, 2023 (Predecessor).
Of the above charges incurred during the three months ended March 31, 2023 (Predecessor), $18 million related to Brandon Shores inventories. See Note 8 for additional information on the Brandon Shores recoverability assessment.
7. Nuclear Decommissioning Trust Funds
| Successor | ||||||||||||||||||||||||||||||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | |||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 15 | $ | — | $ | — | $ | 15 | $ | 9 | $ | — | $ | — | $ | 9 | ||||||||||||||||||||||||||||||||||
| Equity securities | 498 | 618 | 55 | 1,061 | 491 | 575 | 53 | 1,013 | ||||||||||||||||||||||||||||||||||||||||||
| Debt securities | 573 | 4 | 3 | 574 | 570 | 10 | 1 | 579 | ||||||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | (8) | — | — | (8) | (26) | — | — | (26) | ||||||||||||||||||||||||||||||||||||||||||
NDT funds | $ | 1,078 | $ | 622 | $ | 58 | $ | 1,642 | $ | 1,044 | $ | 585 | $ | 54 | $ | 1,575 | ||||||||||||||||||||||||||||||||||
See Note 12 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of March 31, 2024 (Successor) and December 31, 2023 (Successor).
As of March 31, 2024 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate related fair value of available-for-sale debt securities with unrealized losses as of March 31, 2024 (Successor) were:
| Fair Value | Unrealized Losses | ||||||||||
| U.S. Government debt securities | $ | 204 | $ | (3) | |||||||
F-15
There were securities in an unrealized loss position for a duration of one year or longer. As of March 31, 2024 (Successor), the aggregate fair value of these securities was $39 million, and the unrealized losses were non-material.
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| Successor | ||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||
| Maturities within one year | $ | 48 | $ | 105 | ||||||||||
| Maturities within two to five years | 217 | 194 | ||||||||||||
| Maturities thereafter | 309 | 280 | ||||||||||||
Debt securities, fair value | $ | 574 | $ | 579 | ||||||||||
The sales proceeds, gains, and losses for available-for-sale debt securities for the three months ended March 31 were:
| Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| 2024 | 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Sales proceeds of nuclear decommissioning trust funds investments (a) | $ | 499 | $ | 596 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross realized gains | 3 | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross realized losses | (3) | (10) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
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(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the trust.
8. Property, Plant and Equipment
| Successor | ||||||||||||||||||||||||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (years) | Gross Value | Accumulated Provision | Carrying Value | Gross Value | Accumulated Provision | Carrying Value | ||||||||||||||||||||||||||||||||||||||
| Electric generation | 3-27 | $ | 2,998 | $ | (152) | $ | 2,846 | $ | 3,178 | $ | (109) | $ | 3,069 | |||||||||||||||||||||||||||||||
| Nuclear fuel | 1-6 | 314 | (79) | 235 | 228 | (55) | 173 | |||||||||||||||||||||||||||||||||||||
| Other property and equipment | 1-20 | 141 | (23) | 118 | 357 | (21) | 336 | |||||||||||||||||||||||||||||||||||||
| Intangible assets | 2-26 | 69 | (14) | 55 | 1 | — | 1 | |||||||||||||||||||||||||||||||||||||
| Capitalized software | 1-5 | 6 | (2) | 4 | 6 | (1) | 5 | |||||||||||||||||||||||||||||||||||||
| Construction work in progress | 101 | — | 101 | 255 | — | 255 | ||||||||||||||||||||||||||||||||||||||
Property, plant and equipment, net (a) | $ | 3,629 | $ | (270) | $ | 3,359 | $ | 4,025 | $ | (186) | $ | 3,839 | ||||||||||||||||||||||||||||||||
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(a)As of March 31, 2024, $202 million of property, plant and equipment, net is presented as “Assets held for sale” on the Consolidated Balance Sheet. See Note 17 for additional information on the ERCOT divestiture.
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The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||||||||
Depreciation expense (a) | $ | 60 | $ | 115 | ||||||||||||||||||||||||||||||||||
Amortization expense (b) | 2 | 3 | ||||||||||||||||||||||||||||||||||||
Accretion expense (c) | 13 | 15 | ||||||||||||||||||||||||||||||||||||
| Other | — | (1) | ||||||||||||||||||||||||||||||||||||
Depreciation, amortization, and accretion | $ | 75 | $ | 132 | ||||||||||||||||||||||||||||||||||
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(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 9 for additional information.
The cost of nuclear fuel is presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Reliability Impact Assessments
Brandon Shores Reliability Impact Assessment. In April 2023, Talen notified PJM that it intends to deactivate electric generation at Brandon Shores on June 1, 2025. In June 2023, PJM notified Brandon Shores that its generation units were needed for reliability. 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 units 1 and 2 at the generation facility. The filed rate schedule sets forth the terms, conditions, and cost-based rates under which Brandon Shores will agree to continue to operate the generation units for reliability purposes from June 1, 2025 through December 31, 2028. No assurance can be provided when, if at all, FERC will approve the filing.
H.A. Wagner Reliability Impact Assessment. In October 2023, Talen notified PJM that it intends to deactivate electric generation at H.A. Wagner on June 1, 2025. In January 2024, PJM notified H.A. Wagner that its generation units were needed for 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 units 3 and 4 at the generation facility. The filed rate schedule sets forth the terms, conditions, and cost-based rates under which Wagner will agree to continue to operate the generation units for reliability purposes from June 1, 2025 through December 31, 2028. No assurance can be provided when, if at all, FERC will approve the filing.
2023 Impairment
Brandon Shores Asset Group. Brandon Shores is required by contract and permit to cease coal combustion by December 31, 2025. In the first quarter 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group.
The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its property, plant and equipment to its estimated fair value. Accordingly, for the three months ended March 31, 2023 (Predecessor), a $361 million non-cash pre-tax impairment charge on the asset group’s undepreciated property, plant and equipment is presented as “Impairments” on the Consolidated Statements of Operations.
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9. Asset Retirement Obligations and Accrued Environmental Costs
| Successor | ||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||
| Asset retirement obligations | $ | 474 | $ | 464 | ||||||||||
| Accrued environmental costs | 23 | 23 | ||||||||||||
Total asset retirement obligations and accrued environmental costs | 497 | 487 | ||||||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | 26 | 18 | ||||||||||||
Asset retirement obligations and accrued environmental costs due after one year | $ | 471 | $ | 469 | ||||||||||
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(a)Presented as “Other current liabilities” on the Consolidated Statements of Operations.
Asset Retirement Obligations
The changes of the ARO carrying value during the three months ended were:
| Successor | |||||||||||
| March 31, 2024 | |||||||||||
Carrying value, beginning of period | $ | 464 | |||||||||
| Obligations settled | (3) | ||||||||||
| Accretion expense | 13 | ||||||||||
Carrying value, end of period | $ | 474 | |||||||||
Supplemental information for the ARO:
| Successor | |||||||||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||||||||
| Supplemental Information | |||||||||||||||||
Nuclear (a) | $ | 221 | $ | 214 | |||||||||||||
Non-Nuclear (b) | 253 | 250 | |||||||||||||||
Carrying value | $ | 474 | $ | 464 | |||||||||||||
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(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning.
(b)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.
See Note 12 for additional information on Susquehanna’s NDT.
See “Talen Montana Financial Assurance” in Note 10 for additional information on Talen Montana’s requirement to provide financial assurance related to certain environmental decommissioning and remediation liabilities related to the Colstrip Units.
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10. Commitments and Contingencies
Legal Matters
Talen is involved in certain legal proceedings, claims and litigation. While we believe that we have meritorious positions and will continue to defend our positions vigorously in these matters, we may not be successful in our efforts. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal proceedings and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding the matters specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial.
Pending Legal Matters
Montana Hydroelectric Litigation. Talen Montana is a defendant in litigation in the U.S. District Court for the District of Montana relating to its past ownership and operation of hydroelectric generation facilities in Montana, which were sold to NorthWestern in November 2014 (the “Montana Hydroelectric Sale”). In connection with the sale, Talen Montana agreed to retain liability with respect to this litigation, if any, attributable to time periods prior to closing of the sale.
The lawsuit was originally filed in 2003 and alleges that the streambeds underlying the facilities are owned by the State of Montana (the “State”), and that Talen Montana owes the State compensation for the use of the streambeds. In August 2023, the court held in favor of Talen Montana with respect to streambed segments underlying six of the seven facilities. Regarding the one streambed segment that the court found belongs to the State, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. The State has appealed this holding to the U.S. Court of Appeals for the Ninth Circuit. Damages and defenses related to this proceeding will be addressed in a future adjudication. Nonetheless, because Talen Montana’s liability on all claims asserted by the State was discharged under the Plan of Reorganization, Talen Montana does not expect any further liability from this matter.
ERCOT Weather Event Lawsuits. Beginning in March 2021, the former Talen subsidiaries that at the time owned the Barney Davis, Nueces Bay and Laredo generation facilities were sued in multiple Texas courts along with many other market participants in ERCOT. See Note 17 for information on Talen’s sale of ERCOT generation assets. The lawsuits were consolidated into a multi-district litigation pre-trial court (“MDL”). In these suits, the plaintiffs allege, among other things, that they suffered loss of life, personal injury and/or property damage due to the defendants’ failure to properly prepare their facilities to withstand extreme winter weather and other operational failures during Winter Storm Uri in February 2021. Numerous insurance company plaintiffs also seek to recover payments to policyholders for damage to residential and commercial properties caused by the storm. The plaintiffs seek unspecified compensatory, punitive and other damages. In January 2023, the MDL court denied a motion to dismiss filed by the generation defendants. The generation defendants sought appellant review of the decision, and, in December 2023, the Texas First Court of Appeals granted the generation defendants’ request for mandamus relief and ordered dismissal of the claims against the generation defendants. Plaintiffs have filed a motion seeking rehearing en banc with the First Court of Appeals. If unsuccessful, plaintiffs are expected to petition the Texas Supreme Court to review the decision. Plaintiffs asserting prepetition Winter Storm Uri claims are limited to recovering any damages solely from the Talen defendants’ insurers pursuant to the Plan of Reorganization. Certain plaintiffs filed lawsuits asserting Winter Storm Uri claims after commencement of the Restructuring. If any of these post-commencement plaintiffs did not receive effective notice of the Restructuring under applicable bankruptcy law, they may not be subject to the terms of the Plan of Reorganization. Talen cannot predict the outcome of this matter for any such claims or its effect on Talen, which has retained these potential liabilities.
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In June 2021, TEC intervened in five cases in which certain market participants are challenging the validity of two PUCT orders directing ERCOT to ensure energy prices were at their maximum of $9,000 per MWh during Winter Storm Uri. One case has since been dismissed, one case is pending in the Texas Third Court of Appeals and two cases are pending in State District Court in Travis County, Texas. In March 2023, the Third Court of Appeals issued an opinion in Luminant v. PUCT that, in part, reversed and remanded the PUCT orders directing ERCOT to ensure prices were at their maximum of $9,000 per MWh during Winter Storm Uri. The PUCT (along with TEC and others) filed petitions for review with the Texas Supreme Court, which were granted in September 2023. Talen cannot predict the timing or outcome of these cases or their ultimate effect on the PUCT’s orders during Winter Storm Uri; however, changes in one or more of the PUCT’s orders could have a material adverse effect on Talen’s results of operations and liquidity.
Pension Litigation. In November 2020, four former Talen employees filed a lawsuit in the U.S. District Court for the Eastern District of Pennsylvania against TES, TEC, the TERP, the TERP committee, and (as amended) ten former retirement plan committee members alleging that they are owed enhanced benefits under the TERP. In September 2023, the parties reached a tentative agreement to settle all claims on a class-wide basis, inclusive of attorneys’ fees, in exchange for $20 million, subject to negotiation of mutually acceptable definitive agreements and court approval of the final settlement. In February 2024, the parties agreed upon the definitive settlement documentation, and on June 3, 2024, the settlement was approved and will become final in July 2024 subject to appeal (if any).
We expect a portion of the settlement to be paid by the TERP with the remainder paid by the Company, net of expected insurance recoveries. The amount paid by the TERP will be the full amount of the settlement less any attorneys’ fee award approved by the court and certain expenses associated with implementing the settlement. TES, at its discretion, may elect to fund a contribution into the TERP to cover settlement payments paid by the TERP. If the settlement is not consummated and the plaintiffs subsequently prevail on their claims, a material adverse judgment could have an adverse effect on the TERP’s assets as well as Talen’s results of operations and liquidity. No assurance can be provided that the final settlement agreement will be consummated as expected or if at all. Accordingly, we cannot predict the outcome of this matter or its effect on Talen if the settlement is not consummated as expected or if the matter is litigated to conclusion. As of March 31, 2024, the settlement amounts agreed to by the parties and expected insurance recoveries are presented on the Consolidated Balance Sheets.
Railroad Surcharge Litigation. In September 2019, TES and certain of its subsidiaries filed suit in the U.S. District Court for the Southern District of Texas, alleging that the four major railroads in the United States violated U.S. antitrust laws by conspiring during the periods from July 2003 through December 2008 to use fuel surcharges as a means to raise price for rail freight shipments. Numerous other plaintiff shippers in various jurisdictions throughout the United States have filed similar lawsuits. The Talen plaintiffs claim that they paid higher rail freight shipment rates than they otherwise would have paid absent the alleged conspiracy and seek treble damages under the antitrust laws. The litigation has been consolidated in the District Court for the District of Columbia with similar lawsuits under the multi-district litigation rules. At this time, Talen cannot predict the outcome of this matter.
Resolved Legal Matters
See the Annual Financial Statements for resolved legal matters.
Regulatory Matters
Talen is subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to: FERC; the Department of Energy; Federal Communications Commission; NRC; NERC; public utility commissions in various states in which we conduct business; and RTOs and ISOs in the regions in which we conduct business. Talen is party to proceedings before such agencies arising in the ordinary course of business and has other regulatory exposure due to new or amended regulations promulgated by such agencies from time to time. While the outcome of these regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations, although the effect could be material to our results of operations in any interim reporting period.
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PJM MOPR. 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 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.
PJM Market Seller Offer Cap. In March 2021, FERC responded to complaints filed by the PJM IMM on behalf of PJM and various consumer advocates alleging that the PJM MSOC was above a competitive offer level and was, therefore, unjust and unreasonable. In September 2021, FERC issued an order requiring the PJM ACR for each generator to be determined administratively by the PJM IMM. In August 2023, the U.S. Court of Appeals for the District of Columbia Circuit denied petitions by Talen and others for review of FERC’s order. On January 12, 2024, the Electric Power Supply Association filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the August 2023 order of the D.C. Circuit. The final impacts of this order on Talen’s financial condition, results of operations and liquidity are not known at this time.
PJM Capacity Market Reform. In February 2023, the PJM Board directed PJM and its stakeholders to resolve: (i) key issues that address the energy transition taking place in PJM; and (ii) issues observed from Winter Storm Elliott. The PJM Board directive included reliability risks, risk drivers and resource availability. The stakeholder process is referred to as Critical Issue Fast Path (“CIFP”) on resource adequacy. On October 13, 2023, PJM made two filings at FERC regarding certain capacity market reforms developed through the CIFP process. On January 30, 2024, FERC accepted one of PJM’s filings, subject to the condition that PJM submit a compliance filing within 30 days. However, in February 2024, FERC rejected the second of PJM’s capacity market reform filings and approved a request from PJM for a 35-day delay of Base Rate Auction. PJM has indicated that it plans to open the Base Residual Auction for the 2025/2026 Delivery on July 17, 2024. At this time, Talen cannot fully predict the impacts of PJM’s reforms on its operations and liquidity.
In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delay schedules the PJM Base Residual Auctions for 2026/2027 in December 2024, for 2027/2028 in June 2025, and for 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, but the final impacts on Talen's financial condition, results of operations and liquidity are not known at this time.
ERCOT Market Systemic Risks. In January 2023, the PUCT adopted the PUCT PCM market design in response to a directive contained within Texas Senate Bill 3 from 2021 to address market reliability concerns in Texas. The details of how the PUCT PCM market will operate are to be developed by the PUCT, ERCOT and the ERCOT stakeholder group. In January 2023, the PUCT directed ERCOT to evaluate bridging options to retain existing assets and build new dispatchable generation until the PUCT PCM can be fully implemented. In response, the PUCT approved a multi-step Operating Reserve Demand Curve floor as a short-term bridge solution, which went into effect on November 1, 2023. Under the approved multi-step Operating Reserve Demand Curve, price floors of $10/MWh and $20/MWh will be triggered when reserves fall below 7 GW and 6.5 GW, respectively. There remains significant uncertainty surrounding the details of the proposed PUCT PCM design, and the timing for implementation. At this time, Talen cannot fully predict the impacts of the PUCT PCM market design, when and if implemented, on its results of operations and liquidity.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, and hazardous and solid waste management. From time to time, in the ordinary course of our business, Talen may become involved in other environmental matters or become subject to other, new or revised environmental statutes, regulations or requirements.
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It may be necessary for us to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. We may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operation and maintenance expenses, monetary fines, penalties or other restrictions, which could be material. Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.
Water and Waste. Changes made by the EPA to the EPA CCR Rule and the EPA ELG Rule in 2020 allow coal generation facility operators to request an extension to compliance deadlines if the facility commits to cessation of coal-fired generation by the end of 2028. Pursuant to Talen’s plans to cease wholly owned coal operations, Talen requested extensions for compliance under these rules for certain of its generation facilities; some have been approved and some are still under review. The most significant extension under review is the EPA CCR Rule Part A extension request for Montour Ash Impoundment 1, and a negative result would have a significant impact on the closure plan for this impoundment.
In 2023, the EPA proposed additional changes to the ELG Rule and the CCR Rule and finalized those changes on May 9 and May 8, 2024, respectively. The new ELG Rule does not add treatment requirements to Talen’s coal-fired power generation facilities planning to cease burning coal by 2028, but it does establish discharge limits for waters collected from CCR units. Under the revised CCR Rule, the EPA has imposed new requirements on: (i) legacy CCR impoundments; and (ii) areas where CCR was disposed of or managed on land outside of regulated units at CCR facilities (subject to a minimum threshold). Furthermore, the EPA’s interpretations of the EPA CCR Rule continue to evolve through enforcement and other regulatory actions.
Talen submitted formal comments on both proposed rules citing their flaws and anticipates it will take legal action to challenge both final rules. If the revised Rules withstand expected legal challenges by power producers (including Talen), industry groups, state attorneys general, and others, the new CCR and ELG requirements could materially impact several Talen facilities. Talen is currently evaluating that potential impact. At this time, Talen cannot predict the full impact of these various rule changes on the operations of its coal-fired generation facilities and its results of operations.
Air. Since 2016, the coal-fired generation facilities in which Talen has ownership, including Brunner Island, Montour, Keystone and Conemaugh, have been the subject of various efforts under the Clean Air Act to strengthen applicable nitrogen oxides (“NOx”) emission limits. These include Section 126 petitions by downwind states, recommendations by the Ozone Transport Commission, and a ruling on Pennsylvania’s RACT2 program by the U.S. District Court for the Southern District of New York. Although the petitions and recommendations are not withdrawn, the EPA’s issuance of a federal implementation plan (the “FIP”) with short-term (RACT2) NOx limits at these plants in 2022 resulting from the court case and the EPA’s “Good Neighbor FIP” issued in June 2023 appear to have addressed open concerns by upwind states regarding NOx controls from Talen’s and other coal plants.
However, both the Pennsylvania NOx RACT2 FIP and the preceding State Implementation Plan (the “SIP”) NOx RACT are under review. The PA DEP agreed to stay the SIP standard while all the parties consider the FIP standards. The EPA FIP is in effect; however, it has since been appealed by other parties and Talen has intervened in the appellate proceeding. Lastly, in November 2022, Pennsylvania finalized its NOx RACT standards for all power generation facilities to address the EPA 2015 Ozone Standard. Affected Talen facilities have submitted permit applications demonstrating their compliance methods for the new standard. At this time, Talen cannot predict the outcome of these potential rule changes on the operations of its generation facilities and its results of operations.
To address the 2015 ozone standard, in June 2023, the EPA published the final rule covering the EPA CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” The EPA made some reductions in allowance allocations, among other changes, to minimize nitrogen oxide emissions during the Ozone Season. Texas, among other states, has received a favorable court ruling, essentially staying its participation in the updated program for 2023. Texas facilities are still subject to the previous version of EPA CSAPR, and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. Additionally, the entire rule has been challenged by multiple parties, and the U.S. Supreme Court heard oral
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arguments on the emergency applications to stay the rule in February 2024. At this time, Talen cannot predict the long-term outcome of these rule changes on the operations of its generation facilities and its results of operations.
The EPA MATS Rule, which is the original EPA NESHAP for coal plants, has been in effect since 2012. In April 2023, the EPA proposed, and on May 7, 2024, finalized, its RTR for coal-fired generation facilities under the EPA NESHAP. The final rule most notably requires coal plants to reduce particulate matter (PM) emissions by the end of 2027 (or 2028 in certain circumstances). Colstrip cannot meet the new PM standard without substantial upgrades to its control equipment; therefore, Talen and the Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the plant. That decision must be made in conjunction with compliance requirements under EPA’s new GHG Rule, finalized on May 9, 2024.
Talen submitted formal comments on the new PM standard and revisions to the MATS Rule, citing the rule’s flaws, and anticipates it (and others, including other power producers, industry groups, and state attorneys general) will take legal action to challenge the revised MATS Rule. On May 8, 2024, a coalition of 23 states filed a challenge to the MATS Rule in the U.S. Court of Appeals for the D.C. Circuit. In light of these filed and expected challenges, Talen cannot predict the full impact of the revised MATS Rule on the operations of its coal-fired generation facilities and its results of operations.
RGGI. In April 2022, Pennsylvania formally entered the RGGI program, with compliance set to begin on July 1, 2022. However, certain third parties filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania was stayed. On November 1, 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PA DEP appealed this decision to the Pennsylvania Supreme Court in November 2023, and the following day filed notice with the court that the RGGI program would not be implemented while the appeal is pending. At this time, Talen is unable to determine the full impact of the RGGI program, when and if implemented, on its results of operations and liquidity.
Federal Climate Change Actions. The current federal administration has identified climate change policy as a priority that includes, but is not limited to, greenhouse gas emission reductions. On May 9, 2024, the EPA issued a new rule under the Clean Air Act that establishes New Source Performance Standards for new electric generating units and greenhouse gas Emissions Guidelines for existing EGUs for state implementation. The guidelines would allow all existing EGUs to continue to operate until at least the end of 2031 without having to meet new greenhouse gas limits. Existing oil/gas steam EGUs (for example, Martins Creek) will not require additional controls at this time. However, if existing coal-fired EGUs (for example, Colstrip) are to be able to operate beyond 2031, they must install a GHG reduction technology, like carbon capture and sequestration (CCS), by the end of 2031. Talen will need to evaluate the viability and costs of additional controls and decide whether to invest in those controls at Colstrip or retire the units. That decision may be influenced by the cost of compliance with the revised MATS rule. EPA stated that it chose not to finalize emission guidelines for existing fossil fuel-fired combustion turbines (for example, LMBE); however, EPA intends to take further action on such emission guidelines at a later date.
In 2023, Talen submitted formal comments on the proposed GHG Rule, citing the rule’s flaws, and anticipates it will take legal action to challenge the GHG Rule. A number of petitions for review of the GHG Rule were filed on May 9, 2024, in the U.S. Court of Appeals for the D.C Circuit, including by coalitions representing 27 states. If the rule withstands filed and expected legal challenges by power producers (including Talen), industry groups, state attorneys general, and others, the GHG Rule could materially impact Colstrip and Talen. Talen is currently evaluating that potential impact. At this time, Talen cannot predict the full impact of the GHG Rule on the operations of its coal-fired generation facilities and its results of operations.
Environmental Remediation. From time-to-time, Talen undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from our operations and undertakes similar actions necessary to resolve environmental matters that arise in the course of normal operations.
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Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs, but at this time we are unable to determine if such investigation or remediation work will have a material adverse effect on our financial condition or results of operations.
Guarantees and Other Assurances
In the normal course of business, Talen enters into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by letters of credit issued by financial institutions, surety bonds issued by insurance companies, and indemnifications. In addition, they may include customary indemnifications to third parties related to asset sales and other transactions. Based on our current knowledge, the probability of expected material payment/performance for the guarantees and other assurances is considered remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain subsidiaries for obligations including, but not limited to, environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers, in each case upon the occurrence of certain events. As of March 31, 2024 (Successor) and December 31, 2023 (Successor), the aggregate amount of surety bonds outstanding was $241 million and $240 million, including surety bonds posted on behalf of Talen Montana as discussed below.
Talen Montana Financial Assurance. Pursuant to the Colstrip AOC, Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the MDEQ on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of the Colstrip Units have provided their proportional share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
TES has posted an aggregate $118 million of surety bonds to the MDEQ on behalf of Talen Montana’s proportional share of remediation and closure activities as of March 31, 2024 (Successor) and $115 million as of December 31, 2023 (Successor). In April 2024, MDEQ approved a modified work scope that will require Talen Montana to post an additional $7 million of surety bonds or other financial assurance in the second quarter 2024. Talen Montana has agreed to reimburse TES and its affiliates in the event that these surety bonds are called. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements will decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed.
Cumulus Digital Assurances. As of December 31, 2023 (Successor), TES had issued LCs in the aggregate amount of $50 million to the lenders of the Cumulus Digital TLF, which LCs could be drawn upon, among other events, the acceleration of the loan due to a bankruptcy or other event of default by Cumulus Digital. The LCs were cancelled upon the repayment in full of the Cumulus Digital TLF in March 2024.
Additionally, TEC had provided a guarantee to the lenders under the Cumulus Digital TLF for certain shortfalls in interest and principal payments by Cumulus Digital (up to a maximum of 23% of the principal amount of outstanding loans thereunder). The guarantee was cancelled upon the payment in full of the Cumulus Digital TLF in March 2024.
Other Commitments and Contingencies
Nuclear Insurance. The Price-Anderson Act is a United States federal law which governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed
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nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of March 31, 2024 (Successor), the liability limit per incident is $16.2 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers (approximately $500 million in coverage), with the remainder covered by an industry retrospective assessment program.
As of March 31, 2024 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $332 million per incident, payable at a maximum of $49 million per year.
Additionally, Susquehanna purchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna is a member. As of March 31, 2024 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $2.0 billion and non-nuclear property damage losses up to $1.0 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $45 million as of March 31, 2024 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Talen Montana Fuel Supply. Talen Montana purchases coal from the Rosebud Mine for its interest in Colstrip Units 3 and 4 under a full requirements contract with an unaffiliated coal mine operator. In 2015, the MDEQ issued the mine operator an amendment to one of its mine permits expanding the area authorized for mining. Certain parties challenged the permit amendment in a proceeding at the MBER and, after the MBER issued a decision upholding the permit amendment, in a lawsuit in Montana state district court. In January 2022, the district court entered an order vacating the permit amendment effective April 1, 2022. Rosebud Mining ceased mining in the expansion area prior to the April 1, 2022 deadline. The mine operator and the MDEQ appealed the district court’s decisions to the Montana Supreme Court and filed motions seeking to stay the order vacating the permit. In August 2022, the Montana Supreme Court entered an order staying the district court’s order pending resolution of the appeal. In November 2023, the Montana Supreme Court remanded the case to the MBER to reanalyze the administrative record, resolve factual questions, and re-examine its prior conclusion. The MBER is awaiting remand. In the meantime, however, the Montana Supreme Court reinstated vacatur of the permit amendment pending MBER review.
In May 2022, MDEQ issued a second permit amendment expanding the area authorized for mining by the coal-mine operator. A group of complainants initiated proceedings at the MBER and in Montana state district court challenging the second permit amendment. Summary judgment briefing was completed in the MBER case as of January 2024. In December 2023 the Montana state district court challenge was stayed for six months pending a ruling from the Montana Supreme Court in analogous cases.
In September 2022, the Montana Federal District Court entered an order upholding challenges to a third permit amendment expanding the area authorized for mining by the mine operator. The plaintiffs asserted that the OSM violated NEPA when preparing the EIS for the permit amendment. The court ordered OSM to complete an updated EIS in accordance with NEPA’s requirements. The permit amendment will be vacated unless OSM completes the updated EIS within 19 months from the date of the court’s order. The federal defendants did not appeal and expect to issue a revised decision on the permit amendment within the 19-month deadline, but in November 2022, intervenor-defendants, Westmoreland Rosebud and International Union, appealed the ruling to the Ninth Circuit Court of Appeals. MEIC and the other plaintiffs moved to dismiss the appeal for lack of jurisdiction, and the federal defendants did not oppose the motion to dismiss. The appeal was dismissed in November 2023, and the federal defendants requested an extension of the deadline to complete the updated EIS until June 30, 2025. In April 2024, the District Court granted an extension but only to January 31, 2025.
At this time, Talen cannot predict the outcome of these matters or their effect on Talen Montana’s operations, results of operations or liquidity.
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11. Long-Term Debt and Other Credit Facilities
Long-Term Debt
| Successor | ||||||||||||||||||||
Interest Rate (a) | March 31, 2024 | December 31, 2023 | ||||||||||||||||||
| TLB | 9.83 | % | $ | 863 | $ | 866 | ||||||||||||||
| TLC | 9.83 | % | 470 | 470 | ||||||||||||||||
| Secured Notes | 8.63 | % | 1,200 | 1,200 | ||||||||||||||||
| PEDFA 2009B Bonds | 4.75 | % | 50 | 50 | ||||||||||||||||
| PEDFA 2009C Bonds | 4.75 | % | 81 | 81 | ||||||||||||||||
Cumulus Digital TLF, including PIK (b) | — | % | — | 182 | ||||||||||||||||
Total principal | 2,664 | 2,849 | ||||||||||||||||||
| Unamortized deferred finance costs and original issuance discounts | (36) | (29) | ||||||||||||||||||
Total carrying value | 2,628 | 2,820 | ||||||||||||||||||
| Less: long-term debt, due within one year | 9 | 9 | ||||||||||||||||||
Long-term debt | $ | 2,619 | $ | 2,811 | ||||||||||||||||
__________________
(a)Computed interest rate as of March 31, 2024 (Successor).
(b)Limited recourse to TES and TEC. See “Guarantees and Other Assurances - Cumulus Digital Assurances” in Note 10 for additional information. The Cumulus Digital TLF was repaid and extinguished in March 2024. See “2024 Transactions – Cumulus Digital TLF Repayment” below for additional information.
The aggregate long-term debt maturities, including amortization and early redemption provisions, at March 31, 2024 (Successor) were:
2024 (a) | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| Total maturities | $ | 7 | $ | 9 | $ | 9 | $ | 9 | $ | 9 | $ | 2,621 | $ | 2,664 | |||||||||||||||||||||||||||
__________________
(a)For the period from April 1, 2024 through December 31, 2024.
Revolving Credit and Other Facilities
| Successor | ||||||||||||||||||||||||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||||||||||||||||||||||||||||||||
| Expiration | Committed Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | ||||||||||||||||||||||||||||||||||||||
RCF (a) | May 2028 | $ | 700 | $ | — | $ | 156 | $ | 544 | $ | — | $ | 62 | |||||||||||||||||||||||||||||||
TLC LCF (b)(c)(d) | May 2030 | 470 | — | 366 | 104 | — | 404 | |||||||||||||||||||||||||||||||||||||
Bilateral LCF (b) | May 2028 | 75 | — | 74 | 1 | — | 74 | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,245 | $ | — | $ | 596 | $ | 649 | $ | — | $ | 540 | ||||||||||||||||||||||||||||||||
__________________
(a)Committed capacity includes $475 million of LC commitments. Outstanding direct cash borrowings under the RCF, when applicable, are presented as “Revolving credit facilities” on the Consolidated Balance Sheets.
(b)Direct cash borrowings are not permitted under the facility.
(c)These LCs are cash collateralized by $472 million as of March 31, 2024 (Successor) and December 31, 2023 (Successor), which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.
(d)Includes $133 million of LCs backing the PEDFA Bonds as of each of March 31, 2024 (Successor) and December 31, 2023 (Successor).
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2024 Transactions
Cumulus Digital TLF Repayment. In connection with the Data Center Campus Sale, the Cumulus Digital TLF was paid in full, together with all accrued interest and other outstanding amounts. See “Non-Recourse Debt and Other Credit Facilities – Cumulus Digital TLF” in Note 13 in Notes to the Annual Financial Statements for additional information on the related release of liens, termination of guarantees, and cancellation of LCs. See Note 17 for additional information on the Data Center Campus Sale.
Long-Term Debt 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 the Standard Overnight Financing Rate (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 Company’s sale of its Texas generation portfolio, and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement. See Note 17 for additional information on the recent sale of our generation assets in Texas.
Talen Energy Supply Long-Term Debt, Revolving Credit and Other Facilities
As of March 31, 2024 (Successor), Talen was not in default under any of its indebtedness agreements.
See “Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities” in Note 13 in Notes to the Annual Financial Statements for a description of the material terms of our Credit Facilities, Secured Notes, PEDFA Bonds and Secured IDSAs.
See “Security Interests, Guarantees, and Cross-Defaults on TES Post-Emergence Obligations” in Note 13 in Notes to the Annual Financial Statements for additional information on the security interests and guarantees supporting these obligations. In addition to the obligations outlined under “Long-Term Debt” and “Revolving Credit and Other Facilities” above, secured obligations included approximately $61 million under Secured ISDAs as of March 31, 2024 (Successor).
12. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT.
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The classifications of recurring fair value measurements within the fair value hierarchy were:
| Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Netting(a) | Total | Level 1 | Level 2 | NAV | Netting(a) | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | 15 | $ | — | $ | 15 | $ | — | $ | — | $ | 9 | $ | — | $ | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Equity securities (b) | 702 | — | 359 | — | 1,061 | 629 | — | 384 | — | 1,013 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 318 | — | — | — | 318 | 337 | — | — | — | 337 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | 87 | — | — | 87 | — | 86 | — | — | 86 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 169 | — | — | 169 | — | 156 | — | — | 156 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | (8) | (26) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
NDT funds | 1,020 | 256 | 374 | — | 1,642 | 966 | 242 | 393 | — | 1,575 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives (d) | 92 | 78 | — | (151) | 19 | 98 | 196 | — | (200) | 94 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 2 | — | — | 2 | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total assets | $ | 1,112 | $ | 336 | $ | 374 | $ | (151) | $ | 1,663 | $ | 1,064 | $ | 439 | $ | 393 | $ | (200) | $ | 1,670 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | 149 | 155 | — | (203) | 101 | 155 | 139 | — | (257) | 37 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 1 | — | — | 1 | — | 6 | — | — | 6 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Less: other | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | $ | 149 | $ | 156 | $ | — | $ | (203) | $ | 102 | $ | 155 | $ | 145 | $ | — | $ | (257) | $ | 43 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
__________________
(a)Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b)Includes commingled equity and fixed income funds and real estate investment trusts.
(c)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
(d)Commodity contracts assets include $3 million of ERCOT positions that are presented as “Assets held for sale” on the Consolidated Balance Sheets. See Note 17 for additional information on the ERCOT divestiture.
There were no recurring fair value measurements classified as Level 3 as of March 31, 2024 (Successor) and December 31, 2023 (Successor).
Nonrecurring Fair Value Measurements
There were no nonrecurring fair value measurements related to impairments of long-lived assets during the three months ended March 31, 2024 (Successor). See Note 8 for information on the nonrecurring fair value measurement of Brandon Shores during the three months ended March 31, 2023 (Predecessor).
Reported Fair Value
The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents,” “Restricted cash and cash equivalents,” “Accounts receivable, net,” and “Accounts payable and other accrued liabilities” approximate fair value.
The fair value measurements of indebtedness are classified as Level 2 within the fair value hierarchy. The fair value of fixed rate debt was estimated primarily by utilizing an income approach whereby the future cash flows of
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the obligations are discounted at the estimated current cost of funding rates, which incorporates the credit risk associated with the obligations. The carrying value of variable rate indebtedness approximates fair value.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| Successor | |||||||||||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||||||||||||||||
Long-term debt (a) | $ | 2,628 | $ | 2,749 | $ | 2,820 | $ | 2,934 | |||||||||||||||||||||
Other short-term indebtedness (b) | 2 | 2 | 6 | 6 | |||||||||||||||||||||||||
__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
(b)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
13. Postretirement Benefit Obligations
Talen Energy Supply and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and defined contribution plans.
The components of net periodic benefit costs for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||
| 2024 | 2023 | |||||||||||||
Postretirement benefits service cost (a) | $ | 1 | $ | 1 | ||||||||||
| Interest cost | 17 | 18 | ||||||||||||
| Expected return on plan assets | (17) | (22) | ||||||||||||
| Amortization of: | ||||||||||||||
| Net loss | — | 1 | ||||||||||||
Postretirement benefit (gain) loss, net (b) | — | (3) | ||||||||||||
Net periodic defined benefit cost (credit) | $ | 1 | $ | (2) | ||||||||||
__________________
(a)Activity presented as “Operation, maintenance and development” on the Consolidated Statements of Operations.
(b)Activity presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
See Note 10 for additional information on pending litigation regarding certain of our defined benefit pension obligations.
In March 2024, $10 million of excess assets from the PA Mines UMWA Plan VEBA were transferred to a separate VEBA which provides benefits for participants in Talen's health and welfare “wrap plan.” As such assets were not presented on the Consolidated Balance Sheets prior to the transfer of the assets from the VEBA, a transfer gain of $10 million was recognized for the three months ended March 31, 2024 (Successor) and presented as “Other non-operating income (expense), net” on the Consolidated of Operations.
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14. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||
| 2024 | 2023 | |||||||||||||
| Numerator: (Millions of Dollars) | ||||||||||||||
Net Income (loss) | $ | 319 | $ | 46 | ||||||||||
| Less: | ||||||||||||||
| Net income (loss) attributable to noncontrolling interest | 25 | (2) | ||||||||||||
Net Income (loss) attributable to the Company | $ | 294 | $ | 48 | ||||||||||
| Denominator: (Thousands) | ||||||||||||||
| Weighted-average shares outstanding - Basic | 58,807 | — | ||||||||||||
| Warrants | 184 | — | ||||||||||||
| Restricted stock units | 427 | — | ||||||||||||
| Performance stock units | 1,298 | — | ||||||||||||
Weighted-average shares outstanding - Diluted | 60,716 | — | ||||||||||||
Basic earnings per share | $ | 5.00 | N/A | |||||||||||
Diluted earnings per share | 4.84 | N/A | ||||||||||||
Diluted EPS during the three months ended March 31, 2024 (Successor) excludes the impact of 10,125 restricted stock units (“RSUs”) outstanding due to their anti-dilutive nature.
In the three months ended March 31, 2024 (Successor) the Company repurchased 493,000 shares of common stock for $39 million at a weighted average per share price of $78.31.
15. Accumulated Other Comprehensive Income
Changes in AOCI for the three months ended March 31 were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
| 2024 | 2023 | ||||||||||||||||||||||||||||
| Beginning balance | $ | (23) | $ | (167) | |||||||||||||||||||||||||
| Gains (losses) arising during the period | — | 10 | |||||||||||||||||||||||||||
| Reclassifications to Consolidated Statements of Operations | (7) | 6 | |||||||||||||||||||||||||||
| Income tax benefit (expense) | 3 | (7) | |||||||||||||||||||||||||||
Other comprehensive income (loss) | (4) | $ | 9 | ||||||||||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (27) | $ | (158) | |||||||||||||||||||||||||
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The components of AOCI, net of tax, for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | 1 | $ | (8) | ||||||||||||||||
| Qualifying derivatives unrealized gain (loss), net | — | 9 | ||||||||||||||||||
| Postretirement benefit prior service credits (costs), net | — | 7 | ||||||||||||||||||
| Postretirement benefit actuarial gain (loss), net | (28) | (166) | ||||||||||||||||||
Accumulated other comprehensive income (loss) | $ | (27) | $ | (158) | ||||||||||||||||
Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the three months ended March 31, 2024, (Successor) and 2023 (Predecessor).
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 13 for additional information.
16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the three months ended March 31 were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||
Cash paid (received) during the period | ||||||||||||||||||||||||||||||||
Interest and other finance charges, net of capitalized interest (a) | $ | 33 | $ | 93 | ||||||||||||||||||||||||||||
| Income taxes, net | — | 1 | ||||||||||||||||||||||||||||||
| Non-cash investing and operating activities | ||||||||||||||||||||||||||||||||
| Capital expenditure accrual increase (decrease) | (16) | (8) | ||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Operations: | ||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | 75 | 132 | ||||||||||||||||||||||||||||||
Amortization of deferred finance costs and original issuance discounts (interest expense) (b) | 1 | 6 | ||||||||||||||||||||||||||||||
| Other | (2) | — | ||||||||||||||||||||||||||||||
Total depreciation, amortization and accretion | $ | 74 | $ | 138 | ||||||||||||||||||||||||||||
| Non-cash financing/investing activities | ||||||||||||||||||||||||||||||||
Non-cash increase to PP&E and decrease to other current assets for transfer of miners by Cumulus Coin (c) | $ | — | $ | 14 | ||||||||||||||||||||||||||||
| Non-cash decrease to PP&E and decrease to noncontrolling interest for transfer of miners to TeraWulf | — | 2 | ||||||||||||||||||||||||||||||
Non-cash increase to PP&E and increase to noncontrolling interest for transfer of miners by TeraWulf (b) | — | 38 | ||||||||||||||||||||||||||||||
| Unrealized (gain) loss on derivatives: | ||||||||||||||||||||||||||||||||
| Commodity contracts | 134 | (30) | ||||||||||||||||||||||||||||||
| Interest rate swap contracts | (6) | 2 | ||||||||||||||||||||||||||||||
Total unrealized (gain) loss on derivatives | $ | 128 | $ | (28) | ||||||||||||||||||||||||||||
F-31
| Successor | Predecessor | |||||||||||||||||||||||||||||||
| 2024 | 2023 | |||||||||||||||||||||||||||||||
| Operating activities reconciliation adjustments, other: | ||||||||||||||||||||||||||||||||
| Net periodic defined benefit cost | $ | — | $ | (2) | ||||||||||||||||||||||||||||
| Stock-based compensation | 8 | — | ||||||||||||||||||||||||||||||
| Derivative option premium amortization | — | 19 | ||||||||||||||||||||||||||||||
| Bitcoin revenue | (42) | (9) | ||||||||||||||||||||||||||||||
| Gain on sale of mineral rights and western gas portfolio | — | (29) | ||||||||||||||||||||||||||||||
| Gain on cancellation of lease | — | (7) | ||||||||||||||||||||||||||||||
| Nonrecourse PIK interest | — | 6 | ||||||||||||||||||||||||||||||
| Debt restructuring (gain) loss, net | (9) | — | ||||||||||||||||||||||||||||||
| Other | 1 | — | ||||||||||||||||||||||||||||||
Total | $ | (42) | $ | (22) | ||||||||||||||||||||||||||||
__________________
(a)Capitalized interest totaled $3 million and $8 million for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor).
(b)Includes previously recognized fair value adjustments on certain exchanges of indebtedness.
(c)In 2023, each of the joint venture partners of Nautilus made non-cash contributions to Nautilus of cryptocurrency miners that increased PP&E.
Cash and Restricted Cash
The following provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Statements of Cash Flows to line items within the Consolidated Balance Sheets:
| Successor | ||||||||||||||||||||
| March 31, 2024 | December 31, 2023 | |||||||||||||||||||
Cash and cash equivalents | $ | 597 | $ | 400 | ||||||||||||||||
| Restricted cash and cash equivalents: | ||||||||||||||||||||
| TES TLC debt restricted deposits | 472 | 472 | ||||||||||||||||||
| Nautilus project restricted deposits | 10 | 10 | ||||||||||||||||||
| Cumulus Digital Holdings restricted deposits | 1 | 19 | ||||||||||||||||||
Restricted cash and cash equivalents | 483 | 501 | ||||||||||||||||||
Total | $ | 1,080 | $ | 901 | ||||||||||||||||
17. Acquisitions and Divestitures
Completed Divestitures
ERCOT Asset Sale. In March 2024, the Company and CPS Energy entered into an agreement for CPS Energy to acquire the Company’s approximately 1,710 MW Texas generation portfolio located within the ERCOT market for $785 million, subject to customary net working capital adjustments. Under the terms of the sale, there is no contingent consideration associated with the transfer of assets. The sale closed on May 1, 2024. Under the terms of the sale, CPS Energy acquired the Barney Davis, Nueces Bay, and Laredo generation facilities and certain related contracts. The Company is providing certain customary back-office and information technology transitional services to CPS Energy for up to 90 days after the sale.
As of March 31, 2024 (Successor), the assets and liabilities associated with the sale are presented as held for sale on the Consolidated Balance Sheet. “Assets held for sale” primarily represent the carrying value of property, plant and equipment, net and “Liabilities held for sale” primarily represent accounts payable and other accrued liabilities.
F-32
Cumulus Data Campus Sale. In March 2024, an affiliate of Amazon.com, Inc. (together with its affiliates, “Amazon”) purchased substantially all the assets of Cumulus Data and certain other assets for gross proceeds of $650 million. Gross proceeds of $350 million were initially received at closing with the remaining $300 million of variable consideration, presented as “Other current assets” on the Consolidated Balance Sheet, expected to be received from escrow at the completion of certain development milestones. Cumulus Digital Holdings distributed $109 million of the initial net proceeds from the sale to its members, including $108 million to TES.
In connection with the Cumulus Data Campus Sale, the Company entered into a power purchase agreement with Amazon, pursuant to which (i) the Company agreed to supply up to 960 MW of long-term, carbon-free power to the Cumulus Data Campus from Susquehanna; (ii) the parties agreed to fixed-price power commitments that increase in 120 MW increments over several years; and (iii) Amazon, under certain conditions, has the option to cap their commitments at 480 MW. Amazon also became lessor under the ground lease agreement with Nautilus.
For the three months ended March 31, 2024 (Successor), a $324 million net gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. For the three months ended March 31, 2024 (Predecessor), a $29 million gain was presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
Acquisition of Noncontrolling Interests
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 an aggregate $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital Holdings.
Cancelled Acquisition
Talen Montana Colstrip Units 3 and 4 Transaction. In September 2022, Talen Montana entered into an agreement under which Puget Sound Energy, Inc. would abandon its 25% share of Colstrip Units 3 and 4 to Talen Montana for no cash consideration. In February 2024, Puget Sound sent a notice asserting that Talen Montana was in breach of the agreement for failing to obtain Bankruptcy Court approval and that the agreement is unenforceable. Talen Montana has agreed that the agreement is unenforceable and disputed that it breached the agreement. Accordingly, it is unlikely that this transaction will be consummated.
18. Segments
Talen’s reportable segments are based upon the market areas in which our generation facilities operate and reflect the manner in which our chief operating decision makers review results and allocates resources. Adjusted EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision makers.
Our reportable segments are engaged in electricity generation, marketing activities, commodity risk and fuel management within their respective RTO or ISO markets. The segments include:
•PJM - a reportable segment that includes the operating and marketing activities within the PJM market. PJM is comprised of Susquehanna and Talen’s natural gas and coal generation facilities located within the PJM market; and
•ERCOT and WECC - a reportable segment that includes the operating and marketing activities within the ERCOT market for the operations of the Talen Texas power generation facilities, and the operating and marketing activities for Talen Montana’s proportionate share of the Colstrip Units. We have determined it appropriate to aggregate results from these markets into one reportable segment, based on a combination of size and economic characteristics.
F-33
Corporate, Development, and Other, or CD&O, represents the remaining non-segment grouping that includes: (i) General and administrative expenses incurred by our corporate and commercial functions that are not allocated to our reportable segments; (ii) the development activities of Cumulus Growth; (iii) the development and operating activities of Cumulus Digital; (iv) other non-material components that are not regularly reviewed by our chief operating decision makers; and (v) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
Financial data for the segments and reconciliation to consolidated results are:
| Three Months Ended March 31, 2024 (Successor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 418 | $ | 85 | $ | 6 | $ | 509 | |||||||||||||||
| Interest expense | — | — | 59 | 59 | |||||||||||||||||||
| Capital expenditures | 52 | 7 | 7 | 66 | |||||||||||||||||||
| Adjusted EBITDA | 279 | 15 | 294 | ||||||||||||||||||||
| Three Months Ended March 31, 2023 (Predecessor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 974 | $ | 95 | $ | 4 | $ | 1,073 | |||||||||||||||
| Interest expense | — | — | 104 | 104 | |||||||||||||||||||
| Capital expenditures | 94 | 2 | 34 | 130 | |||||||||||||||||||
| Adjusted EBITDA | 644 | 31 | 675 | ||||||||||||||||||||
| Three Months Ended March 31, | ||||||||||||||
| Successor | Predecessor | |||||||||||||
| 2024 | 2023 | |||||||||||||
| Adjusted EBITDA: | ||||||||||||||
| PJM | $ | 279 | $ | 184 | ||||||||||
| ERCOT and WECC | 15 | 3 | ||||||||||||
Total Adjusted EBITDA | $ | 294 | $ | 187 | ||||||||||
| Reconciling Items: | ||||||||||||||
| Interest expense and other finance charges | (50) | (104) | ||||||||||||
| Income tax benefit (expense) | (69) | (14) | ||||||||||||
| Depreciation, amortization and accretion | (75) | (132) | ||||||||||||
| Nuclear fuel amortization | (35) | (24) | ||||||||||||
| Reorganization gain (loss), net | — | (39) | ||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | (134) | 31 | ||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 75 | 46 | ||||||||||||
| Gain (loss) on non-core asset sales, net | 324 | 35 | ||||||||||||
| Legal settlements and litigation costs | 2 | — | ||||||||||||
| Unusual market events | 1 | (13) | ||||||||||||
| Impairments, canceled projects, inventory net realizable value and obsolescence, and receivables allowance | (1) | (389) | ||||||||||||
| Corporate, development and other | (13) | 462 | ||||||||||||
Net Income (Loss) | $ | 319 | $ | 46 | ||||||||||
F-34
19. Subsequent Events
The Company evaluated subsequent events through May 13, 2024, the date the financial statements are available to be issued. All significant subsequent events are included in their respective notes to the financial statements, except as noted below.
Share Repurchase Program
On May 9, 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion.
F-35
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Stockholders of Talen Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Talen Energy Corporation and its subsidiaries (Successor) (the “Company”) as of December 31, 2023, and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the period from May 18, 2023 through December 31, 2023, including the related notes and financial statement schedule listed in the accompanying index (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023, and the results of its operations and its cash flows for the period from May 18, 2023 through December 31, 2023 in conformity with accounting principles generally accepted in the United States of America.
Basis of Accounting
As discussed in Note 3 to the consolidated financial statements, the United States Bankruptcy Court for Southern District of Texas confirmed the Company's Plan of Reorganization (the “plan”) in December 2022. Confirmation of the plan resulted in the discharge of all claims against the Company that arose before May 9, 2022 and substantially alters rights and interests of equity security holders as provided for in the plan. The plan was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting as of May 17, 2023.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audit included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audit provides a reasonable basis for our opinion.
F-36
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Commodity Derivatives Valuation
As described in Notes 2, 5 and 14 to the consolidated financial statements, the Company had a fair value net derivative asset position of $95 million and a fair value net derivative liability position of $43 million, as of December 31, 2023. As disclosed by management, the Company utilizes exchange-traded and over the-counter traded derivative instruments to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with their generation portfolio. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties.
The principal considerations for our determination that performing procedures relating to commodity derivative valuation is a critical audit matter are (i) the significant judgment by management when developing the valuation of commodity derivatives; (ii) a high degree of auditor judgment and effort in performing procedures and evaluating management’s significant assumptions related to the forward commodity prices and commodity price volatility; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others, (i) testing management’s process for developing the valuation of commodity derivatives; (ii) evaluating the appropriateness of management’s model; (iii) testing, on a sample basis, the completeness and accuracy of the underlying contract terms and the accounting treatment conclusions; and (iv) evaluating, on a sample basis, the reasonableness of the significant assumptions used by management related to forward commodity prices and commodity price volatility. Professionals with specialized skill and knowledge were used to assist in evaluating the reasonableness of forward commodity prices and commodity price volatility assumptions.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 14, 2024, except for the financial statement schedule, as to which the date is April 4, 2024
We have served as the Company’s auditor since 2017.
F-37
Report of Independent Registered Public Accounting Firm
To the Board of Managers and Members of Talen Energy Supply, LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheet of Talen Energy Supply, LLC and its subsidiaries (Predecessor) (the “Company”) as of December 31, 2022 and the related consolidated statements of operations, comprehensive income (loss), equity and cash flows for the period from January 1, 2023 through May 17, 2023 and for each of the two years in the period ended December 31, 2022, including the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2022, and the results of its operations and its cash flows for the period from January 1, 2023 through May 17, 2023, and for each of the two years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.
Basis of Accounting
As discussed in Note 3 to the consolidated financial statements, the Company filed a petition on May 9, 2022 with the United States Bankruptcy Court for the Southern District of Texas for reorganization under the provisions of Chapter 11 of the Bankruptcy Code. The Company’s Plan of Reorganization was substantially consummated on May 17, 2023 and the Company emerged from bankruptcy. In connection with its emergence from bankruptcy, the Company adopted fresh start accounting.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s consolidated financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits of these consolidated financial statements in accordance with the standards of the PCAOB and in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud.
Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
F-38
Critical Audit Matters
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Fresh start accounting - valuation of electric generation assets
As described above and in Notes 3 and 4 to the consolidated financial statements, in May 2022, Talen Energy Supply, LLC (TES) and the other initial Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. The Plan of Reorganization was approved by the requisite parties in November 2022, was confirmed by the Bankruptcy Court in December 2022, and was consummated and became effective in May 2023, when the Debtors emerged from the Restructuring. Upon emergence, TES adopted fresh start accounting and allocated the reorganization value to its individual assets based on their estimated fair values. The Company’s principal assets are generation facilities whose values were determined by a discounted cash flow analysis based on management’s latest outlook of the business through the end of their expected useful lives. The forward-looking projections considered: (i) company-specific factors, such as unit characteristics, plant dispatch, operating expenses, capital expenditures and estimated economic useful lives; and (ii) macroeconomic factors, such as capacity prices, energy prices, fuel prices, market supply and demand factors, inflation factors, and environmental regulations. The present value of expected future cash flows utilized a weighted average cost of capital discount rate. The Company recorded fresh start adjustments for the period from January 1, 2023 through May 17, 203, which included $350 million related to electric generation assets recorded within property, plant and equipment, net.
The principal considerations for our determination that performing procedures relating to fresh start accounting – valuation of electric generation assets is a critical audit matter are (i) the significant judgment by management in developing the fair value estimate of electric generation assets; (ii) the high degree of auditor judgment and effort in performing procedures and evaluating management’s significant assumptions related to plant dispatch, capital expenditures, forward energy prices, and the weighted average cost of capital discount rate; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.
Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included, among others (i) testing management’s process for developing the fair value estimate of electric generation assets; ii) evaluating the appropriateness of management’s discounted cash flow models; (iii) testing the completeness and accuracy of underlying data used by management in the models, (iv) evaluating the reasonableness of management’s significant assumptions related to plant dispatch, capital expenditures, forward energy prices, and the weighted average cost of capital discount rate. Evaluating management’s assumptions related to plant dispatch, capital expenditures, forward energy prices, and the weighted average cost of capital discount rate involved evaluating whether the assumptions used by management were reasonable considering (a) the current and past performance of the assets; (b) the consistency with external market and industry data; and (c) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the models used and (ii) the reasonableness of the forward energy prices and the weighted average cost of capital discount rate assumptions.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
March 14, 2024
We have served as the Company’s auditor since 2017.
F-39
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| (Millions of Dollars, except share data) | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Capacity revenues | $ | 133 | $ | 108 | $ | 377 | $ | 444 | ||||||||||||||||||
| Energy and other revenues | 1,156 | 1,042 | 2,035 | 1,331 | ||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 55 | 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), net | 108 | 57 | (184) | 196 | ||||||||||||||||||||||
| Interest expense and other finance charges | (176) | (163) | (359) | (325) | ||||||||||||||||||||||
| Reorganization income (expense), net | — | 799 | (812) | — | ||||||||||||||||||||||
| Consolidation of subsidiary gain (loss) | — | — | (170) | — | ||||||||||||||||||||||
| Other non-operating income (expense), net | 102 | 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 | 9 | (14) | (4) | — | ||||||||||||||||||||||
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 134 | $ | 479 | $ | (1,289) | $ | (977) | ||||||||||||||||||
| Per Common Share (Successor) | ||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | 2.27 | N/A | N/A | N/A | |||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | $ | 2.26 | N/A | N/A | N/A | |||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 59,029 | N/A | N/A | N/A | ||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 59,399 | N/A | N/A | N/A | ||||||||||||||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-40
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| (Millions of Dollars) | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
Net Income (Loss) | $ | 143 | $ | 465 | $ | (1,293) | $ | (977) | ||||||||||||||||||
| Other Comprehensive Income (Loss) | ||||||||||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | 2 | 6 | (69) | (13) | ||||||||||||||||||||||
| Postretirement benefit actuarial gain (loss), net | (38) | — | (15) | 151 | ||||||||||||||||||||||
| Income tax benefit (expense) | 8 | (2) | 31 | (35) | ||||||||||||||||||||||
Gains (losses) arising during the period, net of tax | (28) | 4 | (53) | 103 | ||||||||||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net | 7 | 4 | 33 | 2 | ||||||||||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | — | (1) | (2) | (2) | ||||||||||||||||||||||
| Postretirement benefit prior service (credits) costs, net | — | — | 1 | 1 | ||||||||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net | — | 2 | 27 | 52 | ||||||||||||||||||||||
| Income tax (benefit) expense | (2) | (3) | (21) | (14) | ||||||||||||||||||||||
Reclassifications from AOCI, net of tax | 5 | 2 | 38 | 39 | ||||||||||||||||||||||
Total Other Comprehensive Income (Loss) | (23) | 6 | (15) | 142 | ||||||||||||||||||||||
Comprehensive Income (Loss) | 120 | 471 | (1,308) | (835) | ||||||||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | 9 | (14) | (4) | — | ||||||||||||||||||||||
Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 111 | $ | 485 | $ | (1,304) | $ | (835) | ||||||||||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-41
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
| Successor | Predecessor | |||||||||||||
| December 31, | December 31, | |||||||||||||
| (Millions of Dollars. except share data) | 2023 | 2022 | ||||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | 400 | $ | 724 | ||||||||||
| Restricted cash and cash equivalents (Note 20) | 501 | 264 | ||||||||||||
| Accounts receivable, net (Note 6) | 137 | 408 | ||||||||||||
| Inventory, net (Note 8) | 375 | 457 | ||||||||||||
| Derivative instruments (Notes 5 and 14) | 89 | 2,165 | ||||||||||||
| Other current assets | 52 | 247 | ||||||||||||
Total current assets | 1,554 | 4,265 | ||||||||||||
| Property, plant and equipment, net (Note 10) | 3,839 | 4,705 | ||||||||||||
| Nuclear decommissioning trust funds (Notes 9 and 14) | 1,575 | 1,400 | ||||||||||||
| Derivative instruments (Notes 5 and 14) | 6 | 228 | ||||||||||||
| Other noncurrent assets | 147 | 124 | ||||||||||||
Total Assets | $ | 7,121 | $ | 10,722 | ||||||||||
| Liabilities and Equity | ||||||||||||||
| Revolving credit facilities (Notes 13 and 14) | $ | — | $ | 848 | ||||||||||
| Long-term debt, due within one year (Notes 13 and 14) | 9 | 1,010 | ||||||||||||
| Accrued interest | 32 | 278 | ||||||||||||
| Accounts payable and other accrued liabilities | 344 | 454 | ||||||||||||
| Derivative instruments (Notes 5 and 14) | 32 | 1,927 | ||||||||||||
| Other current liabilities | 69 | 346 | ||||||||||||
Total current liabilities | 486 | 4,863 | ||||||||||||
| Long-term debt (Notes 13 and 14) | 2,811 | 2,494 | ||||||||||||
| Liabilities subject to compromise (Note 4) | — | 2,825 | ||||||||||||
| Derivative instruments (Notes 5 and 14) | 11 | 363 | ||||||||||||
| Postretirement benefit obligations (Note 15) | 368 | — | ||||||||||||
| Asset retirement obligations and accrued environmental costs (Note 11) | 469 | 567 | ||||||||||||
| Deferred income taxes (Note 7) | 407 | 75 | ||||||||||||
| Other noncurrent liabilities | 35 | 17 | ||||||||||||
Total Liabilities | 4,587 | 11,204 | ||||||||||||
| Commitments and Contingencies (Note 12) | ||||||||||||||
| Stockholders’ (Successor) / Member’s (Predecessor) Equity | ||||||||||||||
| Member’s equity | — | (573) | ||||||||||||
Common stock - $0.001 par value (a) (Note 16) | — | — | ||||||||||||
| Additional paid-in capital | 2,346 | — | ||||||||||||
| Accumulated retained earnings (deficit) | 134 | — | ||||||||||||
| Accumulated other comprehensive income (loss) | (23) | — | ||||||||||||
Total Stockholders’(Successor) / Member’s (Predecessor) Equity | 2,457 | (573) | ||||||||||||
Noncontrolling interests | 77 | 91 | ||||||||||||
Total Equity | 2,534 | (482) | ||||||||||||
Total Liabilities and Equity | $ | 7,121 | $ | 10,722 | ||||||||||
__________________
(a)As of December 31, 2023 (Successor): 350,000,000 shares authorized; 59,028,843 shares issued and outstanding.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-42
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| (Millions of Dollars) | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Operating Activities | ||||||||||||||||||||||||||
| Net income (loss) | $ | 143 | $ | 465 | $ | (1,293) | $ | (977) | ||||||||||||||||||
| Non-cash reconciliation adjustments: | ||||||||||||||||||||||||||
| Unrealized (gains) losses on derivative instruments | (40) | 65 | (647) | 684 | ||||||||||||||||||||||
| (Gain) loss on consolidation of Cumulus Digital Holdings | — | — | 170 | — | ||||||||||||||||||||||
| Nuclear fuel amortization | 108 | 33 | 94 | 96 | ||||||||||||||||||||||
| Depreciation, amortization and accretion | 157 | 208 | 549 | 555 | ||||||||||||||||||||||
| Impairments | 3 | 381 | — | — | ||||||||||||||||||||||
| Operational restructuring | — | — | 488 | — | ||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) | (78) | (43) | 227 | (158) | ||||||||||||||||||||||
| Deferred income taxes | 55 | 195 | (48) | (324) | ||||||||||||||||||||||
| Reorganization (income) expense, net | — | (933) | 99 | — | ||||||||||||||||||||||
| Other | — | (43) | 200 | (150) | ||||||||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||||||||
| Accounts receivable, net | 8 | 261 | (298) | 24 | ||||||||||||||||||||||
| Inventory, net | (68) | 10 | (55) | 72 | ||||||||||||||||||||||
| Other assets | 147 | 103 | (46) | (138) | ||||||||||||||||||||||
| Accounts payable and accrued liabilities | (49) | (74) | 187 | 24 | ||||||||||||||||||||||
| Accrued interest | 28 | (124) | 250 | 3 | ||||||||||||||||||||||
| Other liabilities | (12) | (42) | 310 | (5) | ||||||||||||||||||||||
| Net cash provided by (used in) operating activities | 402 | 462 | 187 | (294) | ||||||||||||||||||||||
| Investing Activities | ||||||||||||||||||||||||||
| Property, plant and equipment expenditures | (116) | (138) | (232) | (142) | ||||||||||||||||||||||
| Nuclear fuel expenditures | (45) | (49) | (80) | (82) | ||||||||||||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds | 1,265 | 949 | 2,243 | 1,817 | ||||||||||||||||||||||
| Nuclear decommissioning trust funds investment purchases | (1,290) | (959) | (2,271) | (1,834) | ||||||||||||||||||||||
| Equity investments in affiliates | (5) | (8) | (162) | (65) | ||||||||||||||||||||||
| Proceeds from the sale of non-core assets | 8 | 46 | — | — | ||||||||||||||||||||||
| Increase (decrease) in cash and restricted cash due to consolidation of subsidiaries | — | — | 123 | — | ||||||||||||||||||||||
| Other investing activities | 12 | 2 | 11 | 26 | ||||||||||||||||||||||
Net cash provided by (used in) investing activities | (171) | (157) | (368) | (280) | ||||||||||||||||||||||
F-43
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| (Millions of Dollars) | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
| Financing Activities | ||||||||||||||||||||||||||
| Talen Energy Supply long-term debt issuance proceeds | — | — | — | 131 | ||||||||||||||||||||||
| Contributions from member | — | 1,393 | — | — | ||||||||||||||||||||||
| Exit Financings proceeds, net of discount | — | 2,219 | — | — | ||||||||||||||||||||||
| Repayment of Prepetition Secured Indebtedness | — | (3,898) | — | — | ||||||||||||||||||||||
| Payment of make-whole premiums on Prepetition Secured Indebtedness | — | (152) | — | — | ||||||||||||||||||||||
| DIP Facilities proceeds, net | — | — | 987 | — | ||||||||||||||||||||||
| TLB proceeds, net | 288 | — | — | — | ||||||||||||||||||||||
| Talen Energy Supply long-term debt repayments | — | — | — | (114) | ||||||||||||||||||||||
| Talen Deferred Capacity Obligation issuance proceeds | — | — | — | 370 | ||||||||||||||||||||||
| Prepetition Deferred Capacity Obligations repayments | — | — | (176) | (209) | ||||||||||||||||||||||
| LMBE-MC TLB payments | (294) | (7) | (52) | (27) | ||||||||||||||||||||||
| Cumulus Digital TLF payments | (15) | — | — | — | ||||||||||||||||||||||
| Prepetition Inventory Repurchase Obligations, net increase (decrease) | — | — | (165) | — | ||||||||||||||||||||||
| Prepetition CAF proceeds | — | — | 62 | 827 | ||||||||||||||||||||||
| Prepetition CAF repayments, net | — | — | (62) | — | ||||||||||||||||||||||
| Deferred finance costs | (7) | (74) | (59) | (23) | ||||||||||||||||||||||
| Repurchase of warrants | (40) | — | — | — | ||||||||||||||||||||||
| Repurchase of Riverstone noncontrolling interest | (19) | — | — | — | ||||||||||||||||||||||
| Derivatives with financing elements | — | (20) | (104) | — | ||||||||||||||||||||||
| Other | 3 | — | (5) | 1 | ||||||||||||||||||||||
Net cash provided by (used in) financing activities | (84) | (539) | 426 | 956 | ||||||||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents | 147 | (234) | 245 | 382 | ||||||||||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | 754 | 988 | 743 | 361 | ||||||||||||||||||||||
End of period cash and cash equivalents and restricted cash and cash equivalents | $ | 901 | $ | 754 | $ | 988 | $ | 743 | ||||||||||||||||||
See Note 20 in Notes to the Annual Financial Statements for supplemental cash flow information.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-44
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF EQUITY
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Member’s Equity | Noncontrolling Interest | Total Equity | |||||||||||||||||||||||||||||||||||||
December 31, 2021 (Predecessor) | — | $ | — | $ | — | $ | — | $ | 733 | $ | — | $ | 733 | |||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | (1,289) | (4) | (1,293) | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (15) | — | (15) | |||||||||||||||||||||||||||||||||||||
| Non-cash consolidation of affiliate subsidiary | — | — | — | — | — | 71 | 71 | |||||||||||||||||||||||||||||||||||||
| Non-cash distribution to member | — | — | — | — | (2) | — | (2) | |||||||||||||||||||||||||||||||||||||
| Non-cash contribution from member | — | — | — | — | — | 17 | 17 | |||||||||||||||||||||||||||||||||||||
| Cash contribution | — | — | — | — | — | 7 | 7 | |||||||||||||||||||||||||||||||||||||
December 31, 2022 (Predecessor) | — | — | — | — | (573) | 91 | (482) | |||||||||||||||||||||||||||||||||||||
December 31, 2022 (Predecessor) | — | — | — | — | (573) | 91 | (482) | |||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 479 | (14) | 465 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | 6 | — | 6 | |||||||||||||||||||||||||||||||||||||
Cancellation of member’s equity (b) | — | — | — | — | 88 | — | 88 | |||||||||||||||||||||||||||||||||||||
Issuance of member’s equity (b) | — | — | — | — | 2,313 | — | 2,313 | |||||||||||||||||||||||||||||||||||||
Issuance of warrants (b) | — | — | — | — | 8 | — | 8 | |||||||||||||||||||||||||||||||||||||
| Common equity from member’s equity exchange | 59,029 | 2,321 | — | — | (2,321) | — | — | |||||||||||||||||||||||||||||||||||||
Non-cash contributions (c) | — | — | — | — | — | 38 | 38 | |||||||||||||||||||||||||||||||||||||
Non-cash distributions, net (d) | — | — | — | — | — | (5) | (5) | |||||||||||||||||||||||||||||||||||||
May 17, 2023 (Predecessor) | 59,029 | 2,321 | — | — | — | 110 | 2,431 | |||||||||||||||||||||||||||||||||||||
May 18, 2023 (Successor) | 59,029 | 2,321 | — | — | — | 110 | 2,431 | |||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | 134 | — | — | 9 | 143 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | (23) | — | — | (23) | |||||||||||||||||||||||||||||||||||||
| Repurchase of NCI | — | 5 | — | — | — | (24) | (19) | |||||||||||||||||||||||||||||||||||||
| Cash contribution | — | — | — | — | — | 1 | 1 | |||||||||||||||||||||||||||||||||||||
Non-cash distributions (d) | — | — | — | — | — | (20) | (20) | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | 19 | — | — | — | — | 19 | |||||||||||||||||||||||||||||||||||||
| Other | — | 1 | — | — | — | 1 | 2 | |||||||||||||||||||||||||||||||||||||
December 31, 2023 (Successor) | 59,029 | $ | 2,346 | $ | 134 | $ | (23) | $ | — | $ | 77 | $ | 2,534 | |||||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Pursuant to the Plan of Reorganization: (i) existing equity interests were canceled; and (ii) new equity interests and equity-classified warrants were issued.
(c)Relates to contributions of cryptocurrency mining machines by TeraWulf to Nautilus.
(d)Relates primarily to a distribution of cryptocurrency mining machines or Bitcoin to TeraWulf.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-45
TALEN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO THE ANNUAL FINANCIAL STATEMENTS
Capitalized terms and abbreviations appearing in these Notes to the Annual Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted.
“TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. For periods after May 17, 2023, the terms “Talen,” “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 to TES and its consolidated subsidiaries, unless the context clearly indicates otherwise. See “Reverse Acquisition” in Note 2 for information on an accounting reverse acquisition that occurred at Emergence.
This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary.
1. Organization and Operations
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, ERCOT, and WECC, with our generation fleet principally located in the Mid-Atlantic, Texas, and Montana. While the majority of our generation is already produced at zero-carbon nuclear and lower-carbon gas-fired facilities, we are reducing the carbon profile of our fleet through conversions and retirements of wholly-owned coal facilities. In addition, we are developing a hyperscale data center campus adjacent to our zero-carbon Susquehanna nuclear facility that will utilize carbon-free, low-cost energy provided directly from the plant. 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. As of December 31, 2023 (Successor), our generation capacity was 12,374 MW (summer rating). Talen is headquartered in Houston, Texas.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Annual Financial Statements, which are prepared in accordance with GAAP, include: (i) the accounts of all controlled subsidiaries; (ii) elimination adjustments for intercompany transactions between controlled subsidiaries; (iii) any undivided interests in jointly owned facilities consolidated on a proportionate basis; and (iv) all adjustments considered necessary for a fair presentation of the information set forth. All adjustments are of a normal recurring nature except as otherwise disclosed.
Fresh Start Accounting. After Emergence, TES applied fresh start accounting, which resulted in a new basis of accounting as the Company became a new financial reporting entity. As a result of the application of fresh start accounting and the implementation of the Plan of Reorganization, our financial position and results of operations beginning after Emergence are not comparable to our financial position or results of operations prior to that date. Accordingly, the financial results are presented for: (i) the Predecessor period from January 1 through May 17, 2023; and (ii) the Successor period from May 18 through December 31, 2023. The Annual Financial Statements and Notes thereto have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
F-46
Reverse Acquisition. In May 2022, TEC deconsolidated TES for financial reporting purposes because TEC no longer controlled the activities of TES when TES and the other initial Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. Under the terms of the Restructuring, TEC regained control of TES at Emergence, which resulted in TEC’s reconsolidation of TES. The combination was accounted for as a reverse acquisition in which TEC was the legal acquirer and TES was the accounting acquirer. Such conclusion was based on an assessment of the Plan of Reorganization’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. Specifically, a conversion of $2.3 billion of member’s equity of TES into 59,028,843 shares of new TEC common stock and equity-classified warrants to purchase common stock issued in accordance with the Plan of Reorganization, which is presented as “Common equity from member’s equity exchange” in the Consolidated Statements of Equity.
Accordingly, our Annual Financial Statements are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer. This accounting acquirer determination was primarily based on the following facts and circumstances: (i) TES operations comprise substantially all of the ongoing operations of the combined entity; (ii) certain former TES creditors received substantially all voting interests of the combined entity; (iii) certain former TES creditors assumed the power to appoint or remove board members of the combined entity; (iv) TES employs senior management and all employees of the combined entity; and (v) TEC, prior to Emergence, did not have any operations or material assets separate from TES.
The economic substance and related accounting were also used in the determination of fresh start accounting applicability. See Note 4 for additional information on fresh start accounting. See Note 3 for additional information on the legal structure of the Restructuring transactions.
Consolidation of an Affiliate’s Subsidiary. In September 2022, TES and its Talen Growth subsidiary exchanged their preferred units in Cumulus Coin Holdings and Cumulus Data Holdings for common units in Cumulus Digital Holdings. Cumulus Coin Holdings and Cumulus Data Holdings were then consolidated by TEC. Following the consummation of the exchange and other related transactions, TES became the primary beneficiary of Cumulus Digital Holdings, a VIE, due to its ability to control the activities that most significantly impact Cumulus Digital Holdings. Accordingly, Cumulus Digital Holdings and its subsidiaries were consolidated by TES as of September 30, 2022. The difference between: (i) the fair value of Cumulus Digital Holdings and its subsidiaries; and (ii) the carrying value of preferred units immediately before the exchange resulted in a loss of $170 million presented as “Consolidation of subsidiary gain (loss)” on the Consolidated Statements of Operations for the year ended December 31, 2022 (Predecessor).
Summary of Significant Accounting Policies
Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity or cash flows.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
F-47
Restructuring Effects. Prepetition liabilities and obligations whose treatment and satisfaction were dependent on the outcome of the Restructuring are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. The carrying value of prepetition liabilities that were subject to compromise are presented at the best estimate of the claim amount permitted by the Bankruptcy Court. Such amounts presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets were subject to adjustments depending on Bankruptcy Court actions, developments with respect to disputed claims, determination of secured status of certain claims, the determination as to the value of any collateral securing claims, proof of claims and (or) other events. Additionally, any income, expenses, gains or losses that were incurred or realized as a direct result of the Restructuring since the Petition Date are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations.
As of the Petition Date, the Talen Filing Parties ceased recognizing interest expense on certain outstanding unsecured or under-secured prepetition indebtedness. Contractual interest expense represented amounts due under the terms of outstanding prepetition indebtedness. See Note 13 for information on this contractual interest.
See Note 3 for additional information on the Restructuring.
Fair Value of Financial Instruments and Derivatives. Talen carries a portion of its assets and liabilities at fair value that are measured at a reporting date using an exit price (i.e., the price that would be received to sell an asset or paid to transfer a liability). An exit price may be developed under a market approach utilizing market transactions, an income approach utilizing present value techniques, or a replacement cost approach. The exit prices are disclosed according to the quality of valuation inputs under a three-tiered hierarchy comprised of: (i) Level 1 inputs that are quoted prices (unadjusted) in active markets for identical assets or liabilities; (ii) Level 2 inputs that are other than quoted prices that are directly or indirectly observable; and (iii) Level 3 inputs that are unobservable inputs that are significant to the fair value of assets or liabilities.
The classification of an asset or liability is based on the lowest level of input significant to its fair value. Those that are initially classified as Level 3 are subsequently reported as Level 2 when the fair value derived from unobservable inputs is inconsequential to the overall fair value, or if corroborated market data becomes available. Assets and liabilities initially reported as Level 2 are subsequently reported as Level 3 if corroborated market data is no longer available. Transfers occur at the end of the reporting period. Level 3 positions at December 31, 2023 (Successor) and December 31, 2022 (Predecessor) were not material.
See Notes 5, 10, 14 and 15 for fair value disclosures.
Operating Revenues and Revenue Recognition. Operating revenues on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) “Capacity revenues;" (ii) “Energy revenues;” and (iii) “Unrealized gain (loss) on derivative instruments” for certain electricity contracts.
Capacity revenues. Includes amounts earned from auctions in ISOs and RTOs and under bilateral contracts to provide available generation capacity that is needed to satisfy system reliability and integrity requirements. Capacity revenues are recognized ratably over the PJM Capacity Year by Talen-owned generation facilities that participate in the auctions and stand ready to deliver generated power. Capacity revenues are based on invoiced amounts corresponding directly to the value provided over a specific time interval.
Energy revenues. Primarily includes: (i) amounts earned from sales to ISOs and RTOs for electric generation and ancillary services products that support transmission and grid operations; (ii) amounts earned for wholesale electricity sales to bilateral counterparties; and (iii) realized gains and losses on commodity derivative instruments.
Sales of each electric generation and ancillary services to ISOs and RTOs represent performance obligations recognized over time based on volumes delivered or services performed at contractually agreed upon day-ahead or real-time market prices.
Sales of wholesale electricity to bilateral counterparties represent performance obligations recognized over a contractually agreed period of time based on volumes delivered at the contractually agreed price.
F-48
Sales of electric generation, ancillary services, and wholesale electricity to bilateral counterparties are recognized based on invoiced amounts which corresponds directly with the value provided over a specific time interval.
Certain contracts constitute bundled agreements to sell energy, capacity, and (or) ancillary services. In such cases, all performance obligations are deemed to be delivered and (or) performed at the same time. Accordingly, as the timing of revenue recognition for all performance obligations is the same and occurs over a contractually agreed period of time, it is unnecessary to allocate transaction price to multiple performance obligations.
Realized gains and losses on commodity derivative instruments include the settlements of financial and physical power transactions utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within "Energy revenues" on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See "Energy Expenses" below for additional information on realized gains and losses of derivative instruments presented as "Fuel and energy purchases" on the Consolidated Statements of Operations.
Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain power contracts that qualify as derivative instruments. See "Derivative Instruments" below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See "Energy Expenses" below for additional information on unrealized gains and losses of derivative instruments presented as "Energy expenses" on the Consolidated Statements of Operations.
Nautilus Revenue Recognition and Remeasurement. The primary output of Nautilus’s ordinary business activities is providing hash calculation services to solve complex cryptographic algorithms in support of blockchain mining. Nautilus is party to a mining pool arrangement to provide an unspecified amount of its available hash calculations to an unaffiliated mining pool operator. Nautilus is entitled to an enforceable right to compensation from the mining pool operator only for the duration of time over which Nautilus provides its hash calculations.
In exchange for providing hash calculation services to the mining pool operator, Nautilus is entitled to consideration, whether or not the mining pool operator successfully solves a block, based on a ‘full-pay-per-share’ payout methodology. Nautilus’s only performance obligation is to provide hash calculations to the mining pool operator. If Nautilus does not provide hash calculations to the mining pool operator, no consideration is earned by Nautilus nor does Nautilus incur any penalties from the mining pool operator. The Bitcoin earned by Nautilus is all variable noncash consideration. Accordingly, Nautilus recognizes revenue that is measured at fair value using the quoted price for Bitcoin in Nautilus’s principal market at the beginning of each day (Coordinated Universal Time).
Bitcoin amounts held by Nautilus are: (i) accounted for as intangible assets with indefinite useful lives; (ii) sold on a first-in-first-out basis; and (iii) measured for impairment whenever indicators of impairment are identified based on its lowest intraday quoted Bitcoin price in Nautilus’s principal market for Bitcoin held at the end of each day. To the extent an impairment loss is recognized, a new carrying value is established. Bitcoin held at any individual reporting period is not material because the joint venture agreements require Nautilus to liquidate Bitcoin to support its operations and distribute excess Bitcoin, or proceeds from excess Bitcoin sales, to the joint venture owners no less frequently than once every two weeks. Accordingly, impairments and the gains or loss from Bitcoin sales are not material. See ASU 2023-08 under “Recent Accounting Pronouncements, Not Yet Adopted” for changes to accounting for Bitcoin.
See Note 6 for additional information on revenue.
Energy Expenses. Energy expenses on the Consolidated Statements of Operations are primarily comprised of items presented as: (i) "Fuel and energy purchases;" (ii) "Nuclear fuel amortization;" and (iii) "Unrealized gain (loss) on derivative instruments" for certain commodity purchase contracts.
Fuel and energy purchases. Primarily includes: (i) fuel costs; (ii) environmental product costs; and (iii) realized gain (loss) on commodity derivative instruments.
F-49
Fuel costs include the costs incurred by Talen-owned generation facilities for the conversion of natural gas, coal, and (or) oil products to electricity. Fuel for electric generation from natural gas purchases are recognized at the agreed price for natural gas delivered to the applicable generation facility over a contractually agreed period of time. Fuel for electric generation from coal and oil product inventories are recognized at the applicable weighted average inventory cost of volumes consumed.
Environmental product costs primarily include RGGIs and other emission product compliance costs that are mandated by certain states. The estimated cost of compliance is accrued at the time an obligation under the applicable terms of each state's environmental compliance program arises.
Realized gains and losses on commodity derivative instruments include the settlements of financial and physical fuel and environmental product contracts utilized for the Company’s commercial risk management objectives. Realized settlements of these derivative instruments are recognized and presented net within “Fuel and energy purchases” on the Consolidated Statements of Operations based on the delivery period of the underlying contract at contractually agreed prices. See “Operating Revenues” above for additional information on realized gains and losses on derivative instruments presented as “Energy revenues” on the Consolidated Statements of Operations.
Nuclear fuel amortization. Nuclear fuel-related costs, including procurement of uranium, conversion, enrichment, fabrication and assemblies, are capitalized and presented as “Property, plant and equipment, net” on the Consolidated Balance Sheets and presented as a cash outflow within the investing activities section on the Consolidated Statements of Cash Flows. Such costs are amortized as the fuel is consumed using the units-of-production method and presented as "Nuclear fuel amortization" on the Consolidated Statements of Operations.
Unrealized gain (loss) on derivative instruments. Includes unrealized gains and losses resulting from changes in the fair value of certain fuel contracts and environmental product contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Operating Revenues” above for additional information on unrealized gains and losses of derivative instruments presented as "Operating Revenues" on the Consolidated Statements of Operations.
Derivative Instruments. The fair value of derivative contracts required to be measured at fair value are presented as “Derivative instruments” within assets or liabilities on the Consolidated Balance Sheets. The primary type of derivative instruments utilized are commodity derivatives. Commodity derivative contracts are valued using inputs and assumptions such as contractual volumes, delivery location, forward commodity prices, commodity price volatility, discount rates, and credit worthiness of counterparties. For derivatives that trade in liquid markets, such as generic forwards, swaps, and options, the inputs and assumptions are generally observable. Such instruments are categorized in Level 2.
In most instances, master netting agreements govern derivative transactions between parties and contain certain provisions for setoff rights. The fair value of derivative instruments is presented net of setoff rights and cash collateral deposits. The fair value of commercial contracts that are not subject to netting and (or) collateral provisions is presented gross. Prior to Emergence, the fair value of derivative instruments presented on the Consolidated Balance Sheets was presented gross of setoff rights and cash collateral deposits exchanged between parties under such arrangements.
Unrealized gains or losses associated with a derivative instrument that economically hedges certain risks but where qualified cash flow hedge accounting is not elected or not met are presented on the Consolidated Statements of Operations in the period when such gains or losses arise. As there are no derivatives where qualified hedge accounting has been elected, changes in the fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments,” as a component of either “Operating Revenues” or “Energy Expenses” on the Consolidated Statements of Operations in a manner consistent with the presentation of net realized gains and losses. See "Operating Revenues" and "Energy Expenses" above for a discussion of net realized gains and losses on commodity derivatives. The cumulative net gains or losses for interest rate contracts are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Notes 5 and 14 for additional information on the presentation of derivative contracts and fair value measurements.
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Operation, Maintenance and Development. The costs of removal, repairs, maintenance, and other operating costs, pre-commercial development activities, and salaries and benefits for operations personnel that each do not meet capitalization criteria are recognized as an expense when incurred. Materials and supplies inventories are recognized as an expense at the weighted average cost of materials consumed as they are used for repairs and maintenance. Costs for pre-commercial development stages of certain projects that are not capitalized as “Property, plant, and equipment, net” on the Consolidated Balance Sheets and recurring operational and maintenance activities are each presented as "Operation, maintenance and development" on the Consolidated Statements of Operations. Development expenses incurred are primarily for pre-commercial activities at Nautilus and hyperscale construction activities at Cumulus Data.
Stock-Based Compensation. TEC grants performance stock units and restricted stock units to certain employees and non-employee directors. The fair value of performance stock units is estimated on the grant date utilizing a Monte Carlo Valuation Model, which contains significant unobservable inputs that are believed to be consistent with those used by principal market participants. The fair value of restricted stock units is derived from the closing price of TEC common stock at the grant date. Forfeitures are recognized as they occur. Unvested performance stock units and restricted stock units are entitled to dividends or dividend equivalents, which are accrued and distributed to award recipients at the time such awards vest. Dividends and dividend equivalents are subject to the same vesting and forfeiture provisions as the underlying awards. Stock-based compensation expense is recognized for both graded and cliff vesting awards on a straight-line basis over the requisite service period for the entire award. Stock-based compensation expense is presented as “General and administrative” on the Consolidated Statements of Operations.
See Note 17 for additional information on our stock-based compensation.
Income Taxes. TEC and its subsidiaries file a consolidated U.S. federal income tax return. Income taxes are accounted for under the asset and liability method. Deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying values of existing assets and liabilities and their respective tax basis, tax credits and NOL carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which temporary differences are expected to be recovered or settled. The effect on deferred tax assets and liabilities due to a change in tax rates is recognized as income in the period that includes the enactment date. Valuation allowances are recognized to reduce deferred tax assets to the extent necessary to result in an amount that is more likely than not to be realized. Disproportionate income tax effects are removed from AOCI when the circumstance upon which they are premised ceases to exist.
The financial statement effect of a tax position is recognized when it is more-likely-than-not, based on the technical merits, that the position will be sustained upon examination. A tax position that meets the more-likely-than-not recognition threshold is measured as the largest amount of tax benefit that is greater than 50% likely of being realized upon ultimate settlement with a taxing authority. A previously recognized tax position is reversed in the first period in which it is no longer more-likely-than-not that the tax position would be sustained upon examination. Interest and penalties from tax uncertainties are presented as "Income tax benefit (expense)" on the Consolidated Statements of Operations.
See Note 7 for additional information on income taxes.
Loss Contingencies. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. We continuously assess potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Loss contingencies are discounted when appropriate. Legal costs are expensed as incurred. See Note 12 for additional information.
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Concentrations of Credit Risk. Concentrations of credit risk exist primarily within cash and cash equivalents, receivables and commodity derivative assets. Cash and cash equivalents are generally held in accounts where the amounts deposited exceed the maximum deposit insurance provided by the Federal Deposit Insurance Corporation. Cash and cash equivalents and restricted cash balances are primarily deposited in accounts with major financial institutions with investment grade credit ratings. In certain instances, funds are invested in highly liquid U.S. Treasury securities or other obligations with original maturities of less than 90 days that are issued by or guaranteed by the U.S. Government. Concentrations of credit risk for receivables are primarily attributable to entities that reimburse Talen for certain capital expenditures and operating costs associated with jointly owned facilities. Concentrations of credit risk for commodity derivative assets are primarily attributable to unaffiliated investment grade counterparties which engage in energy marketing activities with Talen Energy Marketing. See Note 5 for additional information on concentrations of credit risk.
Nautilus is subject to concentrations of credit risk associated with its broker and custodial arrangements which provides Nautilus the ability to access markets to liquidate its Bitcoin and to temporarily store Bitcoin prior to liquidation or distribution. Because Nautilus liquidates Bitcoin to support its operations and distributes excess Bitcoin, or proceeds from excess Bitcoin sales, to the joint venture owners at least once every two weeks, Nautilus does not carry any insurance on its broker and custodial accounts.
Cash and Cash Equivalents. Bank deposits, liquid investments, and other similar assets with original maturities of three months or less. Bank deposits, commodity exchange deposits, liquid investments, and other similar assets with original maturities of three months or less that are restricted by agreement are presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets. See Note 20 for additional information.
Accounts Receivable. Receivables primarily consist of amounts due from customers, net of any collection allowances. Uncollected receivables greater than 30 days past due are assessed for collectability based on a variety of factors that include, but are not limited to, customer credit worthiness, duration receivables are outstanding, and (or) historical collection experience. Management continuously assesses and considers current economic trends that might impact the amount of future credit losses. Additionally, if it becomes known that a specific customer may have the inability to settle its obligation that is not yet past due, such receivables are assessed for collectability. If these assessments indicate a receivable collection is remote, its carrying value is reduced through an allowance for doubtful accounts measured at management’s best estimate, and a charge is presented on the Consolidated Statements of Operations. If any portion of the original carrying value of the receivable is recovered, the allowance and the associated charge are reversed in the period of collection.
Inventory. Inventory consists of fuel for generation (primarily coal and fuel oil), materials and supplies, and environmental products each of which are valued at the lower of weighted average cost or net realizable value. See Note 8 for additional information on inventory.
Leases. Operating leases primarily relate to office space. Right-of-use assets and lease liabilities are recognized at lease commencement for leases with a term greater than 12 months. Lease terms include options to extend or terminate the lease if Talen is reasonably certain to exercise such options. These leases do not contain any material restrictive covenants or residual value guarantees. Talen has elected to not separate lease and non-lease components for all classes of assets. Right-of-use assets are measured as the present value of lease payments over the lease term. The discount rate used is the rate implicit in the lease if readily available or the Company’s incremental borrowing rate.
Talen has elected to not recognize the right of use assets and the lease liabilities arising from leases with a short-term duration. A short-term lease is less than 12 months and does not include a purchase option or an option to extend beyond 12 months that Talen is reasonably certain to exercise.
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Right-of-use assets are presented as “Other current assets” and “Other noncurrent assets” on the Consolidated Balance Sheets and lease liabilities are presented as “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets. The carrying value of right-of-use assets and lease liabilities and estimated future lease payments were a non-material amount as of December 31, 2023 (Successor). Additionally, lease expense was a non-material amount for the periods: (i) January 1 through May 17, 2023 (Predecessor); (ii) May 18 through December 31, 2023 (Successor); and (iii) the years ended December 31, 2022 (Predecessor) and December 31, 2021 (Predecessor).
Variable Interest Entities. The primary beneficiary (a controlling financial interest) of a VIE is required to consolidate the VIE when it has both: (i) the power to direct the activities that most significantly impact the entity’s economic performance; and (ii) the obligation to absorb losses or receive benefits from the entity that could potentially be significant to the VIE. Talen consolidates a VIE when it is determined that it is the primary beneficiary of the VIE. Investments in entities in which Talen has the ability to exercise significant influence but does not have a controlling financial interest are accounted for under the equity method.
Investments in Debt and Equity Securities. The NDT holds investments in available-for-sale debt securities and equity securities, which are carried at fair value and presented as "Nuclear decommissioning trust funds" on the Consolidated Balance Sheets.
Unrealized gains and losses, net of income tax, on available-for-sale debt securities are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income in the period when such gains and losses arise. Realized gains and losses on available-for-sale debt securities are transferred from AOCI to “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when the sale of the security occurs. The specific identification method is used to calculate realized gains and losses on debt and equity securities. If an available-for-sale debt security's fair value declines below cost and the decline is determined to be other-than-temporary, the unrealized loss is recognized on the Consolidated Statements of Comprehensive Income in the period when such determination arises.
Unrealized gains and losses and realized gains and losses on equity securities are presented as “Nuclear decommissioning trust funds gain (loss), net” on the Consolidated Statements of Operations in the period when such gains or losses arise.
See Notes 9 and 14 for additional information on investments in debt and equity securities.
Property, Plant and Equipment. Expenditures for land, the construction of facilities, the addition or refurbishment of major equipment, and commercially viable new development projects are capitalized at cost. Such capitalized amounts include interest costs, where appropriate. Facilities, land, and other equipment acquired in a business combination is recognized at fair value. In each case, such amounts are presented as "Property, plant, and equipment, net" on the Consolidated Balance Sheets. Reductions in the carrying value of property, plant and equipment are accumulated over the estimated useful life of each depreciable unit using straight-line or group depreciation methods, where appropriate. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. Generally, upon normal retirement of property, plant, and equipment under the group depreciation method, the costs of such assets are retired against accumulated depreciation in the period of the retirement and no gain or loss is recognized. Any remaining carrying value of property, plant and equipment at its retirement date that depreciated under the straight-line depreciation method is presented as a loss within "Other operating income (expense), net" on the Consolidated Statements of Operations. Any remaining carrying value of property, plant and equipment at its sale date and any proceeds from the disposition are presented as a gain or loss net on the Consolidated Statements of Operations.
Expenditures for intangible assets such as contractual rights, software and licenses are capitalized at cost and are presented as "Property, plant and equipment, net" on the Consolidated Balance Sheets. Reductions in the carrying value of intangible assets with finite useful lives are accumulated over the estimated useful life of each intangible asset using an amortization pattern which reflects the economic benefits of the intangible asset. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations.
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See “Impairments” below for additional information regarding impairments on the carrying values of property, plant and equipment.
See Note 10 for additional information on property, plant and equipment.
Impairments. Property, plant and equipment used in operations are assessed for impairment whenever changes in facts and circumstances indicate the carrying value of the asset group may not be recoverable. Indicators of impairment may include changes in the economic environment, negative financial trends, physical damage to assets or decisions of management regarding strategic initiatives. Where applicable, individual assets are grouped for impairment purposes at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other assets and liabilities. If there is an indication the carrying value of an asset group may not be recovered, management reviews the expected future cash flows of the asset group. If the sum of the undiscounted pre-tax cash flows is less than the carrying value of the asset group, the asset group is written down to its estimated fair value. Impairment charges are presented as "Impairments" on the Consolidated Statements of Operations in the period in which the impairment condition arises. If facts and circumstances indicate that the carrying value of an asset under construction will have no future economic benefit, such amounts are presented on the Consolidated Statements of Operations in the period in which such projects are abandoned, canceled, or management otherwise determines the costs to be unrecoverable.
Fair value may be determined by a variety of valuation methods including third-party appraisals, market prices of similar assets, and present value techniques. However, as there is generally a lack of quoted market prices for long-lived assets, the fair value of impaired assets is typically determined based on the present values of expected future cash flows using discount rates that are believed to be consistent with those used by principal market participants. The estimated cash flows and related fair value computations consider all available evidence at the date of the review, such as estimated future generation volumes, forward capacity and commodity prices, energy prices, operating costs, capital expenditures, and environmental costs.
See Note 10 for information on impairments.
Asset Retirement Obligations. A liability for an ARO or conditional ARO exists when a legal obligation arises from laws, regulations or other contractual requirements for the retirement of tangible long-lived assets. When an ARO liability is incurred, which is typically at asset construction or through assumption of the liability in connection with a business combination, it is initially recognized at fair value. Fair value measurements are estimated under a present value technique and are discounted using a credit-adjusted risk-free rate. Additionally, given the inherent uncertainty in estimating the amount of cash flows to settle an ARO liability or its settlement date, fair value estimates include a market risk premium and a range of possible cash flow outcomes, where applicable. At the initial recognition, the effects on the Consolidated Balance Sheets include: (i) an increase to “Asset retirement obligations and accrued environmental costs” for the portion of ARO to be settled after one year and (or) “Other current liabilities” for the portion of the ARO to be settled within one year; and (ii) an offsetting increase to “Property, plant, and equipment” for the asset retirement capitalized cost. Estimated future ARO cash expenditures and settlement dates are reviewed periodically to identify any required amendments to the carrying value of each ARO liability.
ARO liabilities increase over a period of time through the recognition of accretion expense to recognize changes in the obligation due to the passage of time. The asset retirement capitalized cost is depreciated at a rate consistent with the useful life of the associated long-lived asset. The depreciation of the asset retirement capitalized cost and the accretion of the ARO liability are each presented as "Depreciation, amortization and accretion" on the Consolidated Statements of Operations. An ARO liability amendment associated with a long-lived asset that is not fully impaired or depreciated is recognized through an adjustment to the ARO liability and the asset retirement capitalized cost. Any revision to the asset retirement capitalized cost is generally depreciated over the remaining life of the associated long-lived asset. An ARO liability amendment associated with a fully impaired or depreciated asset is presented as "Other operating income (expense), net" on the Consolidated Statements of Operations. At settlement, a gain or loss will arise if the cash expenditures to settle the ARO liabilities are different than the carrying values. Such gains or losses are presented as "Other operating income (expense), net" on the Consolidated Statements of Operations.
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A conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement is conditional on a future event that may or may not be within the entity’s control. There may also be instances when there is no available information regarding the ultimate ARO settlement timing or the fair value of the obligation may not be reasonably estimable. If sufficient information becomes available to reasonably estimate the fair value of the liability for an ARO or a conditional ARO, a liability is recognized in the period in which it is determined.
See Note 11 for additional information on AROs.
Contingencies. Management continuously assesses potential loss contingencies for environmental remediation, litigation claims, regulatory penalties and other events. Potential losses are accrued when: (i) information is available that indicates it is probable (i.e., likely to occur) that a loss has been incurred, given the likelihood of the uncertain future events; and (ii) the amount of the loss can be reasonably estimated. Loss contingencies are recognized at management's best estimate, which may be discounted, where appropriate. Loss contingencies exclude estimates for any legal fees, which are recognized as incurred when the legal services are performed. See Note 12 for additional information on loss contingencies.
Business interruption insurance proceeds are considered gain contingencies and not recognized until realized.
Debt. Proceeds received on the issuance of new term loans, secured notes, unsecured notes, bonds, and similar indebtedness are presented as “Long-term debt” or “Long-term debt, due within one year” on the Consolidated Balance Sheets. Interest incurred as paid-in-kind, whether accrued or capitalized as additional principal are presented as “Long-term debt” with the associated outstanding amounts of indebtedness. Costs incurred to issue new indebtedness and any original issuance discounts or premiums are deferred at issuance on the Consolidated Balance Sheets and presented together with the associated outstanding principal amounts of indebtedness.
Interest accrues on outstanding principal amounts of indebtedness based on contractually determined rates during each period. Costs incurred for the issuance of indebtedness and any original issuance discounts or premiums are subsequently amortized through the expected maturity date of the associated indebtedness under the effective interest rate method and are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
Gains and losses on the: (i) early redemption of indebtedness; or (ii) early termination and (or) reduction of revolving credit facility committed capacity are presented as a gain or loss on the Consolidated Statements of Operations. Such amounts include the proportional derecognition of any deferred financing costs, fees, discounts, and (or) premiums associated with the indebtedness.
Direct cash borrowings under secured lines of credit, revolving credit facilities, and similar indebtedness are presented as “Revolving credit facilities” on the Consolidated Balance Sheets. Costs incurred to issue new arrangements are deferred and presented as “Other current assets” or “Other non-current assets” on the Consolidated Balance Sheets. Interest accrues on direct cash borrowings and LCs based on contractually determined rates during each period.
Costs incurred to issue new arrangements are subsequently amortized through the expected expiration of the associated arrangement under the straight-line method. Commitment fees on available but unused credit facility capacity are expensed as incurred. Such costs are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Note 13 for additional information on debt.
Postretirement Benefit Obligations. Talen sponsors or participates in, as applicable, various qualified and non-qualified defined benefit pension plans and other postretirement benefit plans. Gains and losses, net of income tax, that arise and are not a component of net periodic defined benefit costs are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statements of Comprehensive Income.
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Following Emergence, actuarial gains and losses in excess of the greater of 10% of the plan's projected benefit obligation or the market-related value of plan assets are amortized over (i) the expected average remaining service period of active plan participants for active plans; or (ii) the average future remaining lifetime of the plan participants of frozen plans. Prior to Emergence, Talen used an accelerated amortization method for the recognition of gains and losses for defined benefit pension plans: (i) actuarial gains and losses in excess of 30% of the plan's projected benefit obligation are amortized on a straight-line basis over one-half of the expected average remaining service of active plan participants; and (ii) actuarial gains and losses in excess of 10% of the greater of the plan's projected benefit obligation or the market-related value of plan assets and less than 30% of the plan's projected benefit obligation are amortized on a straight-line basis over the expected average remaining service period of active plan participants.
Following Emergence, a spot rate curve that represents a portfolio of high-quality corporate bonds is used to develop the discount rate utilized to measure the projected benefit obligations and service costs for benefit plans. Prior to Emergence, a bond matching methodology was utilized, based on a specific portfolio of bonds that closely match the overall cash flow timing and duration of the benefit plans.
Talen is obligated to provide health care benefits under the Coal Act and pneumoconiosis (black lung) benefits under the Black Lung Act for retired miners and eligible beneficiaries. Benefits are funded from a VEBA trust and a trust maintained under certain federal and state black lung legislation. Shortfalls in funded status of the plans are assessed as contingent liabilities. As such, Talen recognizes funding shortfalls on its balance sheet, where applicable, if benefit obligations of either plan exceed the fair value of available trust assets.
See Note 15 for additional information about the plans and the accounting for defined benefits.
Recent Accounting Pronouncements, Not Yet Adopted
ASU 2023-07. In November 2023, the FASB issued ASU 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures. This ASU requires enhanced disclosures about significant segment expenses. The ASU is effective for fiscal years beginning after December 15, 2023, and interim periods within fiscal years beginning after December 15, 2024. Early adoption is permitted. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
ASU 2023-08. In December 2023, the FASB issued ASU 2023-08, Intangibles—Goodwill and Other—Crypto Assets (Subtopic 350-60): Accounting for and disclosure of Crypto Assets. This ASU requires cryptocurrency assets to be measured at fair value with changes in fair value recognized in net income. The amendments also require disclosures on significant cryptocurrency holdings, contractual sale restrictions, and changes during the reporting period. The ASU is effective for fiscal years beginning after December 15, 2024, including interim periods within those fiscal years. Early adoption is permitted for both interim and annual financial statements that have not yet been issued. Nautilus is evaluating the impact of this ASU and expects to adopt it in the required period.
ASU 2023-09. In December 2023, the FASB issued ASU 2023-09 Income Taxes (Topic 740): Improvements to Income Tax Disclosures. This ASU requires annual disclosures for specific categories in the rate reconciliation and additional information for reconciling items that meet a quantitative threshold. The ASU is effective for annual periods beginning after December 15, 2024. Early adoption is permitted for annual financial statements that have not yet been issued. The Company is evaluating the disclosure impact of this ASU and expects to adopt it in the required period.
3. Talen Emergence from Restructuring
Voluntary Reorganization Under Chapter 11 of the U.S. Bankruptcy Code
In May 2022, TES and the other initial Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. In December 2022, TEC became a Debtor in the Restructuring in order to facilitate certain transactions contemplated by the Plan of Reorganization. The Plan of Reorganization was approved by the requisite parties in November 2022, was confirmed by the Bankruptcy Court in December 2022, and was consummated and became effective in May 2023, when the Debtors emerged from the Restructuring.
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Settlements, Restructuring Support Agreement, and Backstop Commitment Letter
Prior to and during the Restructuring, the Debtors reached a number of settlements with certain stakeholders in the Restructuring (including certain holders of claims under the Prepetition Unsecured Notes, Prepetition CAF, Prepetition TLB, and Prepetition Secured Notes, as well as Riverstone and TEC), each of which resolved outstanding issues among the Debtors and those parties. These settlements were agreed to in the RSA. An additional settlement was reached with the Official Committee of Unsecured Creditors of the Debtors, which resolved all of the Committee’s outstanding issues in the Restructuring. The terms of the RSA and the settlements were incorporated into the final Plan of Reorganization.
Pursuant to the settlements, the settling parties agreed to support the Plan of Reorganization and the Restructuring transactions outlined below, which included a common equity Rights Offering of up to $1.9 billion. The Backstop Parties, comprised of certain holders of claims under the Prepetition Unsecured Notes, also entered into the Backstop Commitment Letter, under which they agreed to purchase up to $1.55 billion of the new equity offered in the Rights Offering to the extent not fully subscribed. As consideration for their backstop commitments, the Backstop Parties became entitled to subscription rights to purchase 30% of the new equity issued in the Rights Offering and a Backstop Premium payment in the form of cash and (or) new equity. Pursuant to the Rights Offering, TEC raised $1.4 billion of additional equity capital.
Plan of Reorganization and Emergence from Restructuring
The Plan of Reorganization implemented, among other things, the transactions contemplated by the RSA and the related settlements. The Restructuring was completed, and the Debtors emerged from the Restructuring, on May 17, 2023. Pursuant to the Plan of Reorganization, among other things:
•Claims against TEC were paid in full in cash or reinstated. All existing equity interests in TEC were extinguished, and new equity interests in TEC were issued as follows:
◦Holders of 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 new 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; (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 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 share of approximately $2.1 billion, as agreed in the relevant settlement.
◦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 to 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 for additional information on the PPL/Talen Montana litigation and the related settlement.
4. Fresh Start Accounting
At Emergence, TES adopted fresh start accounting as: (i) the holders of existing voting shares before the consummation of the Plan of Reorganization received less than 50% of the voting shares of the Successor; and (ii) the reorganization value of TES’s assets immediately prior to confirmation of the Plan of Reorganization of $7.8 billion was less than the total of post-petition liabilities and allowed claims of $9.8 billion. Accordingly, TES allocated its reorganization value to its individual assets based on their estimated fair values.
Reorganization Value
Reorganization value is derived from an estimate of enterprise value, or the fair value of the Company’s interest-bearing debt and member’s equity. As negotiated in the Plan of Reorganization and related disclosure statement approved by the Bankruptcy Court, the enterprise value as of Emergence was $4.5 billion. Management engaged third-party valuation advisors to assist in estimating the enterprise value and allocating the enterprise value to the assets and liabilities for financial reporting purposes as of Emergence. Enterprise value assumptions incorporated: (i) economic and industry information relevant to the business; (ii) internal financial information and operating data; (iii) historical financial information; and (iv) financial projections and other applicable assumptions. The valuation techniques used to estimate the enterprise value as of Emergence included the income approach, market approach, and cost approach, with consideration of the exit market and nature of the applicable asset or liability subject to valuation.
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The Company’s principal assets are generation facilities whose values were determined by a discounted cash flow analysis based on management’s latest outlook of the business through the end of their expected useful lives. The forward-looking projections considered: (i) company-specific factors, such as unit characteristics, plant dispatch, operating expenses, capital expenditures and estimated economic useful lives; and (ii) macroeconomic factors, such as capacity prices, energy prices, fuel prices, market supply and demand factors, inflation factors, and environmental regulations. Commodity prices used to estimate future cash flows in observable periods were primarily based on adjusted exchange prices, prices provided by brokers, or prices provided by price service companies that are corroborated by market data. Commodity prices for future unobservable periods used third party pricing services that incorporate industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, inflation assumptions, and other relevant economic measures. Future estimates for capital expenditures and operating expenses, such as major maintenance and employee compensation were estimated considering unit operating experience, recent historical financial information, and expected operating performance. The expected useful lives of the generation facilities were estimated through 2050 and incorporated expectations regarding the economic prospects of each unit, permitting and licensing, regulatory requirements, and (or) other considerations. The cash flow estimates incorporated a federal effective tax rate of 21% and the applicable state tax rate based on the location of each generation facility. The present value of expected future cash flows utilized a weighted average cost of capital discount rate that ranged from 8.5% to 46.5%. The discount rate utilized for nuclear generation was 8.5% and certain natural gas generation facilities were estimated near the low end of the range. Certain coal and natural gas generation units were estimated near the high end of the range. Discount rates for each generation facility considered, among other things, unit characteristics, fuel type, and market location.
The assumptions used to estimate the reorganization value considered all available evidence as of Emergence, are believed to be consistent with those used by the principal market participants and outlook for each generation facility, and represent management’s best estimate of reorganization value. However, such assumptions are inherently uncertain and require judgment. Accordingly, changes to sensitive assumptions, which primarily include commodity prices and discount rates, would have a reasonable possibility of significantly affecting the measurement of the reorganization value. See below under “Fresh Start Adjustments” for additional information regarding assumptions used in the measurement of the Company’s various other significant assets and liabilities.
Upon the application of fresh start accounting, the Company preliminarily allocated the reorganization value to its individual assets based on their estimated fair values. The following table reconciles the Company’s enterprise value to the estimated reorganization value at Emergence:
| May 17, 2023 | |||||
Enterprise value (a) | $ | 4,500 | |||
Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) | 701 | ||||
| Plus: Current liabilities excluding long-term debt due within one year | 514 | ||||
| Plus: Non-current liabilities excluding long-term debt and liability-classified warrants | 1,234 | ||||
| Plus: Fair value of noncontrolling interest | 110 | ||||
Reorganization value to be allocated | $ | 7,059 | |||
__________________
(a)Excludes any value associated with noncontrolling interest.
(b)Excludes $52 million for payment of professional fees.
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The following table reconciles TES’s enterprise value to the estimated fair value at Emergence:
| May 17, 2023 | |||||
Enterprise value (a) | $ | 4,500 | |||
Plus: Cash and cash equivalents and Restricted cash and cash equivalents (b) | 701 | ||||
| Less: Fair value of debt | (2,845) | ||||
| Less: Liability-classified warrants | (35) | ||||
Fair value of member’s equity (c) | 2,321 | ||||
| Plus: Fair value of noncontrolling interest | 110 | ||||
Fair value of equity | $ | 2,431 | |||
__________________
(a)Excludes any value associated with noncontrolling interest.
(b)Excludes $52 million for payment of professional fees.
(c)Issued in accordance with the Plan of Reorganization. Includes 59,028,843 shares of TEC common stock and $8 million of equity-classified warrants.
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Consolidated Balance Sheet
The “Reorganization Adjustments” on the fresh start Consolidated Balance Sheet as of Emergence present the aggregate effect of the transactions contemplated by the Plan of Reorganization. The “Fresh Start Adjustments” present the preliminary fair value and other required adjustments as a result of applying fresh start accounting. The explanatory notes provide additional information related to the adjustments, the methods used to determine fair values, and significant assumptions.
| May 17, 2023 | ||||||||||||||||||||||||||||||||
| Assets | Predecessor | Reorganization Adjustments (a) | Fresh Start Adjustments | Successor | ||||||||||||||||||||||||||||
| Cash and cash equivalents | $ | 1,302 | $ | (1,133) | (b) | $ | — | $ | 169 | |||||||||||||||||||||||
| Restricted cash and cash equivalents | 240 | 426 | (c) | (81) | (q) | 585 | ||||||||||||||||||||||||||
| Accounts receivable, net | 148 | (3) | (d) | — | 145 | |||||||||||||||||||||||||||
| Inventory, net | 448 | — | (141) | (r) | 307 | |||||||||||||||||||||||||||
| Derivative instruments | 818 | — | (632) | (q) | 186 | |||||||||||||||||||||||||||
| Other current assets | 135 | — | (5) | (s) | 130 | |||||||||||||||||||||||||||
Total current assets | 3,091 | (710) | (859) | 1,522 | ||||||||||||||||||||||||||||
| Property, plant and equipment, net | 4,322 | — | (458) | (t) | 3,864 | |||||||||||||||||||||||||||
| Nuclear decommissioning trust funds | 1,465 | — | — | 1,465 | ||||||||||||||||||||||||||||
| Derivative instruments | 37 | — | (37) | (q) | — | |||||||||||||||||||||||||||
| Other noncurrent assets | 146 | (12) | (e) | 74 | (u) | 208 | ||||||||||||||||||||||||||
Total Assets | $ | 9,061 | $ | (722) | $ | (1,280) | $ | 7,059 | ||||||||||||||||||||||||
| Liabilities and Equity | ||||||||||||||||||||||||||||||||
| Revolving credit facilities | $ | 848 | $ | (848) | (f) | $ | — | $ | — | |||||||||||||||||||||||
| Long-term debt, due within one year | 1,005 | (1,000) | (g) | — | 5 | |||||||||||||||||||||||||||
| Accrued interest | 288 | (284) | (h) | — | 4 | |||||||||||||||||||||||||||
| Accounts payable and other accrued liabilities | 382 | 3 | (i) | — | 385 | |||||||||||||||||||||||||||
| Derivative instruments | 711 | — | (654) | (q) | 57 | |||||||||||||||||||||||||||
| Other current liabilities | 414 | (349) | (j) | 3 | (v) | 68 | ||||||||||||||||||||||||||
Total current liabilities | 3,648 | (2,478) | (651) | 519 | ||||||||||||||||||||||||||||
| Long-term debt | 2,504 | 281 | (k) | 55 | (w) | 2,840 | ||||||||||||||||||||||||||
| Liabilities subject to compromise | 2,788 | (2,788) | (l) | — | — | |||||||||||||||||||||||||||
| Derivative instruments | 135 | — | (93) | (q) | 42 | |||||||||||||||||||||||||||
| Postretirement benefit obligations | (1) | 302 | (m) | 34 | (x) | 335 | ||||||||||||||||||||||||||
| Asset retirement obligations and accrued environmental costs | 580 | 202 | (m) | (340) | (y) | 442 | ||||||||||||||||||||||||||
| Deferred income taxes | 82 | 283 | (n) | (8) | (z) | 357 | ||||||||||||||||||||||||||
| Other noncurrent liabilities | 19 | 60 | (o) | 14 | (aa) | 93 | ||||||||||||||||||||||||||
Total Liabilities | 9,755 | (4,138) | (989) | 4,628 | ||||||||||||||||||||||||||||
| Member’s equity | (818) | 3,416 | (p) | (277) | (bb) | 2,321 | ||||||||||||||||||||||||||
| Noncontrolling interests | 124 | — | (14) | (cc) | 110 | |||||||||||||||||||||||||||
Total Equity | (694) | 3,416 | (291) | 2,431 | ||||||||||||||||||||||||||||
Total Liabilities and Equity | $ | 9,061 | $ | (722) | $ | (1,280) | $ | 7,059 | ||||||||||||||||||||||||
F-61
Reorganization Adjustments
The reorganization adjustments required in connection with the application of fresh start accounting and the allocation of the enterprise value were:
(a)Emergence adjustments for the implementation of the Plan of Reorganization. Such adjustments include: (i) settlement of prepetition liabilities subject to compromise; (ii) payment of certain prepetition indebtedness; (iii) issuances of member’s equity; (iv) recognition of new indebtedness and related restricted cash; and (v) other items.
(b)The uses of “Cash and cash equivalents” at Emergence resulting from the implementation of the Plan of Reorganization were:
| Proceeds from Rights Offering | $ | 1,400 | |||
| Proceeds from TLB and TLC | 1,019 | ||||
| Proceeds from Secured Notes | 1,200 | ||||
| Release of restricted cash | 89 | ||||
| Payment of claims under Prepetition CAF | (1,029) | ||||
| Payment of claims under other Prepetition Secured Indebtedness | (2,136) | ||||
| Payment of DIP TLB | (1,012) | ||||
| Restriction of cash relating to TLC LCF | (470) | ||||
| Payment of debt issuance costs on TLB, TLC and Secured Notes | (54) | ||||
| Funding of professional fees escrow account | (52) | ||||
| Payment of hedge rejections | (42) | ||||
| Payment to general unsecured creditors trust | (26) | ||||
| Payment of professional fees | (22) | ||||
Other (a) | 2 | ||||
Total uses of Cash and cash equivalents | $ | (1,133) | |||
__________________
(a)Includes $1 million of proceeds from Riverstone for payment to general unsecured creditors trust.
(c)“Restricted cash and cash equivalents” net change:
| Restriction of cash relating to TLC LCF | $ | 470 | |||
| Funding of professional fees escrow account | 52 | ||||
| Release of restricted cash | (89) | ||||
| Payment of professional fees | (7) | ||||
Net change in Restricted cash and cash equivalents | $ | 426 | |||
(d)“Accounts receivable, net” net change related to settlement of affiliate receivables.
(e)“Other noncurrent assets” net change:
| Write-off of debt issuance costs associated with Prepetition CAF | $ | (22) | |||
| Reclassification of previously capitalized debt issuance costs to Long-term debt | (14) | ||||
| Capitalization of debt issuance costs | 24 | ||||
Net change in Other noncurrent assets | $ | (12) | |||
(f)Payment of principal amounts owed under Prepetition CAF.
(g)Repayment of DIP Facilities.
F-62
(h)“Accrued interest” net change:
| Payment of accrued interest on Prepetition CAF | $ | (183) | |||
| Payment of accrued interest on other Prepetition Secured Indebtedness | (89) | ||||
| Payment of accrued interest on DIP Facilities | (12) | ||||
Net change in Accrued interest | $ | (284) | |||
(i)“Accounts payable and other accrued liabilities” net change:
| Payment of hedge contract rejections | $ | (42) | |||
| Payment of professional fees | (6) | ||||
| Reinstatement of liabilities subject to compromise | 38 | ||||
| Accrual for professional fees incurred at Emergence | 13 | ||||
Net change in Accounts payable and other accrued liabilities | $ | 3 | |||
(j)“Other current liabilities” net change:
| Issuance of equity for Backstop Premium | $ | (380) | |||
| Reinstatement of liabilities subject to compromise | 31 | ||||
Net change in Other current liabilities | $ | (349) | |||
(k)“Long-term debt” net change:
| Payment of claims under Prepetition Secured Indebtedness | $ | (2,048) | |||
Borrowings of $1.2 billion under the Secured Notes (a) | 1,179 | ||||
Borrowings of $580 million under TLB (b) | 548 | ||||
Borrowings of $470 million under TLC (c) | 446 | ||||
Reinstatement of PEDFA 2009B Bonds and PEDFA 2009C Bonds (d) | 130 | ||||
| Write-off of Prepetition Secured Indebtedness issuance costs | 26 | ||||
Net change in Long-term debt | $ | 281 | |||
__________________
(a)Net of an aggregate initial purchaser discount and debt issuance costs of $21 million. See Note 13 for additional information.
(b)Net of an aggregate original issue discount and debt issuance costs of $32 million. See Note 13 for additional information.
(c)Net of an aggregate original issue discount and debt issuance costs of $24 million. See Note 13 for additional information.
(d)Includes recognition of $4 million of interest expense.
F-63
(l)“Liabilities subject to compromise” settled or reinstated at Emergence in accordance with the Plan of Reorganization:
| Liabilities subject to compromise prior to Emergence | |||||
| Debt | $ | 1,555 | |||
| Termination of retail contracts | 447 | ||||
| Postretirement benefit obligations | 305 | ||||
| Asset retirement obligations and accrued environmental costs | 220 | ||||
| Other liabilities | 92 | ||||
| Deferred tax liabilities | 77 | ||||
| Accounts payable and accrued liabilities | 51 | ||||
| Accrued interest | 41 | ||||
| Total | 2,788 | ||||
| Reinstatement and settlements of certain Liabilities subject to compromise | |||||
Reinstatement of liabilities subject to compromise (a) | (801) | ||||
| Excess fair value ascribed to lenders participating in Rights Offering | (315) | ||||
| Issuance of member’s equity to holders of claims under Prepetition Unsecured Notes and PEDFA 2009A Bonds | (186) | ||||
| Payment to general unsecured creditors trust | (24) | ||||
| Total | (1,326) | ||||
Gain on derecognition of certain Liabilities subject to compromise (b) | $ | 1,462 | |||
__________________
(a)Primarily includes postretirement benefit obligations, AROs, and deferred income taxes.
(b)Represents liabilities subject to compromise that were discharged in accordance with the Plan of Reorganization.
(m)Reinstatement of “Liabilities subject to compromise.”
(n)“Deferred income taxes” net change:
| Increase in deferred tax liabilities primarily due to estimated tax attribute reduction from the recognition of cancellation of debt income, partially offset by change in valuation allowance | $ | 206 | |||
| Reinstatement of liabilities subject to compromise | 77 | ||||
Net change in Deferred income taxes | $ | 283 | |||
(o)“Other noncurrent liabilities” net change:
Issuance of liability-classified warrants (a) | $ | 35 | |||
| Reinstatement of liabilities subject to compromise | 25 | ||||
Net change in Other noncurrent liabilities | $ | 60 | |||
__________________
(a)See Note 16 for additional information.
F-64
The estimated fair value of liability-classified warrants was determined using a Black-Scholes Option Pricing Model with the following assumptions at Emergence:
| Expected volatility | 30.00 | % | |||
| Expected term (years) | 5 | ||||
| Expected dividend yield | — | % | |||
| Risk-free interest rate | 3.6 | % | |||
| Strike price per share | $ | 52.92 | |||
| Fair value per share | $ | 11.29 | |||
(p)“Member’s equity” net change:
| Gain on settlement of liabilities subject to compromise | $ | 1,462 | |||
| Other losses attributable to gain on debt discharge | (3) | ||||
| Gain on debt discharge | 1,459 | ||||
| Write-off of deferred financing cost | (46) | ||||
| Professional fees expensed at Emergence | (27) | ||||
| Restructuring-related compensation expense | (8) | ||||
| Total reorganization items from reorganization adjustments | 1,378 | ||||
| Interest expense incurred at Emergence | (4) | ||||
| Income from reorganization adjustments before income taxes | 1,374 | ||||
| Income tax expense | (206) | ||||
| Net income from reorganization adjustments | 1,168 | ||||
| Issuance of member’s equity in connection with Rights Offering | 1,715 | ||||
| Issuance of member’s equity for Backstop Premium | 380 | ||||
| Issuance of member’s equity to holders of claims under Prepetition Unsecured Notes and PEDFA 2009A Bonds | 186 | ||||
Issuance of equity-classified warrants (a) | 8 | ||||
Issuance of liability-classified warrants (a) | (35) | ||||
Other (b) | (6) | ||||
Net change in Member’s equity | $ | 3,416 | |||
__________________
(a)See Note 16 for additional information.
(b)Includes $1 million of proceeds from Riverstone for payment to general unsecured creditors trust.
Fresh Start Adjustments
(q)Net presentation of derivatives on the Consolidated Balance Sheets. See Note 2 for additional information on this policy change.
(r)“Inventory, net” fair value adjustments:
| Coal | $ | (33) | |||
| Oil products | 11 | ||||
| Materials and supplies | (133) | ||||
| Environmental products | 14 | ||||
Total adjustment to Inventory, net | $ | (141) | |||
F-65
The fair values for oil, coal and environmental products were estimated using current market prices. The fair values of materials and supplies were estimated using an indirect cost approach. The cost approach estimates fair value by considering the amount required to construct or purchase a new asset of equal utility at current prices, with adjustments for asset function, age, physical deterioration and obsolescence.
(s)“Other current assets” primarily represents miscellaneous fair value adjustments.
(t)“Property, plant and equipment” fair value adjustments:
| Electric generation | $ | (350) | |||
| Other property and equipment | (80) | ||||
| Intangible assets | (65) | ||||
| Capitalized software | (3) | ||||
| Construction work in progress | 40 | ||||
Total adjustment to Property, plant and equipment | $ | (458) | |||
The fair value of “Property, plant and equipment” was estimated using the income approach, market approach and cost approach, as applicable. The fair value of land was estimated utilizing the market approach, which considered comparable market-based transactions within a defined area based on size, use and utility.
(u)“Other noncurrent assets” fair value adjustments:
Favorable supply contracts (a) | $ | 109 | |||
| Fair value adjustment to equity method investments | 3 | ||||
| Eliminate debt issuance costs associated with DIP Facilities | (29) | ||||
| Fair value reduction to other miscellaneous assets | (9) | ||||
Total adjustment to Other noncurrent assets | $ | 74 | |||
__________________
(a)The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and a current market benchmark.
(v)“Other current liabilities” fair value adjustments, primarily related to short-term AROs.
(w)“Long-term debt” fair value adjustments:
Eliminate debt issuance costs associated with Prepetition Secured Notes, Prepetition TLB and LMBE-MC TLB (a) | $ | 48 | |||
Fair value adjustment to Cumulus Digital TLF (a) | 11 | ||||
Fair value adjustment to LMBE-MC TLB (a) | (4) | ||||
Total adjustment to Long-term debt | $ | 55 | |||
__________________
(a)See Note 13 for additional information.
Fair value adjustments to “Long-term debt” were determined using a lattice model, given that the debt can be prepaid by the borrower prior to the maturity date.
(x)Change in accounting policy for discount rates used to estimate postretirement obligations from a bond-matching model to yield curve approach. See Note 2 for additional information.
(y)Adjustment to present at fair value AROs using assumptions as of Emergence, including an inflation factor of 2-3% and an estimated 5- to 20-year credit-adjusted risk-free rate of 8-12% based on timing of cash flows for each underlying obligation.
F-66
(z)Adjustment to “Deferred income taxes” for the change in financial reporting basis of assets and liabilities as a result of the adoption of fresh start accounting.
(aa)Fair value adjustments primarily related to unfavorable supply contracts of $13 million and the recognition of unfavorable lease liabilities. The fair value of supply contracts was determined utilizing the present value of the after-tax difference between the pricing of actual contracts in place and current market benchmarks.
(bb)Cumulative impact of fresh start accounting adjustments presented herein.
(cc)“Noncontrolling interests” fair value adjustments for certain subsidiaries.
Liabilities Subject to Compromise
As of December 31, 2022 (Predecessor), “Liabilities subject to compromise” on the Consolidated Balance Sheets represents the expected allowed amount of the prepetition claims of the Debtors that were not fully secured and that had at least a possibility of not being repaid at the full claim amount.
| Predecessor | |||||
December 31, 2022 | |||||
Debt (a) | $ | 1,558 | |||
| Termination of retail power and other contracts | 447 | ||||
Postretirement benefit obligations (a) | 309 | ||||
Asset retirement obligations and accrued environmental costs (a) | 219 | ||||
Other liabilities (a) | 114 | ||||
| Deferred tax liabilities | 83 | ||||
| Accounts payable and accrued liabilities | 53 | ||||
| Accrued interest | 41 | ||||
Derivatives (a) | 1 | ||||
Liabilities Subject to Compromise | $ | 2,825 | |||
__________________
(a)Includes both current and noncurrent amounts.
Reorganization Income (Expense), net
“Reorganization income (expense), net” for the periods presented were:
| Successor | Predecessor | |||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Backstop Premium | $ | — | $ | (70) | $ | (310) | ||||||||||||||
| Gain (loss) on debt discharge | — | 1,459 | — | |||||||||||||||||
| Gain (loss) on revaluation adjustments | — | (460) | — | |||||||||||||||||
| Professional fees | — | (56) | (210) | |||||||||||||||||
| Make-whole premiums and accrued interest on certain indebtedness | — | (21) | (183) | |||||||||||||||||
| Professional fees incurred to obtain the DIP Facilities | — | — | (70) | |||||||||||||||||
| Write-off of deferred financing cost and original issue discount | — | (46) | (30) | |||||||||||||||||
| Other | — | (7) | (9) | |||||||||||||||||
Reorganization Income (Expense), net | $ | — | $ | 799 | $ | (812) | ||||||||||||||
F-67
In the preceding table, make-whole premiums and accrued interest on certain indebtedness primarily represents charges recognized by the Debtors for estimates related to make-whole premiums and accrued interest, where applicable, on the Prepetition CAF and certain other Prepetition Secured Indebtedness. The charges are presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations and included in “Accrued interest” on the Consolidated Balance Sheets.
Cash paid for certain reorganization expenses was $308 million for the period from January 1 through May 17, 2023 (Predecessor). Cash paid for the year ended December 31, 2022 (Predecessor) for DIP Facilities financing fees is presented as “Financing Activities” on the Consolidated Statements of Cash Flows.
5. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk and interest rate risk. The hedging and optimization strategies deployed by our commercial organization manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors (including the risk committee) and management have established procedures to monitor, measure and manage hedging activities and credit risk in accordance with the risk policy.
Key risk control activities, which are designed to ensure compliance with the risk policy include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power generation markets provides uncertainty in the future performance and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: seasonal changes in demand; weather conditions; available regional load-serving supply; regional transportation and (or) transmission availability; market liquidity; and federal, regional and state regulations.
Within the parameters of our risk policy, we generally utilize conventional first lien, exchange-traded and over-the-counter traded derivative instruments, and in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives as of December 31, 2023 (Successor) range in maturity through 2026. The net notional volumes of open commodity derivatives were:
| Successor | Predecessor | |||||||||||||
December 31, 2023 (a) | December 31, 2022 (a) | |||||||||||||
| Power (MWh) | (27,557,871) | (34,810,559) | ||||||||||||
| Natural gas (MMBtu) | 8,314,060 | 57,621,580 | ||||||||||||
| Emission allowances (tons) | 500,000 | 5,000,000 | ||||||||||||
__________________
(a)The volumes may be less than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
F-68
Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
Open interest rate derivatives as of December 31, 2023 (Successor) range in maturity dates through 2026. The net notional volumes of open interest rate derivatives were:
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
Interest rate (in millions) (a) | $ | 290 | $ | 289 | ||||||||||
__________________
(a)Value as of December 31, 2023 (Successor) relates to interest rate derivatives for the TLB indebtedness. Value as of December 31, 2022 (Predecessor) relates to interest rate derivatives for the LMBE-MC indebtedness, which was repaid, and the associated derivatives terminated, in August 2023.
Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty or financial institution is unable to perform or pay amounts due, is inherent within cash and cash equivalents, restricted cash and cash equivalents, derivative instruments and accounts receivable. The maximum amount of credit exposure associated with financial assets is equal to the carrying value. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default and executing master netting arrangements which permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, letters of credit and credit insurance may be employed to mitigate credit risk.
Cash and cash equivalents are placed in depository accounts or high-quality short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. Allowance for doubtful accounts was a non-material amount as of December 31, 2023 (Successor) and December 31, 2022 (Predecessor).
As of December 31, 2023 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, letters of credit and any allowances for doubtful collections, was $431 million and its credit exposure net of such effects was $121 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements are subject to applicable market controls, the ten largest single net credit exposures account for approximately 78% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
F-69
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, letters of credit or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in our credit rating. The fair value of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material amount as of December 31, 2023 (Successor) and December 31, 2022 (Predecessor).
Derivative Instrument Presentation
Balance Sheet Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
Successor (a) | Predecessor | |||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||||||
| Commodity contracts | $ | 88 | $ | 32 | $ | 2,156 | $ | 1,928 | ||||||||||||||||||
| Interest rate contracts | 1 | — | 9 | — | ||||||||||||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | — | — | 1 | ||||||||||||||||||||||
Total current derivative instruments | 89 | 32 | 2,165 | 1,927 | ||||||||||||||||||||||
| Commodity contracts | 6 | 5 | 228 | 363 | ||||||||||||||||||||||
| Interest rate contracts | — | 6 | — | — | ||||||||||||||||||||||
Total non-current derivative instruments | $ | 6 | $ | 11 | $ | 228 | $ | 363 | ||||||||||||||||||
__________________
(a)See Note 2 for information on our accounting policy revision at Emergence concerning derivative instrument presentation.
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. See Note 2 for additional information on our derivative instruments and Note 14 for additional information on fair value.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of December 31, 2023 (Successor), while derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets without the effect of such permitted netting as of December 31, 2022 (Predecessor). See Note 2 for information on the related accounting policy.
The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:
Gross Derivative Instruments | Eligible for Offset | Liabilities Subject to Compromise | Net Derivative Instruments | Collateral (Posted) Received | Net Amounts | ||||||||||||||||||||||||||||||
| December 31, 2023 (Successor) | |||||||||||||||||||||||||||||||||||
| Assets | $ | 295 | $ | (198) | $ | — | $ | 97 | $ | (2) | $ | 95 | |||||||||||||||||||||||
| Liabilities | 300 | (198) | — | 102 | (59) | 43 | |||||||||||||||||||||||||||||
| December 31, 2022 (Predecessor) | |||||||||||||||||||||||||||||||||||
| Assets | 2,393 | (2,194) | — | 199 | — | 199 | |||||||||||||||||||||||||||||
Liabilities (a) | 2,291 | (2,194) | 1 | 96 | (75) | 21 | |||||||||||||||||||||||||||||
__________________
(a)Includes amounts that are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. See Note 4 for additional information.
F-70
Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||
| Realized gain (loss) on commodity contracts | |||||||||||||||||||||||||||||
Energy revenues (a) | $ | 360 | $ | 644 | $ | (613) | $ | (228) | |||||||||||||||||||||
Fuel and energy purchases (a) | (91) | (34) | 127 | 230 | |||||||||||||||||||||||||
| Unrealized gain (loss) on commodity contracts | |||||||||||||||||||||||||||||
Operating revenues (b) | 55 | 60 | 677 | (847) | |||||||||||||||||||||||||
Energy expenses (b) | (3) | (123) | (52) | 135 | |||||||||||||||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | |||||||||||||||||||||||||||||
| Interest expense and other finance charges | (4) | — | 30 | 12 | |||||||||||||||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.
Contract Terminations
Commodity Hedge Terminations. In March and April 2022, Talen Energy Marketing and a counterparty terminated certain derivative contracts in a net liability position with a carrying value and fair value of $124 million prior to the agreements’ scheduled maturity dates. As the parties agreed to a monthly settlement through January 2023, repayments are presented as “Derivatives with financing elements” on the Consolidated Statements of Cash Flows.
In May 2022, certain commodity counterparties of Talen Energy Marketing terminated derivative contracts in a net liability position with a carrying value and fair value of $33 million prior to the agreements’ scheduled maturity dates. During 2022, Talen Energy Marketing received approximately $7 million in net settlements from counterparties and settled the remaining $40 million liability at Emergence.
ERCOT 2021 Winter Market Conditions
In mid-February 2021, Texas experienced an extreme winter weather event, Winter Storm Uri, that led to systemic energy market disruptions and price volatility throughout ERCOT. Winter Storm Uri precipitated a rapid increase in energy demand due to the storm's historically cold temperatures and a simultaneous decrease in energy supply caused by operational disruptions to the electric grid, natural gas production and distribution systems, water supplies, and other critical infrastructure throughout Texas. Talen incurred an estimated $78 million pre-tax nonrecurring loss associated with its ERCOT activities during Winter Storm Uri for the year ended December 31, 2021 (Predecessor).
See Note 12 for additional information on ERCOT systemic risks including a settlement by ERCOT with a market participant that had defaulted in its payment obligations.
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6. Revenue
The disaggregation of our operating revenues for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Capacity revenues | $ | 133 | $ | 108 | $ | 377 | $ | 444 | ||||||||||||||||||
| Electricity sales and ancillary services, ISO/RTO | 880 | 281 | 2,534 | 1,960 | ||||||||||||||||||||||
| Physical electricity sales, bilateral contracts, other | 71 | 62 | 298 | 572 | ||||||||||||||||||||||
| Other revenue | 81 | 27 | — | — | ||||||||||||||||||||||
Total revenue from contracts with customers | 1,165 | 478 | 3,209 | 2,976 | ||||||||||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | 179 | 732 | (120) | (2,048) | ||||||||||||||||||||||
Operating revenues | $ | 1,344 | $ | 1,210 | $ | 3,089 | $ | 928 | ||||||||||||||||||
Accounts Receivable
“Accounts receivable, net” presented on the Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
| Customer accounts receivable | $ | 52 | $ | 350 | ||||||||||
| Other accounts receivable | 85 | 58 | ||||||||||||
Accounts receivable, net | $ | 137 | $ | 408 | ||||||||||
During the years ended December 31, 2023 (Successor) and 2022 (Predecessor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 5 for additional information on Talen's credit risk on the carrying value of its receivables. See Note 8 for additional information on a Talen Energy Marketing receivables sales arrangement that was terminated in May 2022.
Deferred Revenue
Deferred revenues that were: (i) presented as a liability on the Consolidated Balance Sheets as of December 31, 2023 (Successor) and 2022 (Predecessor); or (ii) recognized as revenue on the Consolidated Statements of Operations were not material.
Future Performance Obligations
In the normal course of business, Talen has future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements.
As of December 31, 2023 (Successor), the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
| 2024 | 2025 | 2026 | 2027 | ||||||||||||||||||||
| Expected capacity revenues | $ | 170 | $ | 70 | $ | 3 | $ | 1 | |||||||||||||||
The PJM capacity auctions for the 2025/2026 PJM Capacity Year and for any years thereafter have not yet been held. See Note 12 for additional information on the PJM RPM and auctions.
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7. Income Taxes
The components of “Income tax benefit (expense)” for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Federal | $ | 3 | $ | (15) | $ | (9) | $ | (25) | ||||||||||||||||||
| State | 1 | (2) | (4) | 1 | ||||||||||||||||||||||
Current income taxes | 4 | (17) | (13) | (24) | ||||||||||||||||||||||
| Federal | (55) | (184) | 68 | 263 | ||||||||||||||||||||||
| State | — | (11) | (21) | 60 | ||||||||||||||||||||||
Deferred income taxes | (55) | (195) | 47 | 323 | ||||||||||||||||||||||
| Investment tax credit | — | — | 1 | 1 | ||||||||||||||||||||||
Income tax benefit (expense) | (51) | (212) | 35 | 300 | ||||||||||||||||||||||
| Income (loss) before income taxes | 194 | 677 | (1,328) | (1,277) | ||||||||||||||||||||||
Effective income tax rate | 26.3 | % | 31.3 | % | 2.6 | % | 23.5 | % | ||||||||||||||||||
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Income (loss) before income taxes | $ | 194 | $ | 677 | $ | (1,328) | $ | (1,277) | ||||||||||||||||||
| Income tax benefit (expense) | (51) | (212) | 35 | 300 | ||||||||||||||||||||||
Effective tax rate (a) | 26.3 | % | 31.3 | % | 2.6 | % | 23.5 | % | ||||||||||||||||||
| Federal income tax statutory tax rate | 21 | % | 21 | % | 21 | % | 21 | % | ||||||||||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | (41) | (143) | 279 | 269 | ||||||||||||||||||||||
| Income tax increase (decrease) due to: | ||||||||||||||||||||||||||
| State income taxes, net of federal benefit | 1 | (34) | 19 | 59 | ||||||||||||||||||||||
| Change in valuation allowance | (43) | 129 | (198) | — | ||||||||||||||||||||||
| Permanent differences | 22 | (16) | (94) | — | ||||||||||||||||||||||
| Nuclear decommissioning trust taxes | (16) | (9) | 28 | (28) | ||||||||||||||||||||||
| Reorganization adjustments | 26 | (138) | — | — | ||||||||||||||||||||||
| Other | — | (1) | 1 | — | ||||||||||||||||||||||
Income tax benefit (expense) | $ | (51) | $ | (212) | $ | 35 | $ | 300 | ||||||||||||||||||
__________________
(a)The effective tax rate for the Successor period differed from the statutory rate primarily due to the change in valuation allowance, additional 20% trust tax on NDT income, reorganization adjustments, and permanent differences.
F-73
Deferred Taxes
The components of deferred tax liabilities and deferred tax assets as of December 31 were:
| Successor | Predecessor | |||||||||||||
| 2023 | 2022 | |||||||||||||
| Property, plant and equipment, net | $ | 560 | $ | 436 | ||||||||||
| Nuclear decommissioning trust | 443 | 394 | ||||||||||||
| Investment in Subsidiaries | 14 | — | ||||||||||||
| Unrealized gain on qualifying derivatives | 12 | 25 | ||||||||||||
Deferred tax liabilities | 1,029 | 855 | ||||||||||||
| Less: | ||||||||||||||
| Accrued pension costs | 78 | 68 | ||||||||||||
| Federal net operating loss carryforwards | 273 | 258 | ||||||||||||
| State net operating loss carryforwards | 26 | 34 | ||||||||||||
| Federal credits | 8 | 8 | ||||||||||||
| Accrued liabilities | 26 | 155 | ||||||||||||
| Interest limitation carryforward | 336 | 242 | ||||||||||||
| Investment in Subsidiaries | — | 33 | ||||||||||||
| Other | 2 | 96 | ||||||||||||
Deferred tax assets | 749 | 894 | ||||||||||||
| Valuation allowance | (128) | (198) | ||||||||||||
Deferred tax liabilities, net | $ | 408 | $ | 159 | ||||||||||
Net Operating Losses
The components of NOL carryforwards as of December 31 were:
| Successor | Predecessor | |||||||||||||
| 2023 | 2022 | |||||||||||||
| Federal, expirations 2036 - 2037 | $ | 43 | $ | 58 | ||||||||||
| Federal, indefinite expiration, limited to annual utilization of 80% | 1,258 | 1,198 | ||||||||||||
| State, expirations 2024 - 2043 | 555 | 647 | ||||||||||||
See “Emergence from Restructuring” for information on limitations on our NOLs.
Unrecognized Tax Benefits
| Successor | Predecessor | |||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Beginning balance | $ | 9 | $ | 9 | $ | 9 | ||||||||||||||
| Additions for tax positions of prior years | — | — | — | |||||||||||||||||
Ending balance | $ | 9 | $ | 9 | $ | 9 | ||||||||||||||
Included in the balance of unrecognized tax benefits as of both December 31, 2023 (Successor) and 2022 (Predecessor) are potential benefits of $9 million, that, if recognized, would affect the effective tax rate. We do not expect the total amount of unrecognized tax benefit to change significantly within one year.
All tax returns filed for years December 31, 2020 and forward are open to examination by the relevant taxing authorities.
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Emergence from Restructuring
The Company evaluated the tax impact of its Restructuring as described in Note 3 including the change in control resulting from its emergence from bankruptcy. As part of the Restructuring, a substantial portion of the Company’s prepetition debt was extinguished, resulting in cancellation of indebtedness income (“CODI”). A taxpayer emerging from Bankruptcy may exclude CODI from taxable income but must first reduce its tax attributes by the amount of CODI realized. The Company realized CODI of approximately $1.2 billion, which resulted in a partial reduction in tax basis in property, plant, and equipment assets.
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. States generally have similar tax attribute limitation rules following an ownership change. The Company also applied fresh start accounting. As a result, deferred tax assets and liabilities were adjusted based on the Successor GAAP financial statements. See Note 4 for additional information on fresh start accounting.
Valuation Allowance
For the period from January 1 through May 17, 2023 (Predecessor), Talen recognized a $129 million benefit for the reduction of federal and state valuation allowance. This movement of valuation allowance was caused by tax attribute reduction from the cancellation of debt income realized upon Emergence. For the period from May 18 through December 31, 2023 (Successor), Talen recognized a $43 million expense for the increase in federal and state valuation allowance based on realizability of existing deferred tax assets. For the period December 31, 2022 (Predecessor) Talen recognized a $198 million federal and state valuation allowance expense for the portion of Talen’s net deferred tax asset that is not more likely than not to be realized. Such an allowance resulted from a customary deferred tax asset valuation allowance assessment which is performed on net deferred tax asset positions that utilizes available positive and negative evidence to estimate whether sufficient future taxable income will be generated to permit use of the existing deferred tax assets. Talen’s most significant deferred tax assets are its net operating losses and interest limitation carryforwards. A significant objective input of negative evidence considered in the assessment included the cumulative book losses incurred over a three-year period. The existence of objective negative evidence limits the availability to consider other subjective evidence, including (but not limited to) Talen’s projections for future income which may allow for utilization of net operating losses and interest limitation carryforwards. At each period, management will continue to assess the available positive and negative evidence to determine the need for a valuation allowance.
Inflation Reduction Act of 2022
Under the Inflation Reduction Act, the nuclear production tax credit 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 is expected to 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 exceed $25 per MWh. We believe Susquehanna will qualify for these adjustments. The credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation).
Susquehanna generated approximately 18 million MWh each year from 2021 through 2023. We believe Susquehanna Nuclear will qualify for nuclear production tax credits that will result in an increase to its income. However, no assurance can be provided as to the magnitude of such increase as the Inflation Reduction Act’s provisions, including the computations of the nuclear production tax credit, are subject to implementation regulations. The implementation rules, which are also subject to future legislative revisions, have not yet been published by the Department of Treasury. Accordingly, Talen cannot fully predict the impacts of the Inflation Reduction Act to its liquidity or results of operations.
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8. Inventory
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
| Coal | $ | 152 | $ | 189 | ||||||||||
| Oil products | 75 | 61 | ||||||||||||
Fuel inventory for electric generation | 227 | 250 | ||||||||||||
| Materials and supplies, net | 72 | 195 | ||||||||||||
| Environmental products | 76 | 12 | ||||||||||||
Inventory, net | $ | 375 | $ | 457 | ||||||||||
Inventory was adjusted to fair value at Emergence. See Note 4 for additional information.
Inventory net realizable value and obsolescence charges are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. Such non-cash charges were not material for the period from May 18 through December 31, 2023 (Successor). For the period from January 1 through May 17, 2023 (Predecessor), $37 million of charges were recognized, which included $24 million of aggregate adjustments to the Brandon Shores coal and materials and supplies inventories. Net realizable value and obsolescence charges were not material for the years ended December 31, 2022 (Predecessor) and 2021 (Predecessor). See Note 10 for additional information on the Brandon Shores recoverability assessment.
Repurchase Obligations
Prior to May 2022, under an inventory repurchase agreement, Talen from time to time sold and transferred title to certain fuel inventory quantities to an unaffiliated party in exchange for cash consideration. Talen was required to subsequently repurchase the quantities as needed for electric generation or at expiry of the arrangement.
In May 2022, Talen terminated the agreement by repurchasing the remaining inventory and repaying the $165 million outstanding obligation, plus accrued interest and other fees. Talen had no outstanding inventory repurchase obligations and no inventories subject to the arrangement at December 31, 2023 (Successor) and 2022 (Predecessor).
9. Nuclear Decommissioning Trust Funds
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||
Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | |||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 9 | $ | — | $ | — | $ | 9 | $ | 6 | $ | — | $ | — | $ | 6 | ||||||||||||||||||||||||||||||||||
| Equity securities | 491 | 575 | 53 | 1,013 | 521 | 485 | 69 | 937 | ||||||||||||||||||||||||||||||||||||||||||
| Debt securities | 570 | 10 | 1 | 579 | 507 | 1 | 31 | 477 | ||||||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | (26) | — | — | (26) | (20) | — | — | (20) | ||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | $ | 1,044 | $ | 585 | $ | 54 | $ | 1,575 | $ | 1,014 | $ | 486 | $ | 100 | $ | 1,400 | ||||||||||||||||||||||||||||||||||
See Note 14 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of December 31, 2023 (Successor) or December 31, 2022 (Predecessor).
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As of December 31, 2023 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate related fair value of available-for-sale debt securities with unrealized losses as of December 31, 2023 (Successor) were:
Fair Value | Unrealized Losses | ||||||||||
| U.S. Government debt securities | $ | 97 | $ | (1) | |||||||
There were securities in an unrealized loss position for a duration of one year or longer. As of December 31, 2023 (Successor), the aggregate fair value of these securities were $13 million and the unrealized losses were non-material.
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
| Maturities within one year | $ | 105 | $ | 32 | ||||||||||
| Maturities within two to five years | 194 | 173 | ||||||||||||
| Maturities thereafter | 280 | 272 | ||||||||||||
Debt securities, fair value | $ | 579 | $ | 477 | ||||||||||
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
Sales proceeds of nuclear decommissioning trust funds investments (a) | $ | 1,259 | $ | 839 | $ | 2,081 | $ | 1,571 | ||||||||||||||||||
| Gross realized gains | 5 | 7 | 10 | 13 | ||||||||||||||||||||||
| Gross realized losses | (11) | (12) | (43) | (15) | ||||||||||||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the trust.
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10. Property, Plant and Equipment
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (years) | Gross Value | Accumulated Provision | Carrying Value | Gross Value | Accumulated Provision | Carrying Value | ||||||||||||||||||||||||||||||||||||||
| Electric generation | 3-27 | $ | 3,178 | $ | (109) | $ | 3,069 | $ | 10,596 | $ | (6,797) | $ | 3,799 | |||||||||||||||||||||||||||||||
| Nuclear fuel | 1-6 | 228 | (55) | 173 | 491 | (316) | 175 | |||||||||||||||||||||||||||||||||||||
| Other property and equipment | 1-20 | 357 | (21) | 336 | 157 | (82) | 75 | |||||||||||||||||||||||||||||||||||||
| Intangible assets | 2-26 | 1 | — | 1 | 137 | (64) | 73 | |||||||||||||||||||||||||||||||||||||
| Capitalized software | 1-5 | 6 | (1) | 5 | 102 | (95) | 7 | |||||||||||||||||||||||||||||||||||||
| Construction work in progress | 255 | — | 255 | 576 | — | 576 | ||||||||||||||||||||||||||||||||||||||
Property, plant and equipment, net | $ | 4,025 | $ | (186) | $ | 3,839 | $ | 12,059 | $ | (7,354) | $ | 4,705 | ||||||||||||||||||||||||||||||||
Property, plant, and equipment was adjusted to fair value after Emergence. See Note 4 for additional information.
The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations were:
| Successor | Predecessor | ||||||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | ||||||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||||||
Depreciation expense (a) | $ | 133 | $ | 173 | $ | 432 | $ | 436 | |||||||||||||||||||||
Amortization expense (b) | 1 | 4 | 12 | 19 | |||||||||||||||||||||||||
Accretion expense (c) | 31 | 24 | 78 | 71 | |||||||||||||||||||||||||
| Other | — | (1) | (2) | (2) | |||||||||||||||||||||||||
Depreciation, amortization, and accretion | $ | 165 | $ | 200 | $ | 520 | $ | 524 | |||||||||||||||||||||
__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 11 for additional information.
The cost of nuclear fuel is charged to “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Favorable Supply Contracts.
At Emergence, the Company recognized certain favorably priced nuclear fuel supply contracts at their fair value of approximately $109 million. See Note 4 for additional information.
Amortization expense was $53 million for the period from May 18 through December 31, 2023 (Successor). Amortization expense is presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations. The carrying value of these assets as of December 31, 2023 (Successor) was $56 million, presented as “Other noncurrent assets” on the Consolidated Balance Sheets. Estimated amortization expense for the next five years is:
| 2024 | 2025 | 2026 | 2027 | 2028 (a) | |||||||||||||||||||||||||
| Estimated amortization expense | $ | 33 | $ | 14 | $ | 5 | $ | 3 | $ | 1 | |||||||||||||||||||
__________________
(a)The favorable supply contracts expire in 2028.
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2023 Impairments
Brandon Shores Asset Group. Brandon Shores is required by contract and permit to cease coal combustion by December 31, 2025. In the first quarter 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group. Additionally, Brandon Shores notified PJM that it will deactivate electric generation on June 1, 2025.
The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its property, plant and equipment to its estimated fair value. The estimated fair value of the asset group was determined by a discounted cash flow technique that utilized significant unobservable inputs including an 11% discount rate. We believe that the utilized discount rate and other discounted cash flow assumptions are consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for the Brandon Shores asset group, including, but not limited to estimated available future generation volumes and useful lives, capacity prices, energy prices, operating costs, capital expenditures, and environmental costs. Accordingly, in 2023, Talen recognized a non-cash pre-tax impairment charge on its undepreciated property, plant and equipment related to Brandon Shores of $361 million for the period from January 1 through May 17, 2023 (Predecessor), which is presented as “Impairments” on the Consolidated Statements of Operations.
Jointly Owned Facilities
Certain of Talen's subsidiaries own undivided interests in jointly owned electric generation facilities and related assets. These generation facilities and other assets are maintained and operated pursuant to their joint ownership participation and operating agreements. Under such arrangements, each participant is responsible for funding its proportional share of construction costs and operating costs and is entitled to its proportionate share of electric generation and (or) other attributes of the relevant jointly owned facilities. Talen's proportional share of gross margin and other operating costs for its undivided interests is presented within the Consolidated Statements of Operations.
Talen Montana owns 30% of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in a joint-owner sharing agreement which governs each party’s responsibilities and rights whereby Talen Montana is responsible for 15% of the total operating costs and expenditures of Colstrip Unit 3 and 15% of Colstrip Unit 4. Accordingly, it is entitled of 15% of the available generation from each of these units. In January 2020, Talen Montana and the other co-owner of Colstrip Units 1 and 2 permanently retired the units. Talen Montana is responsible for 50% of the decommissioning and other related costs of Colstrip Units 1 and 2. See Note 22 for information on the potential acquisition by Talen Montana of an additional interest in Colstrip Units 3 and 4.
The Colstrip Units have no carrying value at December 31, 2023 (Successor) and 2022 (Predecessor), and therefore are not displayed in the table below.
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The proportionate shares of “Property, plant and equipment, net” presented on the Consolidated Balance Sheets at December 31 were:
| Susquehanna | Conemaugh | Keystone | Merrill Creek Reservoir | ||||||||||||||||||||
| Ownership interest | 90% | 22.22% | 12.34% | 8.37% | |||||||||||||||||||
| December 31, 2023 (Successor) | |||||||||||||||||||||||
| Electric generation | $ | 2,187 | $ | 2 | $ | — | $ | 1 | |||||||||||||||
| Nuclear fuel | 228 | — | — | — | |||||||||||||||||||
| Other property and equipment | 18 | — | — | 5 | |||||||||||||||||||
| Capitalized software | 2 | — | — | — | |||||||||||||||||||
| Intangible assets | 1 | — | — | — | |||||||||||||||||||
| Construction work in progress | 95 | 1 | — | — | |||||||||||||||||||
Proportionate property, plant and equipment, cost | 2,531 | 3 | — | 6 | |||||||||||||||||||
| Less: accumulated depreciation and amortization | 121 | — | — | — | |||||||||||||||||||
Proportionate property, plant and equipment, net | $ | 2,410 | $ | 3 | $ | — | $ | 6 | |||||||||||||||
| December 31, 2022 (Predecessor) | |||||||||||||||||||||||
| Electric generation | $ | 4,843 | $ | 24 | $ | 14 | $ | 1 | |||||||||||||||
| Nuclear fuel | 491 | — | — | — | |||||||||||||||||||
| Other property and equipment | 59 | — | — | 21 | |||||||||||||||||||
| Capitalized software | 19 | — | — | — | |||||||||||||||||||
| Intangible assets | 76 | — | — | — | |||||||||||||||||||
| Construction work in progress | 83 | 1 | — | — | |||||||||||||||||||
Proportionate property, plant and equipment, cost | 5,571 | 25 | 14 | 22 | |||||||||||||||||||
| Less: accumulated depreciation and amortization | 4,248 | 7 | 4 | 18 | |||||||||||||||||||
Proportionate property, plant and equipment, net | $ | 1,323 | $ | 18 | $ | 10 | $ | 4 | |||||||||||||||
Equity Method Investments
The carrying values of equity method investments which are presented as "Other noncurrent assets" on the Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||||||||||||||
| Formation | Ownership Interest (a) | December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||
| Conemaugh Fuels, LLC | 2002 | 22.22 | % | $ | 12 | $ | 15 | |||||||||||||||||||
| Keystone Fuels, LLC | 2000 | 12.34 | % | 6 | 8 | |||||||||||||||||||||
Total | $ | 18 | $ | 23 | ||||||||||||||||||||||
__________________
(a)Ownership at December 31, 2023 (Successor).
Talen holds equity interests in Conemaugh Fuels and Keystone Fuels equal to its respective undivided ownership interests in Conemaugh and Keystone. Conemaugh Fuels and Keystone Fuels were formed to purchase coal and sell it to Conemaugh and Keystone. Additionally, they may sell coal to any entity that manufactures or produces synthetic fuel from coal for resale to Conemaugh and Keystone. The aggregate affiliated fuel purchases by Talen from Conemaugh Fuels and Keystone Fuels is presented as “Fuel and energy purchases” on the Consolidated Statements of Operations. Talen’s aggregate fuel purchases for Conemaugh and Keystone Fuels were $23 million for the period from May 18 through December 31, 2023 (Successor) and $14 million for the period from January 1
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through May 17, 2023 (Predecessor). For the years ended December 31, 2022 (Predecessor) and 2021 (Predecessor), Talen’s aggregate fuel purchases were $63 million and $52 million.
11. Asset Retirement Obligations and Accrued Environmental Costs
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
| Asset retirement obligations | $ | 464 | $ | 751 | ||||||||||
| Accrued environmental costs | 23 | 35 | ||||||||||||
Total asset retirement obligations and accrued environmental costs | 487 | 786 | ||||||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | 18 | — | ||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | 219 | ||||||||||||
Asset retirement obligations and accrued environmental costs due after one year | $ | 469 | $ | 567 | ||||||||||
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(a)Presented as “Other current liabilities” as of December 31, 2023 (Successor) and as “Liabilities subject to compromise” as of December 31, 2022 (Predecessor) on the Consolidated Balance Sheets.
As a result of the Restructuring: (i) certain portions of ARO and accrued environmental costs were presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets as of December 31, 2022 (Predecessor); and (ii) ARO and accrued environmental costs were adjusted to fair value upon completion of the Restructuring. These adjustments included establishing a new discount rate for the AROs, which resulted in a decrease to the value of the obligations for our nuclear facility and an increase in the value of our non-nuclear obligations. See Note 4 for additional information.
Asset Retirement Obligations
Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our generation fleet, which include activities such as structure removal and remediation of coal piles, wastewater basins, and ash impoundments. Most of these obligations, except remediation of some ash impoundments, are not expected to be paid until several years, or decades, in the future. The most significant obligations are associated with the decommissioning of Susquehanna (for which Susquehanna Nuclear has an NDT to assist in funding the ARO) and coal ash disposal units associated with legacy coal-fired generation facilities (for which the Company has posted surety bonds, letters of credit and cash collateral for certain facilities). The carrying value of these obligations include assumptions of estimated future ARO cash expenditures, cost escalation rates, probabilistic cash flow models and discount rates. The ARO carrying value may be impacted by current or future CCR rulemaking. See Note 12 for additional information on the EPA CCR Rule.
Additionally, certain subsidiaries of the Company have legal retirement obligations associated with the removal, disposal, and (or) monitoring of asbestos-containing material at certain generation facilities. Given that the ultimate volume of asbestos-containing material is not yet known, the fair value of these obligations cannot be reasonably estimated. These obligations will be recognized upon a change in economic events or other circumstances which enables the fair value to be estimable.
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The changes of the ARO carrying value during the years were:
ARO Rollforward | |||||
Carrying value, December 31, 2021 (Predecessor) | $ | 760 | |||
| Obligations settled | (13) | ||||
| Changes in estimates and (or) settlement dates | (80) | ||||
| Obligations incurred | 8 | ||||
| Accretion expense | 76 | ||||
Carrying value, December 31, 2022 (Predecessor) | $ | 751 | |||
Carrying value, December 31, 2022 (Predecessor) | $ | 751 | |||
| Obligations settled | (11) | ||||
| Changes in estimates and (or) settlement dates | 3 | ||||
| Accretion expense | 23 | ||||
Carrying value, May 17, 2023 (Predecessor) | $ | 766 | |||
| Fair value adjustment at Emergence | (321) | ||||
| Obligations settled | (11) | ||||
| Accretion expense | 30 | ||||
Carrying value, December 31, 2023 (Successor) | $ | 464 | |||
| Successor | Predecessor | |||||||||||||
December 31, 2023 | December 31, 2022 | |||||||||||||
| Supplemental Information | ||||||||||||||
Nuclear (a) | $ | 214 | $ | 564 | ||||||||||
Non-Nuclear (b) | 250 | 187 | ||||||||||||
Carrying value | $ | 464 | $ | 751 | ||||||||||
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(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning.
(b)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.
Susquehanna Nuclear. Susquehanna Nuclear and the other joint owner of Susquehanna are each obligated to fund their proportional share of Susquehanna's ARO. Susquehanna Nuclear's proportionate share of decommissioning activities will be funded from its NDT when decommissioning commences at the expiration of its licenses. The licenses for Susquehanna Unit 1 and Unit 2 expire in 2042 and 2044 and can be extended subject to NRC approval. The NRC has jurisdiction over the decommissioning of nuclear power generation facilities and requires minimum decommissioning funding based upon a formula. Under the most recent calculation in 2022, Susquehanna Nuclear's NDT funds exceed the NRC's minimum funding requirements. To the extent that Susquehanna Nuclear's actual proportional costs for decommissioning exceed the amounts in the NDT, Susquehanna Nuclear is obligated to fund its remaining proportionate share of the ARO. Susquehanna Nuclear believes its NDT will be adequate to fund its estimated cost of decommissioning. As of December 31, 2023 (Successor), the fair value of the NDT fund was $1.6 billion and the carrying value of Susquehanna Nuclear’s ARO, which is discounted under a present value technique, was $214 million. See Note 2 for additional information on the measurement of AROs.
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In the fourth quarter of 2022 a comprehensive site-specific study was completed for Susquehanna Nuclear decommissioning to estimate the required remediation and (or) removal of generation facility structure and materials. Based on a variety of factors including, changes in assumptions regarding inflation, market risk premiums, the present value discount rate, and the timing of spent fuel remediation, the overall asset retirement obligation decreased by $83 million. The asset retirement obligation of Susquehanna Nuclear was revised at Emergence. A new discount rate resulted in a decrease to the carrying value of the obligations. See Note 4 for additional information.
See Note 14 for additional information on Susquehanna Nuclear’s NDT.
Talen Montana. 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. Actual cash expenditures associated with these obligations 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. Talen Montana, along with the other co-owners of the Colstrip Units, are working with the MDEQ to define the scope of required remediation, the scope of closure and decommissioning activities, and an estimate of the costs, including the amount of necessary financial assurance necessary to backstop these obligations. Talen Montana's decommissioning and environmental remediation is expected to be paid by funds available to Talen Montana at the time of decommissioning.
Talen Montana's estimate of its proportionate share of the AROs, discounted using a credit adjusted risk-free rate, was $107 million at December 31, 2023 (Successor) and $89 million at December 31, 2022 (Predecessor).
Future adjustments may be required to the Talen Montana ARO estimates due to the ongoing remediation requirements under MDEQ obligations and the EPA's coal combustion residuals rule. If the assumptions underlying Talen Montana's estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated. Moreover, regulatory changes and changes due to ongoing discussions with the MDEQ could affect these obligations.
See “Talen Montana Financial Assurance” in Note 12 for additional information on Talen Montana’s requirement to provide financial assurance related to certain environmental decommissioning and remediation liabilities related to the Colstrip Units.
Accrued Environmental Costs
Under the Pennsylvania Clean Streams Law, a subsidiary of Talen Generation is obligated to remediate acid mine drainage at a former mine site and may be required to take additional steps to prevent acid mine drainage at this site.
As a result of revisions to estimated spend related to expected future work performed at the site a $5 million and $13 million charge were recognized to “Other operating income (expense), net” on the Consolidated Statements of Operations for the period from May 18 through December 31, 2023 (Successor) and the year ended December 31, 2022 (Predecessor), respectively.
Liabilities related to the remediation were $23 million and $34 million at December 31, 2023 (Successor) and December 31, 2022 (Predecessor), respectively, and were presented as “Other current liabilities” and “Asset retirement obligations and accrued environmental costs” on the Consolidated Balance Sheets. Such liabilities were discounted based on a credit adjusted risk-free rate that was in existence at the time of initial liability recognition of 8.41%. At December 31, 2023 (Successor) the expected undiscounted payments are estimated to be:
| 2024 | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| Payments | $ | 4 | $ | 4 | $ | 6 | $ | 3 | $ | 3 | $ | 14 | $ | 34 | |||||||||||||||||||||||||||
At December 31, 2022 (Predecessor), all accrued environmental costs, including the ones described above, were presented as "Liabilities subject to compromise" on the Consolidated Balance Sheets.
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12. Commitments and Contingencies
Legal Matters
Talen is involved in certain legal proceedings, claims and litigation. While we believe that we have meritorious positions and will continue to defend our positions vigorously in these matters, we may not be successful in our efforts. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal proceedings and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding the matters specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial.
Pending Legal Matters
Montana Hydroelectric Litigation. Talen Montana is a defendant in litigation in the U.S. District Court for the District of Montana relating to its past ownership and operation of hydroelectric generation facilities in Montana, which were sold to NorthWestern in November 2014 (the “Montana Hydroelectric Sale”). In connection with the sale, Talen Montana agreed to retain liability with respect to this litigation, if any, attributable to time periods prior to closing of the sale.
The lawsuit was originally filed in 2003 and alleges that the streambeds underlying the facilities are owned by the State of Montana (the “State”), and that Talen Montana owes the State compensation for the use of the streambeds. In August 2023, the court held in favor of Talen Montana with respect to streambed segments underlying six of the seven facilities. Regarding the one streambed segment that the court found belongs to the State, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. The State has appealed this holding to the U.S. Court of Appeals for the Ninth Circuit. Damages and defenses related to this proceeding will be addressed in a future adjudication. Nonetheless, because Talen Montana’s liability on all claims asserted by the State was discharged under the Plan of Reorganization, Talen Montana does not expect any further liability from this matter.
ERCOT Weather Event Lawsuits. Beginning in March 2021, Talen subsidiaries that own the Barney Davis, Nueces Bay and Laredo generation facilities along with many other market participants in ERCOT were sued in multiple Texas state courts. The lawsuits were consolidated into a multi-district litigation pre-trial court (“MDL”). In these suits, the plaintiffs allege, among other things, that they suffered loss of life, personal injury and/or property damage due to the defendants’ failure to properly prepare their facilities to withstand extreme winter weather and other operational failures during Winter Storm Uri in February 2021. Numerous insurance company plaintiffs also seek to recover payments to policyholders for damage to residential and commercial properties caused by the storm. The plaintiffs seek unspecified compensatory, punitive and other damages. In January 2023, the MDL court denied a motion to dismiss filed by the generation defendants. The generation defendants sought appellant review of the decision, and, in December 2023, the Texas First Court of Appeals granted the generation defendants’ request for mandamus relief and ordered dismissal of the claims against the generation defendants. Plaintiffs have filed a motion seeking rehearing en banc with the First Court of Appeals. If unsuccessful, plaintiffs are expected to petition the Texas Supreme Court to review the decision. Plaintiffs asserting prepetition Winter Storm Uri claims are limited to recovering any damages from the Talen defendants’ insurers pursuant to the Plan of Reorganization. Certain plaintiffs filed lawsuits asserting Winter Storm Uri claims after commencement of the Restructuring. If any of these post-commencement plaintiffs did not receive effective notice of the Restructuring under applicable bankruptcy law, they may not be subject to the terms of the Plan of Reorganization. Talen cannot predict the outcome of this matter for any such claims or its effect on Talen.
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In June 2021, TEC intervened in five cases in which certain market participants are challenging the validity of two PUCT orders directing ERCOT to ensure energy prices were at their maximum of $9,000 per MWh during Winter Storm Uri. One case has since been dismissed, one case is pending in the Texas Third Court of Appeals and two cases are pending in State District Court in Travis County, Texas. In March 2023, the Third Court of Appeals issued an opinion in Luminant v. PUCT that, in part, reversed and remanded the PUCT orders directing ERCOT to ensure prices were at their maximum of $9,000 per MWh during Winter Storm Uri. The PUCT (along with TEC and others) filed petitions for review with the Texas Supreme Court, which were granted on September 29, 2023. Talen cannot predict the timing or outcome of these cases or their ultimate effect on the PUCT’s orders during Winter Storm Uri; however, changes in one or more of the PUCT’s orders could have a material adverse effect on Talen’s results of operations and liquidity.
Pension Litigation. In November 2020, four former Talen employees filed a lawsuit in the U.S. District Court for the Eastern District of Pennsylvania against TES, TEC, the TERP, the TERP committee, and (as amended) ten former retirement plan committee members alleging that they are owed enhanced benefits under the TERP. In September 2023, the parties reached a tentative agreement to settle all claims on a class-wide basis, inclusive of attorneys’ fees, in exchange for $20 million, subject to negotiation of mutually acceptable definitive agreements and court approval of the final settlement. In February 2024, the parties agreed upon the definitive settlement documentation and the court approved the settlement on a preliminary basis. The court has scheduled a hearing for June 3, 2024 to hear objections, if any, to the settlement.
If the settlement is approved, we expect a portion of the settlement to be paid by the TERP with the remainder paid by the Company, net of expected insurance recoveries. The amount paid by the TERP will be the full amount of the settlement less any attorneys’ fee award approved by the court and certain expenses associated with implementing the settlement. TES, at its discretion, may elect to fund a contribution into the TERP to cover settlement payments paid by the TERP.
If the settlement is not approved and the plaintiffs subsequently prevail on their claims, a material adverse judgment could have an adverse effect on the TERP’s assets as well as Talen’s results of operations and liquidity. No assurance can be provided that the final settlement agreement will be consummated as expected or if at all. Accordingly, we cannot predict the outcome of this matter or its effect on Talen if the settlement is not consummated as expected or if the matter is litigated to conclusion.
A pre-tax charge of $17 million, net of expected recoveries from Talen’s liability insurance policies, was recognized and presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the period from May 18 through December 31, 2023 (Successor).
Railroad Surcharge Litigation. In September 2019, TES and certain of its subsidiaries filed suit in the U.S. District Court for the Southern District of Texas, alleging that the four major railroads in the United States violated U.S. antitrust laws by conspiring during the periods from July 2003 through December 2008 to use fuel surcharges as a means to raise price for rail freight shipments. Numerous other plaintiff shippers in various jurisdictions throughout the United States have filed similar lawsuits. The Talen plaintiffs claim that they paid higher rail freight shipment rates than they otherwise would have paid absent the alleged conspiracy and seek treble damages under the antitrust laws. The litigation has been consolidated in the District Court for the District of Columbia with similar lawsuits under the multi-district litigation rules. At this time, Talen cannot predict the outcome of this matter.
Spent Nuclear Fuel Litigation. Substantial uncertainty exists regarding the nuclear industry’s permanent disposal of spent nuclear fuel (“SNF”). Federal law requires the U.S. Government to provide for the permanent disposal of commercial SNF fuel and prior to May 2014, nuclear generation facility 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. Talen cannot predict if or when the U.S. Government will increase this fee in the future, which could result in significant additional costs to Susquehanna Nuclear.
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In addition, in May 2011, Susquehanna Nuclear entered into an agreement with the U.S. Government to settle the U.S. Government’s breach of contract to accept and dispose of SNF by the statutory deadline. The settlement agreement, which has been extended four times, requires the U.S. Government to reimburse certain costs to temporarily store SNF at Susquehanna and requires Susquehanna Nuclear to waive any claims against the U.S. Government for costs paid or injuries sustained related to temporarily storing SNF. For the period from May 18 through December 31, 2023 (Successor), and the years ended December 31, 2022 (Predecessor), and December 31, 2021 (Predecessor), Susquehanna Nuclear received reimbursements of $24 million, $7 million, and $20 million for such costs. In May 2023, this agreement was extended through the end of 2025. We cannot be certain that subsequent amendments will extend these arrangements beyond 2025.
Resolved Legal Matters
Talen Restructuring. Upon Emergence in May 2023, pursuant to the Plan of Reorganization, the Debtors’ liability was discharged for certain claims arising prior to commencement of the Restructuring. The Debtors may still be liable for certain post-petition claims, including claims arising after commencement of the Restructuring, claims asserted against Talen Energy Corporation, which are unimpaired under the Plan of Reorganization, and claims asserted by parties that did not receive notice of the Restructuring under applicable bankruptcy law. We will continue to defend our positions against any such claims. See Note 3 for additional information on the Restructuring.
Kinder Morgan Litigation. In June 2021, Kinder Morgan filed a suit in Texas state court against Talen Energy Marketing, Nueces Bay and affiliates of Texas Eastern Transmission and NextEra. In the suit, Kinder Morgan alleged, among other things, that Talen agreed to purchase natural gas from it during Winter Storm Uri at the then-prevailing market rate. The case was removed to the Bankruptcy Court. In May 2023, Talen and Kinder Morgan agreed to a settlement in the suit. Under the terms of the settlement, Talen paid Kinder Morgan $10 million, assigned its related claims against NextEra and entered into certain long-term commercial agreements with Kinder Morgan affiliates. During the year ended December 31, 2022, Talen recognized an $18 million charge with respect to this suit, which was presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
PPL/Talen Montana Litigation. In October 2018, the Talen Montana Retirement Plan filed a class action suit in Montana state court against PPL, its affiliates and certain officers and directors, claiming that PPL and its directors improperly made a distribution of $733 million of net proceeds from the Montana Hydroelectric Sale from Talen Montana to PPL, leaving Talen Montana without adequate funds to pay its obligations. In November 2018, PPL filed a lawsuit in Delaware Court of Chancery (the “Delaware Court”) against Talen and certain affiliates seeking, among other things, indemnity from Talen for the claims asserted in the Montana state lawsuit and a declaratory judgment that such claims asserted in the Montana state lawsuit are without merit and that Talen entities do not have standing to bring such claims. Talen Montana filed an adversary complaint against PPL and its affiliates in the Bankruptcy Court asserting claims similar to those in the Montana lawsuit. The lawsuits pending in Montana state court and the Delaware Court were consolidated with the adversary proceeding. The Talen defendants’ liability on all claims asserted by the PPL defendants, except for claims asserted against TEC, was discharged under the Plan of Reorganization.
In December 2023, Talen reached a settlement of litigation with PPL. Under the terms of the settlement agreement, PPL paid Talen Montana $115 million in cash in exchange for a full release of all claims. $11 million of the settlement amount was remitted to the general unsecured creditors trust established per the Plan of Reorganization, resulting in a gain of $104 million that is presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the year ended December 31, 2023 (Successor).
Other. In the normal course of Talen’s business, we are party to various legal proceedings, claims and litigation arising from current or past operations. While the outcome of these matters is uncertain, the likely results are not presently expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations.
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Regulatory Matters
Talen is subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to: FERC; the Department of Energy; Federal Communications Commission; NRC; NERC; public utility commissions in various states in which we conduct business; and RTOs and ISOs in the regions in which we conduct business. Talen is party to proceedings before such agencies arising in the ordinary course of business and has other regulatory exposure due to new or amended regulations promulgated by such agencies from time to time. While the outcome of these regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations, although the effect could be material to our results of operations in any interim reporting period.
PJM MOPR. 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 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. The final impacts on Talen’s financial condition, results of operations and liquidity are not known at this time.
PJM Market Seller Offer Cap. In March 2021, FERC responded to complaints filed by the PJM IMM on behalf of PJM and various consumer advocates alleging that the PJM MSOC was above a competitive offer level and was, therefore, unjust and unreasonable. In September 2021, FERC issued an order requiring the PJM ACR for each generator to be determined administratively by the PJM IMM. In August 2023, the U.S. Court of Appeals for the District of Columbia Circuit denied petitions by Talen and others for review of FERC’s order. On January 12, 2024, the Electric Power Supply Association filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the August 2023 order of the D.C. Circuit. The final impacts of this order on Talen’s financial condition, results of operations and liquidity are not known at this time.
PJM Capacity Market Reform. In February 2023, the PJM Board directed PJM and its stakeholders to resolve: (i) key issues that address the energy transition taking place in PJM; and (ii) issues observed from Winter Storm Elliott. The PJM Board directive included reliability risks, risk drivers and resource availability. The stakeholder process is referred to as Critical Issue Fast Path (“CIFP”) on resource adequacy. On October 13, 2023, PJM made two filings at FERC regarding certain capacity market reforms developed through the CIFP process. On January 30, 2024, FERC accepted one of PJM’s filings, subject to the condition that PJM submit a compliance filing within 30 days. However, on February 6, 2024, FERC rejected the second of PJM’s capacity market reform filings. On February 26, 2024, FERC approved a request from PJM for a 35-day delay of Base Rate Auction. PJM has indicated that it plans to open the Base Residual Auction for the 2025/2026 Delivery on July 17, 2024. At this time, Talen cannot fully predict the impacts of PJM’s reforms on its operations and liquidity.
In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delay schedules the PJM Base Residual Auctions for 2026/2027 in December 2024, for 2027/2028 in June 2025, and for 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, but the final impacts on Talen's financial condition, results of operations and liquidity are not known at this time.
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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. 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. As a result, Talen incurred certain Capacity Performance penalties charged by PJM for certain generation facilities and earned bonus revenues from PJM for other generation facilities. In April 2023, 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 September 2023, PJM filed a request for FERC to approve a market-wide settlement agreement that would resolve all Winter Storm Elliot complaints, including those filed by Talen. The settlement agreement results in a 31.7% reduction in the total penalties assessed on all capacity market sellers, including Talen, as well as an additional $8 million credit to Talen. In December 2023, FERC approved the settlement agreement which reduced Talen’s aggregate penalties, net of expected bonus revenues, to an estimated $28 million. Talen recognized an estimated $48 million of aggregate net penalties, comprised of: (i) initial penalty of $33 million for the year ended December 31, 2022 (Predecessor); (ii) increase of $13 million for the period of January 1 through May 17, 2023 (Predecessor); and (iii) increase of $2 million for the period of May 18 through December 31, 2023 (Successor) as a result of revised assessments from PJM. Talen remitted aggregate penalty payments of $29 million during the periods of January 1 through May 17, 2023 (Predecessor) and May 18 through December 31, 2023 (Successor). In December 2023, the remaining liability of $19 million was derecognized as a result of the settlement.
ERCOT Market Systemic Risks. Due to the effects of Winter Storm Uri, certain market participants in ERCOT defaulted on settlements and caused a deficit of payments to ERCOT. In May 2022, ERCOT reported a cumulative aggregate payment deficit of approximately $2.3 billion as result of the events. As a result, ERCOT instituted “short payments” that delay the remittance of cash for an uncertain period of time to non-defaulting market participants and will only be paid as ERCOT recovers money from defaulting parties or through the collection of default uplift payments. In September 2022, ERCOT reached a settlement agreement with the largest defaulting market participant. In October 2022, Talen made disbursement elections to receive approximately $5 million for its portion of the $1.3 billion owed to applicable market participants. Each of: (i) Talen’s outstanding receivable that is collectible over a 12-year period pursuant to the settlement; and (ii) the portion of the receivable that is ultimately uncollectible by Talen are non-material amounts.
In January 2023, the PUCT adopted the PUCT PCM market design in response to a directive contained within Texas Senate Bill 3 from 2021 to address market reliability concerns in Texas. The details of how the PUCT PCM market will operate are to be developed by the PUCT, ERCOT and the ERCOT stakeholder group. In January 2023, the PUCT directed ERCOT to evaluate bridging options to retain existing assets and build new dispatchable generation until the PUCT PCM can be fully implemented. In response, the PUCT approved a multi-step Operating Reserve Demand Curve floor as a short-term bridge solution, which went into effect on November 1, 2023. Under the approved multi-step Operating Reserve Demand Curve, price floors of $10/MWh and $20/MWh will be triggered when reserves fall below 7 GW and 6.5 GW, respectively. There remains significant uncertainty surrounding the details of the proposed PUCT PCM design, and the timing for implementation. At this time, Talen cannot fully predict the impacts of the PUCT PCM market design, when and if implemented, on its results of operations and liquidity.
Brandon Shores Reliability Impact Assessment. In April 2023, Talen notified PJM that it will deactivate electric generation at Brandon Shores on June 1, 2025. 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. Discussions with PJM are ongoing and may result in Brandon Shores continuing to operate for some period of time until transmission constraints hindering reliability are relieved by PJM.
H.A. Wagner Deactivation. In October 2023, for economic reasons, Talen provided a notice to PJM of its intent 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 deactivation. In January 2024, PJM notified Wagner that Units 3 and 4 are needed for transmission reliability.
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Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, and hazardous and solid waste management. From time to time, in the ordinary course of our business, Talen may become involved in other environmental matters or become subject to other, new or revised environmental statutes, regulations or requirements.
It may be necessary for us to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. We may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operation and maintenance expenses, monetary fines, penalties or other restrictions, which could be material. Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.
Water and Waste. Changes made by the EPA to the EPA CCR Rule and the EPA ELG Rule in 2020 allow coal generation facility operators to request an extension to compliance deadlines if the facility commits to cessation of coal-fired generation by the end of 2028. Pursuant to Talen’s plans to cease wholly owned coal operations, Talen requested extensions for compliance under these rules for certain of its generation facilities; some have been approved and some are still under review. The most significant extension under review is the EPA CCR Rule Part A extension request for Montour Ash Impoundment 1, and a negative result would have a significant impact on the closure plan for this impoundment.
In 2023, the EPA proposed additional changes to the EPA ELG Rule and to the EPA CCR Rule. The EPA ELG Rule proposal does not add treatment requirements to Talen’s coal-fired power generation facilities planning to cease the burning of coal by 2028, but it does propose discharge limits for waters collected from CCR units. With respect to the EPA CCR Rule, the EPA has proposed to impose new requirements on legacy CCR impoundments and facilities where CCR was disposed of or managed on land outside of regulated units at CCR facilities, which could affect several Talen facilities. Furthermore, the EPA’s interpretations on the EPA CCR Rule continue to evolve through enforcement. At this time, Talen cannot predict the outcome of these various rule changes on the operations of its coal-fired generation facilities and its results of operations.
Air. Since 2016, the coal-fired generation facilities in which Talen has ownership, including Brunner Island, Montour, Keystone and Conemaugh, have been the subject of various efforts under the Clean Air Act to strengthen applicable nitrogen oxides (“NOx”) emission limits. These include Section 126 petitions by downwind states, recommendations by the Ozone Transport Commission, and a ruling on Pennsylvania’s RACT2 program by the U.S. District Court for the Southern District of New York. Although the petitions and recommendations are not withdrawn, the EPA’s issuance of a federal implementation plan (the “FIP”) with short-term (RACT2) NOx limits at these plants in 2022 resulting from the court case and the EPA’s “Good Neighbor FIP” issued in June 2023 appear to have addressed open concerns by upwind states regarding NOx controls from Talen’s and other coal plants.
However, both the Pennsylvania NOx RACT2 FIP and the preceding State Implementation Plan (the “SIP”) NOx RACT are under review. The PA DEP agreed to stay the SIP standard while all the parties consider the FIP standards. The EPA FIP is in effect; however, it has since been appealed by other parties and Talen has intervened in the appellate proceeding. Lastly, in November 2022, Pennsylvania finalized its NOx RACT standards for all power generation facilities to address the EPA 2015 Ozone Standard. Affected Talen facilities have submitted permit applications demonstrating their compliance methods for the new standard. At this time, Talen cannot predict the outcome of these potential rule changes on the operations of its generation facilities and its results of operations.
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To address the 2015 ozone standard, in June 2023, the EPA published the final rule covering the EPA CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” The EPA made some reductions in allowance allocations, among other changes, to minimize nitrogen oxide emissions during the Ozone Season. Texas, among other states, has received a favorable court ruling, essentially staying its participation in the updated program for 2023. Texas facilities are still subject to the previous version of EPA CSAPR, and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. Additionally, the entire rule has been challenged by multiple parties, and the U.S. Supreme Court heard oral arguments on the emergency applications to stay the rule on February 21, 2024. At this time, Talen cannot predict the long-term outcome of these rule changes on the operations of its generation facilities and its results of operations.
The EPA MATS Rule, which is the original EPA NESHAP for coal plants, has been in effect since 2012. In April 2023, the EPA issued its EPA RTR for coal-fired generation facilities under the EPA NESHAP, which proposes changes to the EPA MATS Rule, most notably to reduce particulate matter emissions from coal plants. Talen submitted formal comments on the EPA RTR, indicating that the new EPA MATS Rule, if finalized, would unreasonably require Colstrip to install new control equipment. At this time, Talen cannot predict the outcome of this potential rule change on the operations of its generation facilities and its results of operations.
RGGI. In April 2022, Pennsylvania formally entered the RGGI program, with compliance set to begin on July 1, 2022. However, certain third parties filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania was stayed. On November 1, 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PA DEP appealed this decision to the Pennsylvania Supreme Court on November 21, 2023, and the following day filed notice with the court that the RGGI program would not be implemented while the appeal is pending. At this time, Talen is unable to determine the full impact of the RGGI program, when and if implemented, on its results of operations and liquidity.
Federal Climate Change Actions. The current federal administration has identified climate change policy as a priority that includes, but is not limited to, greenhouse gas emission reductions. In May 2023, the EPA proposed a new rule under the Clean Air Act that would establish new source performance standards for new electric generating units and emission guidelines for existing EGUs for state implementation. The rule is expected to be finalized in mid-2024. The proposed guidelines would allow all existing EGUs to continue to operate until at least the end of 2031 without having to meet new greenhouse gas limits. Existing baseload-type EGUs, whether combustion turbines or coal-fired steam units (e.g., Colstrip), would be able to operate beyond 2031, but would be subject to Capacity Factor limits or greenhouse gas reduction requirements. Other EGUs would typically not require additional controls; however, EPA is considering further controls in the future. The proposed rule intends to require significant greenhouse gas reductions for large, baseload coal plants like Colstrip. However, until the rule is finalized, Talen is unable to determine the full impact of the proposed rule on its results of operations and liquidity.
Environmental Remediation. From time-to-time, Talen undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from our operations and undertakes similar actions necessary to resolve environmental matters that arise in the course of normal operations.
Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs, but at this time we are unable to determine if such investigation or remediation work will have a material adverse effect on our financial condition or results of operations.
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Guarantees and Other Assurances
In the normal course of business, Talen enters into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by letters of credit issued by financial institutions, surety bonds issued by insurance companies, and indemnifications. In addition, they may include customary indemnifications to third parties related to asset sales and other transactions. Based on our current knowledge, the probability of expected material payment/performance for the guarantees and other assurances is considered remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain subsidiaries for obligations including, but not limited to, environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers, in each case upon the occurrence of certain events. As of December 31, 2023 (Successor) and December 31, 2022 (Predecessor), the aggregate amount of surety bonds outstanding was $240 million and $248 million, including surety bonds posted on behalf of Talen Montana as discussed below. Included in TES’s outstanding sureties as of December 31, 2023 (Successor) is a bond in the amount of $10 million that was issued on behalf of Cumulus Data for support of its development and construction activities.
Talen Montana Financial Assurance. Pursuant to the Colstrip AOC, Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the MDEQ on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of the Colstrip Units have provided their proportional share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
TES has posted an aggregate $115 million of surety bonds to the MDEQ on behalf of Talen Montana’s proportional share of remediation and closure activities as of December 31, 2023 (Successor) and $113 million as of December 31, 2022 (Predecessor). Talen Montana has agreed to reimburse TES and its affiliates in the event that these surety bonds are called. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements will decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed.
Cumulus Digital Assurances. As of December 31, 2023 (Successor), TES had issued LCs in the aggregate amount of $50 million to the lenders of the Cumulus Digital TLF, which LCs could be drawn upon, among other events, the acceleration of the loan due to a bankruptcy or other event of default by Cumulus Digital. The LCs were cancelled upon the payment in full of the Cumulus Digital TLF on March 1, 2024.
Additionally, TEC had provided a guarantee to the lenders under the Cumulus Digital TLF for certain shortfalls in interest and principal payments by Cumulus Digital (up to a maximum of 23% of the principal amount of outstanding loans thereunder). The guarantee was cancelled upon the payment in full of the Cumulus Digital TLF on March 1, 2024.
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Other Commitments and Contingencies
Nuclear Insurance. The Price-Anderson Act is a United States federal law which governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of December 31, 2023 (Successor), the liability limit per incident is $16.2 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers (approximately $450 million in coverage), with the remainder covered by an industry retrospective assessment program. On January 1, 2024, American Nuclear Insurers increased primary insurance coverage to $500 million, resulting in a commensurate increase in total coverage.
As of December 31, 2023 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna Nuclear could be assessed deferred premiums of up to $332 million per incident, payable at a maximum of $49 million per year.
Additionally, Susquehanna Nuclear purchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna Nuclear is a member. As of December 31, 2023 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $2.0 billion and non-nuclear property damage losses up to $1.0 billion. Susquehanna Nuclear also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna Nuclear could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $45 million as of December 31, 2023 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Talen Montana Fuel Supply. Talen Montana purchases coal from the Rosebud Mine for its interest in Colstrip Units 3 and 4 under a full requirements contract with an unaffiliated coal mine operator. In 2015, the MDEQ issued the mine operator an amendment to one of its mine permits expanding the area authorized for mining. Certain parties challenged the permit amendment in a proceeding at the MBER and, after the MBER issued a decision upholding the permit amendment, in a lawsuit in Montana state district court. In January 2022, the district court entered an order vacating the permit amendment effective April 1, 2022. Rosebud Mining ceased mining in the expansion area prior to the April 1, 2022 deadline. The mine operator and the MDEQ appealed the district court’s decisions to the Montana Supreme Court and filed motions seeking to stay the order vacating the permit. In August 2022, the Montana Supreme Court entered an order staying the district court’s order pending resolution of the appeal. In November 2023, the Montana Supreme Court remanded the case to the MBER to reanalyze the administrative record, resolve factual questions, and re-examine its prior conclusion. The MBER is awaiting remand. In the meantime, however, the Montana Supreme Court reinstated vacatur of the permit amendment pending MBER review.
In May 2022, MDEQ issued a second permit amendment expanding the area authorized for mining by the coal-mine operator. A group of complainants initiated proceedings at the MBER and in Montana state district court challenging the second permit amendment. Summary judgment briefing was completed in the MBER case as of January 2024. In December 2023 the Montana state district court challenge was stayed for six months pending a ruling from the Montana Supreme Court in analogous cases.
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In September 2022, the Montana Federal District Court entered an order upholding challenges to a third permit amendment expanding the area authorized for mining by the mine operator. The plaintiffs asserted that the OSM violated NEPA when preparing the EIS for the permit amendment. The court ordered OSM to complete an updated EIS in accordance with NEPA’s requirements. The permit amendment will be vacated unless OSM completes the updated EIS within 19 months from the date of the court’s order. The federal defendants did not appeal and expect to issue a revised decision on the permit amendment within the 19-month deadline, but in November 2022, intervenor-defendants, Westmoreland Rosebud and International Union, appealed the ruling to the Ninth Circuit Court of Appeals. MEIC and the other plaintiffs moved to dismiss the appeal for lack of jurisdiction, and the federal defendants did not oppose the motion to dismiss. The appeal was dismissed in November 2023, and the federal defendants have requested an extension of the deadline to complete the updated EIS until June 30, 2025, which is under consideration by the District Court.
At this time, Talen cannot predict the outcome of these matters or their effect on Talen Montana’s operations, results of operations or liquidity.
13. Long-Term Debt and Other Credit Facilities
Long-Term Debt
| Successor | Predecessor | |||||||||||||||||||
Interest Rate (a) | December 31, 2023 | December 31, 2022 | ||||||||||||||||||
| TLB | 9.87 | % | $ | 866 | $ | — | ||||||||||||||
| TLC | 9.87 | % | 470 | — | ||||||||||||||||
| Secured Notes | 8.63 | % | 1,200 | — | ||||||||||||||||
PEDFA 2009B Bonds (c) | 5.05 | % | 50 | 49 | ||||||||||||||||
PEDFA 2009C Bonds (c) | 5.05 | % | 81 | 79 | ||||||||||||||||
Cumulus Digital TLF, including PIK (b) | 12.50 | % | 182 | 185 | ||||||||||||||||
| Settled indebtedness | ||||||||||||||||||||
| DIP TLB | N/A | — | 1,000 | |||||||||||||||||
| Prepetition TLB | N/A | — | 427 | |||||||||||||||||
| Prepetition Secured Notes | N/A | — | 1,620 | |||||||||||||||||
Prepetition Unsecured Notes (c) | N/A | — | 1,330 | |||||||||||||||||
PEDFA 2009A Bonds (c) | N/A | — | 100 | |||||||||||||||||
| LMBE-MC TLB | N/A | — | 301 | |||||||||||||||||
Total principal | 2,849 | 5,091 | ||||||||||||||||||
| Unamortized deferred finance costs and original issuance discounts | (29) | (29) | ||||||||||||||||||
Total carrying value | 2,820 | 5,062 | ||||||||||||||||||
| Less: long-term debt, due within one year | 9 | 1,010 | ||||||||||||||||||
Less: amounts presented as “Liabilities subject to compromise” (c) | — | 1,558 | ||||||||||||||||||
Long-term debt | $ | 2,811 | $ | 2,494 | ||||||||||||||||
__________________
(a)Computed interest rate as of December 31, 2023 (Successor).
(b)Limited recourse to TES and TEC. See “Cumulus Digital Assurances” in Note 12 for additional information.
(c)As of December 31, 2022 (Predecessor), amounts are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. See Note 4 for additional information.
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The aggregate long-term debt maturities, including quarterly amortization and early redemption provisions, at December 31, 2023 (Successor) were:
| 2024 | 2025 | 2026 | 2027 (a) | 2028 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| Total maturities | $ | 9 | $ | 9 | $ | 9 | $ | 191 | $ | 9 | $ | 2,622 | $ | 2,849 | |||||||||||||||||||||||||||
__________________
(a)Includes $182 million of limited-recourse indebtedness under the Cumulus Digital TLF.
Revolving Credit and Other Facilities
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||
| Expiration | Committed Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | ||||||||||||||||||||||||||||||||||||||
RCF (a) | May 2028 | $ | 700 | $ | — | $ | 62 | $ | 638 | $ | — | $ | — | |||||||||||||||||||||||||||||||
TLC LCF (b) | May 2030 | 470 | — | 404 | 66 | — | — | |||||||||||||||||||||||||||||||||||||
Bilateral LCF (b) | May 2028 | 75 | — | 74 | 1 | — | — | |||||||||||||||||||||||||||||||||||||
| Settled indebtedness | ||||||||||||||||||||||||||||||||||||||||||||
DIP RCF (c) | N/A | — | — | — | — | — | 33 | |||||||||||||||||||||||||||||||||||||
DIP LCF (c) | N/A | — | — | — | — | — | 434 | |||||||||||||||||||||||||||||||||||||
Prepetition CAF (c)(d) | N/A | — | — | — | — | 848 | — | |||||||||||||||||||||||||||||||||||||
| LMBE-MC RCF | N/A | — | — | — | — | — | 12 | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,245 | $ | — | $ | 540 | $ | 705 | $ | 848 | $ | 479 | ||||||||||||||||||||||||||||||||
__________________
(a)Committed capacity includes $475 million of LC commitments.
(b)Direct cash borrowings are not permitted under the facility.
(c)Extinguished as of Emergence.
(d)The weighted average interest rate was 12.12% at December 31, 2022 (Predecessor).
Outstanding direct cash borrowings under the RCF and the LMBE-MC RCF, when applicable, are each presented as “Revolving credit facilities” on the Consolidated Balance Sheets.
As of December 31, 2023 (Successor) Talen was not in default under any of its indebtedness agreements.
2024 Transactions
Cumulus Digital TLF Repayment. In connection with the Data Center Campus Sale, the Cumulus Digital TLF were paid in full on March 1, 2024, together with all accrued interest and other outstanding amounts. See below under “Non-Recourse Debt and Other Credit Facilities – Cumulus Digital TLF” for additional information on the release of liens, termination of guarantees, and the cancellation of LCs. See Note 22 for additional information on the Data Center Campus Sale.
2023 Transactions
LMBE-MC Refinancing. In August 2023, we incurred an additional $290 million in aggregate principal amount of TLB, resulting in proceeds of $285 million, net of original issue discount and other fees. The additional amount was issued as an incremental borrowing under the TLB and constitutes a single series of indebtedness with the existing TLB incurred at Emergence. The proceeds were used, together with cash on hand, to fully repay the $293 million in aggregate principal amount outstanding under the LMBE-MC TLB. The LMBE-MC Credit Agreement (including the LMBE-MC TLB and LMBE-MC RCF), including an aggregate $12 million of outstanding LCs issued under the agreement, was terminated at settlement.
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Successor Emergence Financings. In May 2023, as part of the Exit Financings, TES issued the following long-term debt:
•TLB, due 2030, in an aggregate principal amount of $580 million, resulting in proceeds of $548 million, net of original issue discount and other fees;
•TLC, due 2030, in an aggregate principal amount of $470 million, resulting in proceeds of $446 million, net of original issue discount and other fees; and
•Secured Notes, due 2030, in an aggregate principal amount $1.2 billion, resulting in proceeds of $1.179 billion, net of initial purchaser discounts and other fees.
Proceeds from the TLB and the Secured Notes were used, together with cash on hand, to fund the settlement of the transactions and claims contemplated by the Plan of Reorganization, including cash settlement of the long-term debt and cash revolver borrowings outstanding under the DIP Facilities, Prepetition TLB, Prepetition Secured Notes, and Prepetition CAF, all of which were extinguished as of May 17, 2023 under the Plan of Reorganization. Proceeds from the TLC were used to cash collateralize letters of credit under the TLC LCF.
Also, as part of the Exit Financings, TES entered into the following revolving and letter of credit facilities:
•RCF, a $700 million revolving credit facility, including letter of credit commitments of $475 million;
•TLC LCF, which provides commitments for up to $470 million in letters of credit, cash collateralized with the proceeds of the TLC, and reduced to the extent that borrowings under the TLC are prepaid; and
•Bilateral LCF, which provides commitments for up to $75 million in letters of credit.
At Emergence, LCs were issued under the TLC LCF and the Bilateral LCF to backstop or replace LCs previously outstanding under the DIP Facilities, which were extinguished as of May 17, 2023.
See “Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities” below for additional information on our Credit Facilities and Secured Notes. See Note 3 for additional information on the Restructuring.
Emergence Equitization. All of the Prepetition Secured Notes and the PEDFA 2009A Bonds were extinguished as of May 17, 2023 under the Plan of Reorganization through the issuance of TEC common stock. See Notes 3 and 4 for additional information on the Restructuring and fresh start accounting adjustments related to indebtedness.
2022 Transactions
DIP Facilities. In May 2022, TES entered into the DIP Facilities, including the DIP TLB, a term loan B facility in an aggregate principal amount of $1 billion that provided $971 million of proceeds, net of discount and fees.
Cumulus Digital TLF. In September 2022, as a result of the Cumulus Digital Equity Conversion, TES consolidated Cumulus Digital Holdings for financial reporting purposes and, accordingly, also consolidated the Cumulus Digital TLF.
Talen Energy Supply Pre-Restructuring Long-Term Debt, Revolving Credit and Other Facilities
Outstanding Prepetition Indebtedness. Upon commencement of the Restructuring, (i) TES’s Prepetition Secured Indebtedness consisted of the Prepetition RCF, Prepetition TLB, Prepetition CAF, and Prepetition Secured Notes; and (ii) TES’s Prepetition Unsecured Indebtedness consisted of the Prepetition Unsecured Notes and PEDFA Bonds, as further outlined in the tables above.
Effects of the Restructuring on Prepetition Indebtedness. Commencement of the Restructuring constituted an event of default and accelerated obligations under TES’s then-outstanding Prepetition Indebtedness, other than the PEDFA 2009B and 2009C Bonds.
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TES’s Prepetition Indebtedness other than the PEDFA 2009B and 2009C Bonds (i.e., the Prepetition TLB, Prepetition Secured Notes, Prepetition Unsecured Notes, PEDFA 2009A Bonds, and Prepetition CAF) was extinguished as of May 17, 2023 under the Plan of Reorganization. The PEDFA 2009B and 2009C Bonds remained outstanding. See “2023 Transactions - Successor Emergence Financings” above for additional information about the repayment of the Prepetition TLB, Prepetition Secured Notes, and Prepetition CAF, and See “2023 Transactions - Emergence Equitization” above for additional information about the equitization of the Prepetition Unsecured Notes and PEDFA 2009A Bonds.
See Note 3 for additional information on the Restructuring, including the Exit Financings.
Prepetition LCFs. LC issuances were not permitted under the Prepetition LCFs due to the Restructuring. We terminated one Prepetition LCF in May 2023 and the other expired in June 2023.
Prepetition Secured ISDAs. Prior to commencement of the Restructuring, Talen Energy Marketing was party to the Prepetition Secured ISDAs, under which TES and the Prepetition Guarantors provided the applicable counterparties with a first priority lien on and security interest (which ranked pari passu with the liens securing the Prepetition Secured Indebtedness) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. Following commencement of the Restructuring, a portion of the Prepetition Secured ISDAs were rolled over into DIP Secured ISDAs. As of May 18, 2023, post-emergence from Restructuring, the remaining Prepetition Secured ISDAs were rolled into the Secured ISDAs.
Talen Energy Supply DIP Facilities
DIP Facilities. Upon commencement of the Restructuring, TES entered into the DIP Facilities, comprised of: (i) the DIP RCF, a $300 million revolving credit facility, including a letter of credit sub-facility of up to $75 million; (ii) the DIP TLB, a term loan B facility in an aggregate principal amount of $1 billion; and (iii) the DIP LCF, a letter of credit facility that provided for approximately $458 million of LCs outstanding under the Prepetition RCF as of commencement of the Restructuring to remain outstanding with superpriority status. Amounts owed under the DIP RCF and DIP TLB were repaid in full, and all DIP Facilities terminated, upon the Debtors’ Emergence from the Restructuring. However, certain LCs issued (or continued) under the DIP RCF and DIP LCF remain outstanding and are now backstopped by LCs issued under the TLC LCF in favor of the applicable DIP LC issuers.
DIP Secured ISDAs. Following commencement of the Restructuring, and as authorized by a final order of the Bankruptcy Court, Talen Energy Marketing was party to certain DIP Secured ISDAs that were continuations of the Prepetition Secured ISDAs but under which TES and the Debtors provided the applicable counterparties with a superpriority lien on and security interest (which ranked pari passu with the liens securing the DIP Facilities) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. As of May 18, 2023, post-emergence from Restructuring, the DIP Secured ISDAs were rolled into the Secured ISDAs and the associated superpriority liens were extinguished and replaced with the first priority liens securing the Secured ISDAs.
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Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities
Certain key terms of our post-emergence facilities include:
| Facility | Maturity | Index | Rate, Applicable Margin, and Amortization | Prepayment Penalty | ||||||||||||||||||||||
| Secured Notes | June 2030 | None | 8.625% per annum fixed rate No applicable margin No amortization | Prior to June 1, 2026: Redeemable at par plus a customary “make-whole” premium. 10% redeemable during each 12-month period at 103%. 40% redeemable from the proceeds of certain equity offerings at 108.625% On or after June 1 of the following years: 2026: 104.313% 2027: 102.156% 2028 and thereafter: 100% | ||||||||||||||||||||||
| TLB | May 2030 | Term SOFR | 4.50% per annum applicable margin Amortization 1.00% per annum; paid quarterly | 1.00% to the extent prepaid prior to February 9, 2024 in connection with a repricing transaction | ||||||||||||||||||||||
| TLC (TLC LCF) | May 2030 | Term SOFR | 4.50% per annum applicable margin No amortization | None | ||||||||||||||||||||||
| RCF (cash borrowings) | May 2028 | Term SOFR | 3.50% per annum applicable margin; step-downs to 3.25% and 3.00% based on first lien net leverage ratios in certain fiscal quarters No amortization | None | ||||||||||||||||||||||
| RCF (LCs) | May 2028 | None | 0.125% per annum Fronting Fee and 3.50% per annum LC Fees (step-downs to 3.25% and 3.00% based on first lien net leverage ratios in certain fiscal quarters) | None | ||||||||||||||||||||||
| Bilateral LCF | May 2028 | None | 3.50% per annum LC Fees and 0.125% per annum Issuance Fee | None | ||||||||||||||||||||||
Credit Agreement. The Credit Agreement governs the RCF, TLB, TLC, and TLC LCF.
The Credit Agreement contains customary negative covenants including, but not limited to, limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and asset sales. The Credit Agreement also contains customary affirmative covenants. Solely with respect to the RCF, and solely during a compliance period (which, in general, is applicable when the aggregate revolving borrowings and issued revolving LCs (in excess of (i) $50 million of undrawn revolving LCs; and (ii) cash collateralized or backstopped LCs) exceed 35% of the revolving commitments under the RCF), the Credit Agreement includes a covenant that requires TES’s consolidated first lien net leverage ratio not to exceed 2.75 to 1.00 as of June 30, 2023 and increasing through a series of step-ups until 4.25 to 1.00 (to be tested as of June 30, 2024 and thereafter). The financial covenant does not apply to the TLB, TLC, or TLC LCF.
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The Credit Agreement also contains customary representations and warranties and events of default. If an event of default occurs under the Credit Agreement, the lenders thereunder are entitled to take various actions, including accelerating amounts due and, in the case of the RCF and the TLC LCF, terminating commitments.
TLC LCF. The TLC LCF provides commitments for up to $470 million in letters of credit, cash collateralized with the proceeds of the TLC, with commitments thereunder reduced to the extent that borrowings under the TLC are prepaid. The lenders of the TLC have issued LCs totaling $404 million under the TLC LCF, which have been issued either directly to Talen’s counterparties or to lenders under the DIP Facilities to backstop LCs that were previously issued (or continued) thereunder and remain outstanding. These LCs are cash collateralized by $472 million as of December 31, 2023 (Successor) which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets. Additionally, the restricted cash earns interest income, which varies by rate depending on the corresponding letter of credit issuer. The interest income earned on the restricted cash offsets against the calculated effective interest rate for the TLC when determining the computed interest rate.
Bilateral LCF. The Bilateral LC Agreement provides for letter of credit issuances that collectively cannot exceed $75 million and expires in May 2028. The Bilateral LC Agreement contains substantially the same covenants, representations and warranties, and events of default as the Credit Agreement. The Bilateral LCF includes a covenant that requires TES’s consolidated first lien net leverage ratio not to exceed 2.75 to 1.00 as of June 30, 2023 and increasing through a series of step-ups to 4.25 to 1.00 as of June 30, 2024 and thereafter, but such covenant only applies to the extent a compliance period exists under the Credit Agreement. In addition, the Bilateral LC Agreement contains an affirmative covenant requiring disposition of certain minority-owned coal assets. Subject to customary conditions, commitments under the Bilateral LC Agreement can be terminated by the lenders upon an event of default thereunder.
Secured Notes. Interest on the Secured Notes is payable semi-annually on June 1 and December 1 of each year, commencing on December 1, 2023, and at maturity. The Secured Notes are subject to customary negative covenants, including, but not limited to, certain limitations on incurrence of liens and additional indebtedness, making investments, payment of dividends, and transactions involving the Susquehanna assets. The Secured Notes do not contain any financial covenants. The Secured Notes also contain customary affirmative covenants and events of default. If an event of default occurs, the holders of the Secured Notes are entitled to take various actions, including the acceleration of amounts due under the Secured Notes.
PEDFA Bonds. The PEDFA 2009B and 2009C Bonds remained outstanding following Emergence. These bonds are backstopped by LCs totaling $133 million as of December 31, 2023 (Successor). Each series of PEDFA Bonds was issued by the PEDFA on behalf of TES. TES received the proceeds from the original issuance of each series of PEDFA Bonds pursuant to a separate exempt facilities loan agreement. An unsecured promissory note of TES corresponding to each series of PEDFA Bonds contains principal, interest and prepayment provisions of the respective series.
The PEDFA 2009B and 2009C Bonds accrue interest at a variable rate in accordance with the provisions of the trust indentures which is payable monthly. Obligations under the PEDFA 2009B and 2009C Bonds are supported by two irrevocable, direct-pay LCs, each corresponding to the applicable series, that were issued by a third-party lender in favor of the bond trustee in an amount equal to the outstanding principal of each series plus an interest component. Prior to Emergence, TES’s obligation to reimburse the third-party lender for payments made under each irrevocable, direct-pay LC was in turn supported by a corresponding backstop LC issued in favor of such lender. Upon Emergence, the backstop LCs were terminated and the direct-pay LCs are outstanding under the TLC LCF.
The PEDFA 2009B and 2009C Bonds: (i) are subject to mandatory purchase by TES at the option of each holder with at least seven days’ advance notice; (ii) may be redeemed at the option of TES at any time prior to their stated maturity date at a redemption price of 100% of the principal amount thereof plus accrued interest, if any, to the redemption date; (iii) are subject to mandatory purchase and optional remarketing upon conversion to an interest rate other than the daily rate as defined in the trust indentures or upon the cancellation, termination, expiration or substitution of the irrevocable, direct-pay LC corresponding to the applicable series; and (iv) are subject to mandatory purchase upon an event of default under the Credit Agreement.
F-98
Each series of PEDFA Bonds is subject to customary affirmative and negative covenants appropriate for such indebtedness. The loan agreements relating to the PEDFA Bonds do not limit TES’s ability to incur additional secured or unsecured indebtedness. Each series of PEDFA Bonds also contains customary events of default. If an event of default occurs, the holders of each series of PEDFA Bonds will be entitled to take various actions, including the acceleration of any outstanding amounts due. The Restructuring constituted an event of default under PEDFA Series 2009A bonds, but was not an event of default under the PEDFA 2009B and 2009C Bonds. The PEDFA 2009B and 2009C Bonds continue to be supported by the irrevocable, direct-pay LCs described above and TES continues to perform its associated reimbursement obligations.
Secured ISDAs. Talen Energy Marketing is party to certain Secured ISDAs, a portion of which are continuations of either the Prepetition Secured ISDAs or the DIP Secured ISDAs. Under the Secured ISDAs, TES and the Subsidiary Guarantors provide the applicable counterparties with a first priority lien on and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs. The secured obligations under the Secured ISDAs were approximately $58 million as of December 31, 2023 (Successor).
Security Interests, Guarantees, and Cross-Defaults on TES Post-Emergence Obligations
Secured Obligations. The obligations under the Credit Facilities, Secured Notes, and Secured ISDAs are secured by a first priority lien on and security interest in substantially all of the assets of TES and the Subsidiary Guarantors. The LCs issued pursuant to the TLC LCF are cash collateralized by $472 million as of December 31, 2023 (Successor) (which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets), with such amounts being held in restricted collateral accounts, first, for the benefit of the issuers of LCs pursuant to the TLC LCF and, thereafter, as security for the obligations under the Credit Facilities (other than the TLC LCF), Secured Notes, and Secured ISDAs.
The Subsidiary Guarantors guarantee the obligations of TES under the Credit Facilities and the Secured Notes. TES and the Subsidiary Guarantors guarantee the obligations of Talen Energy Marketing under the Secured ISDAs. The maximum amount of potential future payments by the Subsidiary Guarantors is equal to the maximum amount of outstanding obligations under such agreements and may include unpaid interest, premiums, penalties, and (or) other fees and expenses. An event of default under the Credit Facilities, Secured Notes, or Secured ISDAs, if not cured or waived, may result in a cross acceleration of amounts due and (or) cross termination across all these agreements.
Unsecured Obligations. The PEDFA 2009B and 2009C Bonds are senior unsecured obligations of TES that are effectively subordinated to the secured obligations of TES, including the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing such secured obligations.
The guarantees under the PEDFA 2009B and 2009C Bonds are the general unsecured obligations of the Subsidiary Guarantors that guarantee such indebtedness, rank equally with all of such Subsidiary Guarantors’ other senior unsecured indebtedness, and are effectively subordinated to the secured obligations of the Subsidiary Guarantors, including the Credit Facilities, Secured Notes, and Secured ISDAs, to the extent of the value of the assets securing such secured obligations.
Non-Recourse Debt and Other Credit Facilities
Cumulus Digital TLF. In September 2021, Cumulus Digital executed the Cumulus Digital TLF, which provided for up to $175 million in aggregate principal borrowings and matures in September 2027. Cumulus Digital borrowed $60 million at closing of the loan transaction, and made additional borrowings over time to fund Cumulus Coin’s contributions to Nautilus and Cumulus Data’s construction of certain data center electrical infrastructure that will support the operations of both Cumulus Data and Nautilus. In connection with a settlement in connection with the Restructuring, Cumulus Digital borrowed the remaining available principal amount in the third quarter 2022. The Cumulus Digital TLF were paid in full on March 1, 2024, together with all accrued interest and other outstanding amounts.
F-99
In March 2023, the Cumulus Digital TLF was amended to, among other things, add a requirement that Cumulus Digital procure up to $16 million in equity funding for Cumulus Data to complete construction of the first data center shell and related infrastructure. The required funding was provided during the second quarter 2023.
Interest on outstanding borrowings was payable quarterly at 12.50% per annum. Interest was initially payable in cash or, at Cumulus Digital’s election for the first four quarterly payment dates, 10% in cash with the remaining 2.50% capitalized as additional principal. In connection with a settlement in connection with the Restructuring, the Cumulus Digital TLF was amended to provide that all interest that accrued thereunder from July 1, 2022 through June 30, 2023 was capitalized as additional principal, and thereafter paid in cash.
The Cumulus Digital TLF was subject to customary representations and warranties, affirmative covenants, negative covenants, and events of default. Notable covenants included limitations on incurrence of liens and additional indebtedness, payment of dividends and asset sales. The Cumulus Digital TLF was subject to customary events of default, including: nonpayment of principal or interest when due, breach of covenants, and the bankruptcy of Cumulus Digital Holdings or any of its subsidiaries. It was also an event of default if TEC filed for bankruptcy while the TEC guarantee described below was in effect. This event of default was waived for purposes of TEC's inclusion in the Restructuring in December 2022, provided that the guarantee was assumed by TEC in the Restructuring as contemplated in the Plan of Reorganization.
Obligations under the Cumulus Digital TLF were secured equally and ratably by first priority liens and security interests in substantially all the assets of Cumulus Digital and its subsidiaries (other than the assets of Nautilus), as well as a pledge of equity in Cumulus Digital by its direct parent, Cumulus Digital Holdings. These liens and security interests were released upon the payment in full of the Cumulus Digital TLF on March 1, 2024.
All obligations under the Cumulus Digital TLF were guaranteed by Cumulus Digital Holdings and each of Cumulus Digital’s subsidiaries (other than Nautilus). The guarantee was terminated upon the payment in full of the Cumulus Digital TLF on March 1, 2024.
TEC provided a guarantee to the lenders under the Cumulus Digital TLF for certain shortfalls in principal and interest payments by Cumulus Digital (up to a maximum of 23% of the principal amount of outstanding loans under the Cumulus Digital TLF). The guarantee was terminated upon the payment in full of the Cumulus Digital TLF on March 1, 2024.
Additionally, TES provided $50 million in LCs to Orion to support certain of Cumulus Digital’s obligations under the Cumulus Digital TLF. The LCs could be drawn upon, among other events: (i) the acceleration of the Cumulus Digital TLF due to an event of default; or (ii) a bankruptcy of Cumulus Digital. Cumulus Digital Holdings agreed to issue additional common equity to TES to reimburse it for any amounts drawn on the LCs. Cumulus Digital also agreed to reimburse TES for fees associated with the LCs, in the form of cash or common equity in Cumulus Digital Holdings. These LCs were cancelled upon the prepayment in full of the Cumulus Digital TLF on March 1, 2024.
See Note 12 for information on the guarantee issued by TEC and the LCs issued by TES related to the Cumulus Digital TLF.
LMBE-MC Credit Agreement. LMBE-MC was the borrower under the LMBE-MC Credit Agreement, which included the LMBE-MC RCF and the LMBE-MC TLB. LMBE-MC and its subsidiaries were not included in the Restructuring and therefore the Restructuring was not an event of default under the LMBE-MC Credit Agreement or the facilities thereunder. The LMBE-MC facilities were repaid, and the LMBE-MC Credit Agreement terminated, in August 2023. See “2023 Transactions - LMBE-MC Refinancing” for additional information.
14. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT.
F-100
The classifications of recurring fair value measurements within the fair value hierarchy were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Netting (a) | Total | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 9 | $ | — | $ | 9 | $ | — | $ | — | $ | — | $ | 6 | $ | 6 | ||||||||||||||||||||||||||||||||||||||||||||||
Equity securities (b) | 629 | — | — | 384 | — | 1,013 | 508 | — | — | 429 | 937 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 337 | — | — | — | — | 337 | 272 | — | — | — | 272 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | 86 | — | — | — | 86 | — | 91 | — | — | 91 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 156 | — | — | — | 156 | — | 114 | — | — | 114 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | (26) | (20) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | 966 | 242 | — | 393 | — | 1,575 | 780 | 205 | — | 435 | 1,400 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | 98 | 196 | — | — | (200) | 94 | 1,807 | 565 | 12 | — | 2,384 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 1 | — | — | — | 1 | — | 9 | — | — | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total assets | $ | 1,064 | $ | 439 | $ | — | $ | 393 | $ | (200) | $ | 1,670 | $ | 2,587 | $ | 779 | $ | 12 | $ | 435 | $ | 3,793 | ||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives (d) | 155 | 139 | — | — | (257) | 37 | 1,879 | 411 | — | — | 2,290 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 6 | — | — | 6 | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Less: other | — | — | — | — | — | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | $ | 155 | $ | 145 | $ | — | $ | — | $ | (257) | $ | 43 | $ | 1,879 | $ | 410 | $ | — | $ | — | $ | 2,289 | ||||||||||||||||||||||||||||||||||||||||||||||
__________________
(a)Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b)Includes commingled equity and fixed income funds and real estate investment trusts.
(c)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
(d)As of December 31, 2022 (Predecessor) certain amounts were presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. See Note 4 for additional information.
Nonrecurring Fair Value Measurements
See Note 4 for information on the nonrecurring fair value measurements resulting in the application of fresh start accounting and Note 10 for information on the nonrecurring fair value measurement of Brandon Shores during the year ended December 31, 2023 (Successor). There were no nonrecurring fair value measurements related to impairments of long-lived assets during the nine months ended September 30, 2022 (Predecessor).
Reported Fair Value
The carrying value of certain assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents,” “Restricted cash and cash equivalents,” “Accounts receivable, net,” and “Accounts payable and other accrued liabilities” approximate fair value.
The fair value measurements of indebtedness are classified as Level 2 within the fair value hierarchy. The fair value of fixed rate debt was estimated primarily by utilizing an income approach whereby the future cash flows of the obligations are discounted at the estimated current cost of funding rates, which incorporates the credit risk associated with the obligations. The carrying value of variable rate indebtedness approximates fair value.
F-101
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||||||
| Revolving credit facilities | $ | — | $ | — | $ | 848 | $ | 848 | ||||||||||||||||||
Long-term debt (a) | 2,820 | 2,934 | 5,062 | 4,386 | ||||||||||||||||||||||
Other short-term indebtedness (b) | 6 | 6 | — | — | ||||||||||||||||||||||
__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
(b)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
15. Postretirement Benefit Obligations
Talen Energy Supply and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and defined contribution plans.
Pension and Other Postretirement Defined Benefit Plans
Obligations under the defined benefit pension and other postretirement plans are generally based on factors, among others, such as age of the participants, years of service, and compensation. The pension and other postretirement plans are closed to new participants. Effective December 31, 2018, all participants ceased accruing additional benefits in the TERP, the Company's largest defined benefit pension plan.
Funded Status. The net fair value of underfunded defined benefit pension and other postretirement plans are presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets. Certain other postretirement plans were overfunded by $33 million, $28 million as of December 31, 2023 (Successor) and 2022 (Predecessor) and are presented as “Other noncurrent assets” on the Consolidated Balance Sheets. The current portion of certain unfunded postretirement obligations were not material.
F-102
The aggregate funded status and the weighted average assumptions were:
| Pension Benefits | ||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation beginning balance | $ | 1,300 | $ | 1,273 | $ | 1,721 | ||||||||||||||
| Service cost | 2 | 1 | 4 | |||||||||||||||||
| Interest cost | 40 | 25 | 50 | |||||||||||||||||
| Actuarial (gain) loss | 20 | 6 | (408) | |||||||||||||||||
| Actual benefits paid | (55) | (34) | (94) | |||||||||||||||||
| Special termination benefits | 1 | — | — | |||||||||||||||||
Benefit obligation ending balance | 1,308 | 1,271 | 1,273 | |||||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Plan assets fair value beginning balance | 997 | 994 | 1,437 | |||||||||||||||||
| Actual return on plan assets | 24 | 35 | (359) | |||||||||||||||||
| Employer contributions | 9 | 2 | 10 | |||||||||||||||||
| Actual benefits paid | (55) | (34) | (94) | |||||||||||||||||
Plan assets fair value ending balance | 975 | 997 | 994 | |||||||||||||||||
Funded status | $ | (333) | $ | (274) | $ | (279) | ||||||||||||||
Accumulated benefit obligation | $ | 1,308 | $ | 1,271 | $ | 1,273 | ||||||||||||||
| Aggregate amounts of underfunded plans | ||||||||||||||||||||
| Benefit obligation/Accumulated benefit obligation | 1,308 | 1,271 | 1,273 | |||||||||||||||||
| Fair value of plan assets | 975 | 997 | 994 | |||||||||||||||||
| Amounts recognized in accumulated other comprehensive income | ||||||||||||||||||||
| Net (gain) loss | 37 | 238 | 239 | |||||||||||||||||
Total accumulated other comprehensive income | $ | 37 | $ | 238 | $ | 239 | ||||||||||||||
| Assumptions | ||||||||||||||||||||
| Discount rate | 5.00 | % | 5.37 | % | 5.41 | % | ||||||||||||||
| Interest crediting rate | 6.00 | % | 6.00 | % | 6.00 | % | ||||||||||||||
| Rate of compensation increase | 3.45 | % | 3.45 | % | 3.45 | % | ||||||||||||||
F-103
| Other Postretirement Benefits | ||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Change in benefit obligation | ||||||||||||||||||||
| Benefit obligation beginning balance | $ | 78 | $ | 77 | $ | 104 | ||||||||||||||
| Service cost | 1 | — | 2 | |||||||||||||||||
| Interest cost | 2 | 1 | 3 | |||||||||||||||||
| Actuarial (gain) loss | 1 | 1 | (24) | |||||||||||||||||
| Plan participant contributions | 2 | 1 | 2 | |||||||||||||||||
| Actual benefits paid | (5) | (4) | (10) | |||||||||||||||||
Benefit obligation ending balance | 79 | 76 | 77 | |||||||||||||||||
| Change in plan assets | ||||||||||||||||||||
| Plan assets fair value beginning balance | 74 | 75 | 99 | |||||||||||||||||
| Actual return on plan assets | 4 | 2 | (17) | |||||||||||||||||
| Employer contributions | — | — | 1 | |||||||||||||||||
| Plan participant contributions | 2 | 1 | 2 | |||||||||||||||||
| Actual benefits paid | (5) | (4) | (10) | |||||||||||||||||
Plan assets fair value ending balance | 75 | 74 | 75 | |||||||||||||||||
Funded status | $ | (4) | $ | (2) | $ | (2) | ||||||||||||||
Accumulated benefit obligation | $ | — | $ | — | $ | — | ||||||||||||||
| Aggregate amounts of underfunded plans | ||||||||||||||||||||
| Benefit obligation / Accumulated benefit obligation | 78 | 76 | 51 | |||||||||||||||||
| Fair value of plan assets | 75 | 74 | 21 | |||||||||||||||||
| Amounts recognized in accumulated other comprehensive income | ||||||||||||||||||||
| Net (gain) loss | (1) | 4 | 4 | |||||||||||||||||
| Prior service cost (credit) | — | (4) | (4) | |||||||||||||||||
Total accumulated other comprehensive income | $ | (1) | $ | — | $ | — | ||||||||||||||
| Assumptions | ||||||||||||||||||||
| Discount rate | 5.01 | % | 5.36 | % | 5.41 | % | ||||||||||||||
| Rate of compensation increase | 2.31 | % | 2.31 | % | 2.31 | % | ||||||||||||||
In 2022 (Predecessor), the decrease in postretirement benefit obligations was primarily attributable to increasing interest rates, offset by actual returns being less than expected returns on plan assets.
Net Periodic Benefit Cost and Amounts Recognized in OCI. Service cost is presented as “Postretirement benefits service (credit) costs, net”, while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Operation, maintenance and development” on the Consolidated Statements of Operations. The portion of net periodic benefit cost capitalized during the periods from May 18 through December 31, 2023 (Successor), January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor) was not material.
F-104
The components of net periodic benefit cost (credit), the amounts recognized in OCI and the associated weighted average assumptions for pension and other postretirement plans were:
| Pension Benefits | ||||||||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Net periodic benefit costs (credits): | ||||||||||||||||||||||||||
| Service cost | $ | 2 | $ | 1 | $ | 4 | $ | 4 | ||||||||||||||||||
| Interest cost | 40 | 25 | 50 | 47 | ||||||||||||||||||||||
| Expected return on plan assets | (41) | (30) | (68) | (67) | ||||||||||||||||||||||
| Amortization of net (gain) loss | — | 2 | 27 | 52 | ||||||||||||||||||||||
| Special termination benefits | 1 | — | — | — | ||||||||||||||||||||||
Net periodic defined benefit cost (credit) | 2 | (2) | 13 | 36 | ||||||||||||||||||||||
Net actuarial (gain) loss | 38 | 2 | 19 | (151) | ||||||||||||||||||||||
| Reclassifications due to settlement and (or) curtailment: | ||||||||||||||||||||||||||
| Amortization of net (gain) loss | — | — | (27) | (52) | ||||||||||||||||||||||
Total recognized in OCI | 38 | 2 | (8) | (203) | ||||||||||||||||||||||
Total recognized in net periodic costs and OCI | $ | 40 | $ | — | $ | 5 | $ | (167) | ||||||||||||||||||
| Assumptions | ||||||||||||||||||||||||||
| Discount rate | 5.12 | % | 5.41 | % | 2.97 | % | 2.67 | % | ||||||||||||||||||
| Rate of compensation increase | 3.45 | % | 3.45 | % | 3.45 | % | 2.96 | % | ||||||||||||||||||
| Expected return on plan assets | 7.25 | % | 7.50 | % | 5.75 | % | 5.75 | % | ||||||||||||||||||
| Other Postretirement Benefits | ||||||||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Net periodic benefit costs (credits): | ||||||||||||||||||||||||||
| Service cost | $ | 1 | $ | 1 | $ | 1 | $ | 2 | ||||||||||||||||||
| Interest cost | 2 | 1 | 3 | 3 | ||||||||||||||||||||||
| Expected return on plan assets | (2) | (2) | (4) | (4) | ||||||||||||||||||||||
| Amortization of prior service cost (credit) | — | — | (1) | (1) | ||||||||||||||||||||||
Net periodic defined benefit cost (credit) | 1 | — | (1) | — | ||||||||||||||||||||||
Net actuarial (gain) loss | (1) | — | (3) | — | ||||||||||||||||||||||
| Reclassifications due to settlement and (or) curtailment: | ||||||||||||||||||||||||||
| Amortization of prior service cost (credit) | — | — | 1 | 1 | ||||||||||||||||||||||
| Amortization of net (gain) loss | — | — | (1) | — | ||||||||||||||||||||||
Total recognized in OCI | (1) | — | (3) | 1 | ||||||||||||||||||||||
Total recognized in net periodic costs and OCI | $ | — | $ | — | $ | (4) | $ | 1 | ||||||||||||||||||
| Assumptions | ||||||||||||||||||||||||||
| Discount rate | 5.13 | % | 5.41 | % | 2.94 | % | 2.57 | % | ||||||||||||||||||
| Rate of compensation increase | 2.31 | % | 2.31 | % | 2.31 | % | 2.61 | % | ||||||||||||||||||
| Expected return on plan assets | 5.49 | % | 5.74 | % | 3.89 | % | 3.89 | % | ||||||||||||||||||
Health care grading trend rates (a) | 6.50% to 4.50% | 6.50% to 4.50% | 4.50 | % | 6.75% to 4.93% | |||||||||||||||||||||
__________________
(a)Trend rates grading to 2027.
F-105
The expected long-term rates of return for pension and other postretirement plans are based on management's projections using a best-estimate of expected returns, volatilities and correlations for each asset class. Each plan's specific current and expected asset allocations are also considered in developing a reasonable return assumption.
Contributions and Payments. Talen Energy Supply contributed $5 million to the TES sponsored pension plan during the period from May 18 through December 31, 2023 (Successor). There were no contributions for the pension plans during the period from January 1 through May 17, 2023 (Predecessor), and the year ended December 31, 2022 (Predecessor). Talen Montana contributed $4 million, $2 million and $10 million of discretionary contributions to the Talen Montana sponsored pension plan during the period from May 18 through December 31, 2023 (Successor), January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor) to the Talen Montana pension plan.
TES expects to contribute $30 million to the TES sponsored pension plan in 2024. Talen Montana expects to contribute $10 million of discretionary contributions to the Talen Montana sponsored pension plan in 2024, of which $7 million is expected to be collected by Talen Montana from the other joint owners of Colstrip.
The aggregate benefits paid to pension and other postretirement plan participants was $60 million during the period from May 18 through December 31, 2003 (Successor), $38 million from January 1 through May 17, 2023 (Predecessor), $104 million in 2022 (Predecessor), and $117 million in 2021 (Predecessor).
The forecasted undiscounted benefit payments to plan participants as of December 31, 2023 (Successor) were:
| 2024 | 2025 | 2026 | 2027 | 2028 | 2029-2033 | ||||||||||||||||||||||||||||||
| Pension plans | $ | 97 | $ | 93 | $ | 93 | $ | 93 | $ | 93 | $ | 456 | |||||||||||||||||||||||
| Other postretirement plans | 7 | 7 | 7 | 6 | 6 | 27 | |||||||||||||||||||||||||||||
Pension plan assets. Pension plan assets are held in external trusts, including a master trust, which includes a 401(h) account that is restricted for certain other postretirement benefit obligations of Talen Energy Supply. The plans' investment policies outline investment objectives.
The risk management framework categorizes the plan assets within three sub-portfolios: growth, immunizing and liquidity. The trust investments within these portfolios are routinely monitored to seek a risk-adjusted return on a mix of assets that, in combination with our funding policy, will provide sufficient assets to provide long-term growth and liquidity for benefit payments, match asset duration with the expected liability duration, and mitigate concentrations of risk with asset diversification.
The weighted-average target asset allocations for the pension plan assets as of December 31, 2023 (Successor) were:
| 2023 | |||||
| Equity securities | 32 | % | |||
| Debt securities | 10 | % | |||
| Other | 7 | % | |||
Growth portfolio | 49 | % | |||
| Debt securities | 36 | % | |||
| Other | 11 | % | |||
Immunizing portfolio | 47 | % | |||
| Liquidity portfolio | 4 | % | |||
Total | 100 | % | |||
F-106
The classification of pension plan asset fair value measurements within the fair value hierarchy were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Total | Level 1 | Level 2 | Level 3 | NAV | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 169 | $ | 169 | $ | — | $ | — | $ | — | $ | 102 | $ | 102 | ||||||||||||||||||||||||||||||||||||||||||
| Commingled equity securities | 288 | 288 | 292 | 292 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt securities | — | — | — | 301 | 301 | — | — | — | 349 | 349 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Alternative and other investments | 52 | — | — | 191 | 243 | 1 | — | — | 236 | 237 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (a) | (25) | 22 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total trust funds | 52 | — | — | 949 | 976 | 1 | — | — | 979 | 1,002 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Restricted 401(h) assets (b) | (1) | (8) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total plan assets | $ | 52 | $ | — | $ | — | $ | 949 | $ | 975 | $ | 1 | $ | — | $ | — | $ | 979 | $ | 994 | ||||||||||||||||||||||||||||||||||||||||||
___________________
(a)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
(b)Other postretirement 401(h) benefits assets are a component of the pension plan master trust. Accordingly, these are excluded from pension plan assets.
Level 1 investments consist of U.S. Treasury and (or) U.S. government debt securities and exchange-traded futures contracts, which are valued using unadjusted prices available from the underlying market.
Certain investments in cash equivalent funds, commingled equity securities, commingled debt securities, and alternative investments are not classified within the fair value hierarchy. The fair value measurement of these funds is based on firm quotes of NAV per share, as a practical expedient for valuation, which are not obtained from a quoted price in an active market.
Investments in cash equivalent funds consist of short-term investment funds and commingled cash equivalent funds. Investments in equity funds consist of large and small cap U.S. and international funds that can be redeemed daily. Investments in commingled debt funds consist of funds that invest in investment-grade intermediate and long-duration corporate and government fixed-income securities. These investments can be redeemed daily.
Alternative and other investments consist of investments in funds that invest in a portfolio of exchange-traded futures and forward contracts, hedge funds of funds that employ investment strategies including long/short equity, market neutral, distressed debt, and relative value, private equity partnerships, with limited lives ranging from ten to fifteen years, and real estate investment partnerships. Investments in real estate partnerships have redemption limitations based on available funding and investments in private equity partnerships that cannot be redeemed with the partnership prior to the end of the partnerships' lives, however, the interest may be sold to other parties. Redemptions of hedge funds, private equity, and real estate partnerships are also subject to the respective general partner's approval.
Other postretirement benefit plan assets. The investment strategy with respect to most of the other postretirement benefit obligations is to fund VEBA or similar trusts and (or) 401(h) accounts with voluntary contributions, when appropriate, and to invest in a tax efficient manner. Excluding the 401(h) accounts included in the master trust, other postretirement benefit plans are invested in a mix of assets for long-term growth with an objective of earning returns that provide liquidity as required for benefit payments. These plans benefit from diversification of asset types, investment fund strategies and investment fund managers, and therefore, have no significant concentration of risk. Equity securities include investments in domestic large-cap commingled funds. Ownership interests in commingled funds that invest entirely in debt securities are classified as equity securities but treated as debt securities for asset allocation and target allocation purposes. Ownership interests in money market funds are treated as cash and cash equivalents for asset allocation and target allocation purposes.
F-107
The target asset allocations for other postretirement benefit assets at December 31 were:
| 2023 | |||||
| Cash and cash equivalents | 7 | % | |||
| Equity securities | 11 | % | |||
| Debt securities | 82 | % | |||
Total | 100 | % | |||
The classification of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| December 31, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Total | Level 1 | Level 2 | Level 3 | NAV | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 7 | $ | 7 | $ | — | $ | — | $ | — | $ | 7 | $ | 7 | ||||||||||||||||||||||||||||||||||||||||||
| Commingled equity securities | — | — | — | 9 | 9 | — | — | — | 7 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 8 | — | — | — | 8 | 6 | — | — | — | 6 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 16 | — | — | 16 | — | 17 | — | — | 17 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt securities | — | — | — | 34 | 34 | — | — | — | 31 | 31 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Total trust funds | 8 | 16 | — | 50 | 74 | 6 | 17 | — | 45 | 68 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
Restricted 401(h) assets (a) | 1 | 7 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total plan assets | $ | 8 | $ | 16 | $ | — | $ | 50 | $ | 75 | $ | 6 | $ | 17 | $ | — | $ | 45 | $ | 75 | ||||||||||||||||||||||||||||||||||||||||||
___________________
(a)Other postretirement 401(h) benefits assets are a component of the pension plan master trust. Accordingly, these are reported as postretirement assets.
Level 1 investments consist of U.S. Treasury and (or) U.S. government debt securities, which are valued using unadjusted prices available from the underlying market.
Level 2 investments consist of corporate debt securities, which are valued using observable inputs such as benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities, and credit valuation adjustments.
Certain investments in money market funds, commingled equity securities, and commingled debt securities are not classified within the fair value hierarchy. The fair value measurements of these funds are based on firm quotes of NAV per share, as a practical expedient for valuation, which are not obtained from a quoted price in an active market.
Investments in equity securities consist of investments in a passively managed equity index fund that invests in securities and a combination of other collective funds. Investments in debt securities represent investments in funds that invest in a diversified portfolio of investment grade fixed income securities.
Defined Contribution Plans
Substantially all Company employees are eligible to participate in 401(k) deferred savings plans. Employer contributions to the plans were $9 million, $10 million, and $18 million during the period from May 18 through December 31, 2023 (Successor), January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor).
Coal Industry Retiree Benefit Plans
Talen is obligated under the Coal Act and the Black Lung Act to pay for certain health care and black lung benefits of retired miners and allowable beneficiaries. These obligations are funded from medical VEBAs and a black lung trust.
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The funded status of each plan at December 31, 2023 (Successor) were:
Trust Asset Fair Value | Obligation Fair Value | Overfunded Status | |||||||||||||||
| Benefit Plan for UMWA Represented Retirees of Pennsylvania Mines, LLC | $ | 30 | $ | 18 | $ | 12 | |||||||||||
| Coal Worker's Pneumoconiosis (Black Lung) Benefit Plan | 11 | 6 | 5 | ||||||||||||||
Shortfalls in funded status of the plans are assessed as contingent liabilities. As the fair value of VEBA and black lung trust assets exceed the plan obligations, both VEBA and black lung trust assets and the plan obligations are not reported on the Talen Consolidated Balance Sheets. See “Postretirement Benefit Obligations” in Note 2 for additional information.
16. Capital Structure
Successor
Our Third Amended and Restated Certificate of Incorporation, which became effective at Emergence, authorizes TEC to issue up to 400,000,000 shares of capital stock, consisting of 350,000,000 shares of common stock, par value $0.001 per share, and 50,000,000 shares of preferred stock, par value $0.01 per share. At Emergence, TEC issued 59,028,843 shares of common stock. The same number of shares remained outstanding as of December 31, 2023 (Successor). No shares of preferred stock are outstanding.
Each share of common stock entitles the record holder to one vote on all matters on which stockholders generally are entitled to vote. Subject to the rights of the holders of preferred stock, if any, the holders of shares of common stock are entitled to receive dividends and other distributions (payable in cash, property or capital stock of TEC) when, as and if declared thereon by the Board of Directors.
Registration Rights Agreement and Stockholders Agreement. In connection with Emergence, TEC entered into a Registration Rights Agreement and a Stockholders Agreement with certain of its stockholders . Under the Registration Rights Agreement, the Reg Rights Holders were granted customary registration rights that may be exercised after the consummation of an initial public offering by the Company, including customary shelf registration rights and piggyback rights. Pursuant to the Stockholders Agreement, the holders party thereto have certain limited information rights, drag-along rights and tag-along rights, and holders holding 5% or more of common stock have the right to designate a representative to an offering committee that, so long as the aggregate TEC ownership represented on the offering committee is at least 20%, will have rights to require TEC to pursue and consummate an initial public offering and to consent to certain key elements of the initial public offering structure.
Equity-Classified Warrants. Pursuant to an employment agreement with a former executive, at Emergence, the Company issued equity-classified warrants to the executive to purchase up to 457,142 shares common stock with a tenor of seven years and a strike price of $43.75, subject to adjustment in certain circumstances. The equity-classified warrants were valued at $8 million using the above strike price, 30.0% volatility, and a risk-free rate of 3.6%.
Liability-Classified Warrants. At Emergence, Riverstone received liability-classified warrants to purchase up to 5%, or 3,106,781 shares of TEC’s common stock with: (i) a tenor of five years; (ii) a strike price of $52.92, subject to adjustment in certain circumstances; (iii) Black-Scholes protection in the event of certain change of control transactions; and (iv) a contingent put option providing Riverstone the right to require that the Company redeem the warrants in cash upon certain change of control events.
F-109
In the third quarter 2023, TEC, TES, and Riverstone completed a transaction pursuant to which: (i) Riverstone surrendered all of its warrants to purchase TEC common stock to TEC and waived all future rights to the Retail PPA Incentive Equity; and (ii) TEC, TES and Riverstone terminated and canceled a tax indemnity agreement executed by them in connection with the TEC Global Settlement. TEC paid Riverstone $40 million in exchange for these cancellations and waivers and recognized a gain of $9 million presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations for the period from May 18 through December 31, 2023 (Successor).
Riverstone Cumulus Digital Buyout. In the third quarter 2023, Riverstone and TES completed a transaction in which TES purchased all of the Class A common units of Cumulus Digital Holdings held by Riverstone for an aggregate purchase price of $20 million (the “Riverstone Buyout”), of which TES paid $19 million. Affiliates of Orion also elected to participate in the Riverstone Buyout and acquired an additional 1% interest under the terms of the Cumulus Digital Holdings limited liability company agreement. Upon closing, TES’s ownership interest in Cumulus Digital Holdings increased to approximately 95%. TES has sole control of Cumulus Digital Holdings’ board of managers following the closing of the Riverstone Buyout.
Retail PPA Incentive Equity. Pursuant to the Plan of Reorganization and the TEC Global Settlement, at Emergence, the Company issued approximately 243,000 shares of TEC common stock to Riverstone in partial satisfaction of Riverstone’s right to the Retail PPA Incentive Equity. The Retail PPA Incentive Equity also included a right of Riverstone to receive additional TEC common stock (or, at TEC’s option, a cash payment) in the event Cumulus Data exercised an option with Talen Generation to purchase additional electricity generated by Susquehanna, as further described in the Plan of Reorganization. In August 2023, Riverstone agreed to waive its right to this additional portion of the Retail PPA Incentive Equity in exchange for a cash payment.
Share Repurchase Program. In October 2023, the Board of Directors approved a share repurchase program authorizing the Company to repurchase up to $300 million of the Company’s outstanding common stock through December 31, 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. In January 2024, the Company repurchased 225,000 shares of common stock for $14 million at a weighted average per share price of $63.52.
Orion Cumulus Digital Buyout. On March 11, 2024, TES acquired all of the equity units of Cumulus Digital Holdings held by affiliates of Orion in exchange for $36 million in cash. Following the transaction, TES owns 99.5% of the equity of Cumulus Digital Holdings, with the remaining 0.5% held by two former members of Talen senior management.
Predecessor
As of December 31, 2022 (Predecessor), outstanding shares of TEC owned by Riverstone affiliates and Talen MidCo LLC were:
Talen MidCo LLC | Raven Power Holdings, LLC | C/R Energy Jade, LLC | Sapphire Power Holdings LLC | ||||||||||||||||||||
| Shares (in thousands) | 221 | 130 | 83 | 16 | |||||||||||||||||||
These shares were cancelled upon Emergence pursuant to the Plan of Reorganization.
F-110
17. Stock-Based Compensation
In June 2023, TEC began granting performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors under the 2023 Talen Equity Plan. The aggregate number of shares authorized for issuance under the 2023 Talen Equity Plan is 7,083,461 shares.
Performance Stock Units
PSUs vest three years after Emergence or a consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs. The following table summarizes the Company’s non-vested PSUs and changes during the year:
| Units | Weighted-Average Grant Date Fair Value per Unit | ||||||||||
| Non-vested as of May 18, 2023 (Successor) | — | $ | — | ||||||||
| Granted | 968,793 | 54.35 | |||||||||
Non-vested as of December 31, 2023 (Successor) | 968,793 | $ | 54.35 | ||||||||
There were no forfeited or vested PSUs for the period from May 18 through December 31, 2023 (Successor). The fair value of the PSUs was determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date and the significant inputs and assumptions summarized below:
| PSUs | |||||
Volatility (a) | 25 | % | |||
| Expected term (in years) | 3 | ||||
Risk-free rate (b) | 4.35% - 4.59% | ||||
__________________
(a)Derived from an option pricing method based on the average asset volatility of peer companies and the Company’s leverage ratio.
(b)Grant date value derived from U.S. constant maturity treasury rates matching the terms of the PSUs.
Restricted Stock Units
RSUs have three-year graded vesting schedules beginning on the grant date. The fair value of the RSUs granted is derived from the closing price of TEC common stock on the grant date. The following table summarizes the Company’s non-vested RSUs and changes during the year:
| Units | Weighted-Average Grant Date Fair Value per Unit | ||||||||||
| Non-vested as of May 18, 2023 (Successor) | — | $ | — | ||||||||
| Granted | 845,269 | 48.46 | |||||||||
Non-vested as of December 31, 2023 (Successor) | 845,269 | $ | 48.46 | ||||||||
There were no forfeited or vested RSUs for the period from May 18 through December 31, 2023 (Successor).
F-111
Stock-based Compensation Expense
Stock-based compensation expense was $19 million for the period from May 18 through December 31, 2023 (Successor) presented as “General and administrative” on the Consolidated Statements of Operations. There was no income tax benefit recognized due to the PSUs and RSUs during the period from May 18 through December 31, 2023 (Successor) and deferred tax assets related to PSUs and RSUs were not material as of December 31, 2023 (Successor).
See Note 2 for additional information regarding our accounting policy for stock-based compensation.
18. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method.
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Numerator: (Millions) | ||||||||||||||||||||||||||
Net Income (loss) | $ | 143 | $ | 465 | $ | (1,293) | $ | (977) | ||||||||||||||||||
| Exclude: | ||||||||||||||||||||||||||
| Net income (loss) attributable to noncontrolling interest | 9 | (14) | (4) | — | ||||||||||||||||||||||
Net Income (loss) attributable to the Company | $ | 134 | $ | 479 | $ | (1,289) | $ | (977) | ||||||||||||||||||
| Denominator: (Thousands) | ||||||||||||||||||||||||||
| Weighted-average shares outstanding - Basic | 59,029 | — | — | — | ||||||||||||||||||||||
| Warrants | 84 | — | — | — | ||||||||||||||||||||||
| Restricted stock units | 166 | — | — | — | ||||||||||||||||||||||
| Performance stock units | 120 | |||||||||||||||||||||||||
Weighted-average shares outstanding - Diluted | 59,399 | — | — | — | ||||||||||||||||||||||
Basic earnings per share | $ | 2.27 | $ | — | $ | — | $ | — | ||||||||||||||||||
Diluted earnings per share | 2.26 | — | — | — | ||||||||||||||||||||||
For the period from May 18 through December 31, 2023 (Successor), basic earnings per share of $2.27 includes 59,028,843 shares of common stock outstanding. For the periods from January 1 through May 17, 2023 and years ended 2022 and 2021 (Predecessor), there were no outstanding shares of common stock.
Diluted earnings per share during the period from May 18 through December 31, 2023 (Successor) excludes 134,798 performance stock units (“PSUs”) outstanding due to their anti-dilutive nature. These awards are excluded from the calculation of EPS because the performance conditions have not been met during the reporting period.
F-112
19. Accumulated Other Comprehensive Income
The total changes in AOCI for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Beginning balance | $ | — | $ | (167) | $ | (152) | $ | (294) | ||||||||||||||||||
| Gains (losses) arising during the period | (36) | 6 | (84) | 138 | ||||||||||||||||||||||
| Reclassifications to Consolidated Statements of Operations | 7 | 5 | 59 | 53 | ||||||||||||||||||||||
| Income tax benefit (expense) | 6 | (5) | 10 | (49) | ||||||||||||||||||||||
Other comprehensive income (loss) | (23) | 6 | (15) | 142 | ||||||||||||||||||||||
| Cancellation of equity at Emergence | 161 | |||||||||||||||||||||||||
Accumulated other comprehensive income | $ | (23) | $ | — | $ | (167) | $ | (152) | ||||||||||||||||||
The components of AOCI, net of tax, as of December 31 were:
| Successor | Predecessor | |||||||||||||||||||
| 2023 | 2022 | 2021 | ||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | 5 | $ | (16) | $ | 4 | ||||||||||||||
| Qualifying derivatives unrealized gain (loss), net | — | 9 | 11 | |||||||||||||||||
| Postretirement benefit prior service credits (costs), net | — | 7 | 6 | |||||||||||||||||
| Postretirement benefit actuarial gain (loss), net | (28) | (167) | (173) | |||||||||||||||||
Accumulated other comprehensive income | $ | (23) | $ | (167) | $ | (152) | ||||||||||||||
The locations of pre-tax gains (losses) reclassified from AOCI and included on the Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| Location of gain (loss) | 2023 | 2023 | 2022 | 2021 | ||||||||||||||||||||||
Nuclear decommissioning trust funds gain (loss), net (a) | $ | (7) | $ | (4) | $ | (33) | $ | (2) | ||||||||||||||||||
Depreciation, amortization and accretion (b) | — | 1 | 2 | 2 | ||||||||||||||||||||||
Operation, maintenance and development (c) | — | — | (1) | (1) | ||||||||||||||||||||||
Other non-operating income (expense), net (d) | — | (2) | (27) | (52) | ||||||||||||||||||||||
Total | $ | (7) | $ | (5) | $ | (59) | $ | (53) | ||||||||||||||||||
__________________
(a)Available-for-sale securities unrealized gain (loss), net.
(b)Qualifying derivatives unrealized gain (loss).
(c)Postretirement benefit prior service credits (costs), net
(d)Postretirement benefit actuarial gain (loss), net.
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 15 for additional information.
F-113
20. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:
| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Cash paid (received) during the period | ||||||||||||||||||||||||||
Interest and other finance charges, net of capitalized interest (a) | $ | 133 | $ | 283 | $ | 277 | $ | 316 | ||||||||||||||||||
| Income taxes, net | 12 | 7 | 14 | 20 | ||||||||||||||||||||||
| Non-cash investing and operating activities | ||||||||||||||||||||||||||
| Capital expenditure accrual increase (decrease) | 7 | (28) | 2 | (2) | ||||||||||||||||||||||
| Accounts receivable contributed to equity method investment | — | — | 2 | 6 | ||||||||||||||||||||||
Non-cash preferred equity method investment contribution and accounts payable accrual (a) | — | — | — | 5 | ||||||||||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Operations: | ||||||||||||||||||||||||||
| Depreciation, amortization and accretion | 165 | 200 | 520 | 524 | ||||||||||||||||||||||
Amortization of deferred finance costs and original issuance discounts (interest expense) (b) | 1 | 8 | 29 | 31 | ||||||||||||||||||||||
| Other | (9) | — | — | — | ||||||||||||||||||||||
Total depreciation, amortization and accretion | $ | 157 | $ | 208 | $ | 549 | $ | 555 | ||||||||||||||||||
| Non-cash financing/investing activities | ||||||||||||||||||||||||||
| Non-cash hypothetical liquidation at book value contribution to equity and noncurrent assets | $ | — | $ | — | $ | — | $ | 11 | ||||||||||||||||||
Non-cash increase to PP&E and decrease to other current assets for transfer of miners by Cumulus Coin (c) | — | 14 | 30 | — | ||||||||||||||||||||||
| Non-cash decrease to PP&E and decrease to noncontrolling interest for transfer of miners to TeraWulf | — | 3 | — | — | ||||||||||||||||||||||
Non-cash increase to PP&E and increase to noncontrolling interest for transfer of miners by TeraWulf (b) | — | 38 | 14 | — | ||||||||||||||||||||||
| Unrealized (gain) loss on derivatives: | ||||||||||||||||||||||||||
| Commodity contracts | (52) | 63 | (625) | 712 | ||||||||||||||||||||||
| Interest rate swap contracts | 12 | 2 | (23) | (28) | ||||||||||||||||||||||
Total unrealized (gain) loss on derivatives | $ | (40) | $ | 65 | $ | (648) | $ | 684 | ||||||||||||||||||
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| Successor | Predecessor | |||||||||||||||||||||||||
| May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Operating activities reconciliation adjustments, other: | ||||||||||||||||||||||||||
| Net periodic defined benefit cost | $ | 2 | $ | (3) | $ | 12 | $ | 36 | ||||||||||||||||||
| Stock-based compensation | 19 | — | — | — | ||||||||||||||||||||||
| Derivative option premium amortization | 52 | 29 | 67 | (176) | ||||||||||||||||||||||
| Bitcoin revenue | (81) | (27) | — | — | ||||||||||||||||||||||
| Non-cash environmental liability revisions | — | — | 13 | — | ||||||||||||||||||||||
| Gain on sale of mineral rights and western gas portfolio | — | (44) | — | — | ||||||||||||||||||||||
| Non-cash ARO revisions | — | — | — | (3) | ||||||||||||||||||||||
| Gain on cancellation of lease | — | (7) | — | — | ||||||||||||||||||||||
| Nonrecourse PIK interest | 3 | 9 | (1) | — | ||||||||||||||||||||||
| Mark-to-market on warrants | 4 | — | — | — | ||||||||||||||||||||||
| Derivatives with financing elements | — | — | 104 | — | ||||||||||||||||||||||
| Debt restructuring (gain) loss, net | 5 | — | 6 | 2 | ||||||||||||||||||||||
| Other | (4) | — | (1) | (9) | ||||||||||||||||||||||
Total | $ | — | $ | (43) | $ | 200 | $ | (150) | ||||||||||||||||||
__________________
(a)Capitalized interest totaled $10 million for May 18 through December 31, $12 million for January 1 through May 17 in 2023, $12 million in 2022, and $4 million in 2021.
(b)Includes previously recognized fair value adjustments on certain exchanges of indebtedness.
(c)In 2023, each of the joint venture partners of Nautilus made non-cash contributions to Nautilus of cryptocurrency miners that increased PP&E.
Cash and Restricted Cash
The following provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Statements of Cash Flows to line items within the Consolidated Balance Sheets:
| Successor | Predecessor | ||||||||||
December 31, 2023 | December 31, 2022 | ||||||||||
Cash and cash equivalents | $ | 400 | $ | 724 | |||||||
| Restricted cash and cash equivalents: | |||||||||||
| Commodity exchange margin | — | 85 | |||||||||
Collateral deposits (a) | — | 89 | |||||||||
| TES TLC debt restricted deposits | 472 | — | |||||||||
| Cumulus Digital Holdings debt restricted deposits | 19 | 49 | |||||||||
| Nautilus project restricted deposits | 10 | 19 | |||||||||
| LMBE-MC major maintenance reserve deposits | — | 7 | |||||||||
LMBE-MC debt service reserve deposits (b) | — | 7 | |||||||||
TEC Global Settlement deposits (c) | — | 7 | |||||||||
| Other | — | 1 | |||||||||
Restricted cash and cash equivalents | 501 | 264 | |||||||||
Total | $ | 901 | $ | 988 | |||||||
__________________
(a)Collateral deposits that supported the DIP LCF. Funds were returned to Talen upon Emergence.
(b)Outstanding indebtedness was repaid in August 2023 and these funds were released. See Note 13 for additional information on the repayment.
(c)Funds were released to a third party upon Emergence.
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21. Related Party Transactions
Registration Rights Agreement and Stockholders Agreement
See Note 16 for information on a Registration Rights Agreement and Stockholders Agreement entered into with certain TEC stockholders at Emergence.
Predecessor Transactions
Prior to the Restructuring, Talen incurred and paid customary management fees for services provided by Riverstone and its affiliates and reimbursed Riverstone for certain costs. In November 2021, Riverstone agreed to suspend Talen’s payment obligations for these management fees. In the third quarter 2022, as a result of the TEC Global Settlement, Talen adjusted the amounts previously accrued for these fees and Riverstone waived further payment of fees following Emergence. The aggregate fees incurred for services and reimbursements were:
| Predecessor | |||||||||||
| Year Ended December 31, | Year Ended December 31, | ||||||||||
| 2022 | 2021 | ||||||||||
Riverstone Holdings, LLC management fees (a) | $ | — | $ | 1 | |||||||
Riverstone Holdings, LLC litigation fees (a) | (5) | 6 | |||||||||
__________________
(a)Presented as “General and administrative” on the Consolidated Statements of Operations. Includes adjustments recognized in September 2022. See below for additional information.
Pursuant to the TEC Global Settlement: (i) upon confirmation of the Plan of Reorganization in December 2022 (Predecessor), TES paid $8 million in fees and expenses of TEC’s professional advisors; and (ii) deposited $7 million in a custodial account presented as “Restricted cash” on the December 31, 2022 (Predecessor) Consolidated Balance Sheets that was to be used to pay fees and expenses of TEC’s advisors when due. The $7 million was paid to TEC’s advisors from the custodial account upon Emergence.
During the year ended December 31, 2022 (Predecessor), as a result of the TEC Global Settlement and UCC Settlement, Talen: (i) reversed $5 million of accrued amounts due to Riverstone for unpaid management fees and expenses presented as “General and administrative”; and (ii) recognized $8 million of charges presented as “Reorganization income (expense), net” on the Consolidated Statements of Operations for TEC advisor fees payable by TES pursuant to the TEC Global Settlement.
Additionally, prior to the Restructuring, TES had paid certain expenses and liabilities incurred by TEC. Accordingly, as of December 31, 2022 (Predecessor), TES carried a $2 million receivable due from TEC presented as “Accounts receivable, net” within the Consolidated Balance Sheets. Such amounts were settled pursuant to the Plan of Reorganization upon Emergence.
See Note 3 for information on the TEC Global Settlement and the UCC Settlement.
During 2022 and 2021, Talen engaged parties related to two employees in management positions, both under two separate independent contractor agreements for office maintenance and IT services. During the years ended December 31, 2022 and 2021 (Predecessor), Talen paid approximately $88 thousand and $140 thousand, respectively, under these agreements. The contracts with these independent contractors were terminated in July 2022.
22. Acquisitions and Divestitures
Potential Acquisition
Talen Montana Colstrip Units 3 and 4 Transaction. In September 2022, Talen Montana entered into an agreement under which Puget Sound Energy, Inc. will abandon its 25% share of Colstrip Units 3 and 4 to Talen Montana for no cash consideration. Under the agreement, Puget Sound will retain certain liabilities attributable to
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pre-closing operations, including environmental remediation and decommissioning costs, and Talen Montana will assume those liabilities for post-closing operations. The agreement is subject to customary closing conditions, including Bankruptcy Court approval. Subject to satisfaction of the closing conditions set forth in the agreement, the parties have agreed on a closing date of December 31, 2025. Talen also has a right of first refusal on any other changes in ownership in Colstrip Units 3 and 4.
Talen Montana did not obtain Bankruptcy Court approval of the agreement and continues to evaluate the circumstances under which it would acquire Puget Sound’s interest in Colstrip Units 3 and 4. In February 2024, Puget Sound informed Talen Montana that it was in breach of the agreement for failing to obtain Bankruptcy Court approval and that the agreement is unenforceable. Talen Montana has agreed that the agreement is unenforceable and disputed that it breached the agreement.
Completed Divestitures
Data Center Campus Sale. On March 1, 2024, the Company completed its disposition of certain assets of Cumulus Data, which included our zero-carbon data center campus currently being developed adjacent to Susquehanna, to Amazon Data Services, Inc. for gross proceeds of $650 million, $300 million of which is to be held in escrow until the achievement of development milestones that are expected to be achieved in 2024. In connection with the Data Center Campus Sale, the Company entered into a power purchase agreement with Amazon Energy LLC, pursuant to which (i) the Company agreed to supply up to 960 MW of long-term, carbon-free power to the Data Center Campus from Susquehanna; (ii) the parties agreed to fixed-price power commitments that increase in 120 MW increments over several years; and (iii) Amazon Energy LLC has a one-time option to cap commitments at 480 MW.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. In 2023, For the period January 1 through May 17, 2023 (Predecessor), a $29 million gain was presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to the transportation of natural gas in the southwestern United States for approximately $15 million. For the period January 1 through May 17, 2023 (Predecessor), a $15 million gain was presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
23. Segments
Talen’s reportable segments are based upon the market areas in which our generation facilities operate and reflect the manner in which our chief operating decision makers review results and allocates resources. Adjusted EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision makers.
Our reportable segments are engaged in electricity generation, marketing activities, commodity risk and fuel management within their respective RTO or ISO markets. The segments include:
•PJM - a reportable segment that includes the operating and marketing activities within the PJM market. PJM is comprised of Susquehanna Nuclear and Talen’s natural gas and coal generation facilities located within the PJM market; and
•ERCOT and WECC - a reportable segment that includes the operating and marketing activities within the ERCOT market for the operations of the Talen Texas power generation facilities, and the operating and marketing activities for Talen Montana’s proportionate share of the Colstrip Units. We have determined it appropriate to aggregate results from these markets into one reportable segment, based on a combination of size and economic characteristics.
Corporate, Development, and Other, or CD&O, represents the remaining non-segment grouping that includes: (i) General and administrative expenses incurred by our corporate and commercial functions that are not allocated to
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our reportable segments; (ii) the development activities of Cumulus Growth Holdings; (iii) the development and operating activities of Cumulus Digital; (iv) other non-material components that are not regularly reviewed by our chief operating decision makers; and (v) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
Financial data for the segments and reconciliation to consolidated results are:
| May 18, 2023 through December 31, 2023 (Successor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 1,114 | $ | 241 | $ | (11) | $ | 1,344 | |||||||||||||||
| Interest expense | — | — | 176 | 176 | |||||||||||||||||||
| Capital expenditures | 111 | 17 | 33 | 161 | |||||||||||||||||||
| Adjusted EBITDA | 376 | 78 | 454 | ||||||||||||||||||||
| January 1, 2023 through May 17, 2023 (Predecessor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 1,052 | $ | 149 | $ | 9 | $ | 1,210 | |||||||||||||||
| Interest expense | — | — | 163 | 163 | |||||||||||||||||||
| Capital expenditures | 131 | 4 | 52 | 187 | |||||||||||||||||||
| Adjusted EBITDA | 687 | 31 | 718 | ||||||||||||||||||||
| Year Ended December 31, 2022 (Predecessor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 2,867 | $ | 313 | $ | (91) | $ | 3,089 | |||||||||||||||
| Interest expense | — | — | 359 | 359 | |||||||||||||||||||
| Capital expenditures | 237 | 10 | 65 | 312 | |||||||||||||||||||
| Adjusted EBITDA | 964 | 105 | 1,069 | ||||||||||||||||||||
| Year Ended December 31, 2021 (Predecessor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 813 | $ | 109 | $ | 6 | $ | 928 | |||||||||||||||
| Interest expense | — | — | 325 | 325 | |||||||||||||||||||
| Capital expenditures | 166 | 21 | 37 | 224 | |||||||||||||||||||
| Adjusted EBITDA | 372 | 61 | 433 | ||||||||||||||||||||
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| Successor | Predecessor | |||||||||||||||||||||||||
May 18 through December 31, | January 1 through May 17, | Year Ended December 31, | Year Ended December 31, | |||||||||||||||||||||||
| 2023 | 2023 | 2022 | 2021 | |||||||||||||||||||||||
| Adjusted EBITDA: | ||||||||||||||||||||||||||
| PJM | $ | 376 | $ | 687 | $ | 964 | $ | 372 | ||||||||||||||||||
| ERCOT and WECC | 78 | 31 | 105 | 61 | ||||||||||||||||||||||
Total Adjusted EBITDA | $ | 454 | $ | 718 | $ | 1,069 | $ | 433 | ||||||||||||||||||
| Reconciling Items: | ||||||||||||||||||||||||||
| Bankruptcy, Liability Management and Restructuring Activities | $ | (48) | $ | 782 | $ | (1,538) | $ | (42) | ||||||||||||||||||
| Interest expense and other finance charges | (181) | (163) | (365) | (336) | ||||||||||||||||||||||
| Income tax benefit (expense) | (51) | (212) | 35 | 300 | ||||||||||||||||||||||
| Depreciation, amortization and accretion | (165) | (200) | (520) | (524) | ||||||||||||||||||||||
| Nuclear fuel amortization | (108) | (33) | (94) | (96) | ||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 52 | (63) | 625 | (712) | ||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 108 | 57 | (184) | 196 | ||||||||||||||||||||||
| Gain (loss) on non-core asset sales, net | 7 | 50 | 3 | 3 | ||||||||||||||||||||||
| Legal settlements and litigation costs | 84 | (1) | (20) | (8) | ||||||||||||||||||||||
| Unusual market events | 19 | (14) | (33) | (78) | ||||||||||||||||||||||
| Impairments, canceled projects, inventory net realizable value and obsolescence, and receivables allowance | (7) | (437) | 4 | (24) | ||||||||||||||||||||||
| Consolidation of subsidiary gain (loss), net | — | — | (170) | — | ||||||||||||||||||||||
| Corporate, development and other | (21) | (19) | (105) | (89) | ||||||||||||||||||||||
Net Income (Loss) | $ | 143 | $ | 465 | $ | (1,293) | $ | (977) | ||||||||||||||||||
24. Subsequent Events
TEC evaluated subsequent events through March 14, 2024, the date the financial statements are available to be issued; all significant subsequent events are included in their respective notes to the financial statements.
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TALEN ENERGY CORPORATION
SCHEDULE I - CONDENSED UNCONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
| Successor | |||||
| (Millions of Dollars, except share data) | May 18 through December 31, 2023 | ||||
Operating Revenues | $ | — | |||
Operating Expenses | — | ||||
Operating Income (Loss) | — | ||||
| Equity in earnings of affiliate | 134 | ||||
Income Before Income Taxes | 134 | ||||
| Income tax benefit (expense) | — | ||||
Net Income | 134 | ||||
Other comprehensive loss of affiliate | (23) | ||||
Comprehensive Income | $ | 111 | |||
| Net Income Per Share of Common Stock: | |||||
| Basic | $ | 2.27 | |||
| Diluted | 2.26 | ||||
| Weighted-Average Shares of Common Stock Outstanding (in thousands): | |||||
| Basic | 59,029 | ||||
| Diluted | 59,399 | ||||
The accompanying Notes to the Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION
SCHEDULE I - CONDENSED UNCONSOLIDATED BALANCE SHEET
| Successor | |||||
| (Millions of Dollars) | December 31, 2023 | ||||
| Assets | |||||
| Investment in affiliate | $ | 2,457 | |||
Total Assets | $ | 2,457 | |||
| Liabilities and Stockholders’ Equity | |||||
| Stockholders’ Equity | |||||
Common stock - $0.001 pay value (a) | $ | — | |||
| Additional paid-in capital | 2,346 | ||||
| Accumulated retained earnings (deficit) | 134 | ||||
| Accumulated other comprehensive income (loss) | (23) | ||||
Stockholders’ Equity | 2,457 | ||||
Total Liabilities and Stockholders’ Equity | $ | 2,457 | |||
__________________
(a)As of December 31, 2023 (Successor): 350,000,000 shares authorized; 59,028,843 shares issued and outstanding.
The accompanying Notes to the Condensed Unconsolidated Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION
SCHEDULE I - NOTES TO CONDENSED UNCONSOLIDATED FINANCIAL STATEMENTS
1.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”). Certain of TES’s debt agreements include covenants that restrict the payment of dividends or other distributions to TEC, restricting in excess of 25% of TEC’s consolidated net assets. Accordingly, these condensed unconsolidated financial statements and related footnotes have been prepared in accordance with Sections 5-04 and 12-04 of Regulation S-X. These statements should be read in conjunction with the Annual Financial Statements of TEC and notes thereto (the “Annual Financial Statements”).
In May 2023, TEC and the majority of its subsidiaries emerged from bankruptcy (the “Restructuring”) and adopted fresh start accounting. Unconsolidated financial results are presented for TEC for the Successor period from May 18 through December 31, 2023. Because results presented in the Annual Financial Statements for Predecessor periods (prior to May 18, 2023) represent the operating results TES, such results are not repeated here. See Notes 2 and 3 in Notes to the Annual Financial Statements for additional information regarding the Restructuring and related accounting.
TEC held no cash nor had any cash activity during the period from May 18 through December 31, 2023; therefore, a statement of cash flows has not been included.
2.TES Indebtedness
For a general description of the material terms of TES’s indebtedness, see Note 13 in Notes to the Annual Financial Statements.
TEC is a holding company that does not (and does not intend to) conduct any business operations or incur material obligations of its own. The Indenture and Credit Facilities restrict the ability of TES to pay dividends or make other distributions to TEC, subject to certain exceptions. Notable exceptions include the ability to pay dividends or make 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 2.25 to 1.0 (or, after the date the second quarter 2024 financials are due under the Credit Agreement, 2.75 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.
TEC does not have any separate indebtedness, other long-term obligations, or mandatory dividend or redemption requirements of redeemable stocks.
As of December 31, 2023, no cash dividends have been paid to TEC in the last three fiscal years by any other entity.
3.Commitments and Contingencies
See Note 12 in Notes to the Annual Financial Statements for commitments and contingencies of TEC.
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GLOSSARY OF TERMS AND ABBREVIATIONS
When used in this prospectus, the following capitalized terms have the meanings set forth below:
“2023 Equity Plan” means the 2023 Equity Incentive Plan of Talen Energy Corporation, effective as of May 17, 2023.
“Adjusted EBITDA” means 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; (xi) income taxes; (xii) legal settlements, liquidated damages and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interest; and (xv) other adjustments. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital credit facility and associated cash flow sweep.
“Adjusted Equity Value” means amount per share of TEC common stock equal to the sum of: (i) (a) if the measurement date is a “change in control event,” the implied per share value achieved in connection with such change in control event or, (b) if the measurement date is not a “change in control event,” the per share value (x) if the Company is listed on a national securities exchange, based on the 120-day volume-weighted average price or, (y) if the Company is not listed on a national securities exchange, as determined by the Company in good faith, plus; (ii) the aggregate per share value of any distributions or dividends paid with respect to shares between Emergence and the measurement date, or approved for distribution within the next quarter but not yet paid.
“Annual Financial Statements” means the audited Consolidated Balance Sheets of TEC as of December 31, 2023 (Successor) and TES as of December 31, 2022 (Predecessor); the related audited consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the period from May 18, 2023 through December 31, 2023 (Successor), and for the period from January 1, 2023 through May 17, 2023 and the years ended 2022 and 2021 (Predecessor), and the related notes.
“AOCI” means accumulated other comprehensive income or loss, which is a component of stockholder’s equity on the Consolidated Balance Sheets.
“ARO” means asset retirement obligation.
“AWS” means Amazon Web Services, Inc. and its affiliates.
“Backstop Commitment Letter” means the Backstop Commitment Letter, dated as of May 31, 2022, by and among the Debtors and the Backstop Parties, as subsequently amended, supplemented or otherwise modified.
“Backstop Parties” means those certain holders of claims under the Prepetition Unsecured Notes and PEDFA 2009A Bonds party to the Backstop Commitment Letter.
“Backstop Premium” means a premium, comprised of (i) a periodic premium, paid monthly by the Debtors to each Backstop Party at a rate equal to 10% per annum of each Backstop Party’s portion of the aggregate backstop commitment under the Backstop Commitment Letter and (ii) an additional premium, payable by the Debtors in cash or equity upon consummation of the Plan of Reorganization, equal to 20% of each Backstop Party’s portion of the aggregate backstop commitment under the Backstop Commitment Letter, reduced by the amount of monthly Backstop Premium previously paid.
“Bankruptcy Code” means Title 11 of the United States Code, 11 U.S.C. §§ 101–1532, as amended.
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas, Houston Division.
“Barney Davis” means a generation facility in Corpus Christi, Texas, owned and operated by Talen prior to the ERCOT Sale.
“Bilateral LC Agreement” means the Letter of Credit Facility Agreement, dated as of May 17, 2023, by and among TES, as borrower, Barclays Bank PLC, as administrative agent and LC issuer, and Citibank, N.A., as collateral agent, which governs the Bilateral LCF, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time.
“Bilateral LCF” means the senior secured bilateral letter of credit facility in an aggregate committed amount of $75 million under the Bilateral LC Agreement, which is available for the issuance of standby LCs. Obligations under the Bilateral LCF are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
“Board of Directors” means the board of directors of Talen Energy Corporation.
“Brandon Shores” means a Talen-owned and operated generation facility in Curtis Bay, Maryland.
“Brunner Island” means a Talen-owned and operated generation facility in York Haven, Pennsylvania.
“Camden” means a Talen-owned and operated generation facility in Camden, New Jersey.
“Capacity Factor” means the ratio of actual electrical energy output of one or more generating units over a given period of time to the theoretical maximum electrical energy output of the same unit or units over that period.
“Capacity Performance” the sole class of capacity product that electricity providers within PJM can offer to satisfy PJM’s capacity obligation and thereby receive capacity payments from PJM. Auctions for this opportunity, generally referred to as capacity auctions, are scheduled by PJM periodically, up to three years in advance of the applicable PJM Capacity Year and in accordance with the terms of PJM’s Tariff and FERC’s orders. Capacity Performance providers assume higher performance requirements during system emergencies and are subject to penalties for non-performance.
“CCR” means Coal Combustion Residuals, including but not limited to fly ash, bottom ash and gypsum, that are produced from coal-fired electric generation facilities.
“CIFP” means Critical Issue Fast Path.
“Code” means the Internal Revenue Code of 1986, as amended.
“Colstrip” means a generation facility comprised of four coal-fired generation units located in Colstrip, Montana (collectively, the “Colstrip Units”). Talen Montana operates the Colstrip Units, owns an undivided interest in Colstrip Unit 3, and has an economic interest in Colstrip Unit 4. Colstrip Units 1 and 2 were permanently retired in January 2020. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in the Colstrip Units.
“Colstrip AOC” means the “Administrative Order on Consent” entered into in 2012 (with minor amendments in 2017) between Talen Montana (on behalf of the co-owners of the Colstrip Units and in its capacity as the operator of Colstrip) and the MDEQ.
“Conemaugh” means a generation facility located in New Florence, Pennsylvania, in which Talen Generation, through a direct subsidiary, owns a 22.22% undivided interest. Conemaugh is operated by an unaffiliated party. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities.
“Conemaugh Fuels” means Conemaugh Fuels, LLC, an entity in which Talen Generation owns a 22.22% equity interest, which engages in the purchase of coal, the subsequent sale of coal to Conemaugh and other fuel-related activities.
“Credit Agreement” means the Credit Agreement, dated as of May 17, 2023, by and among TES, as borrower, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and the joint lead arrangers and joint bookrunners parties thereto, which governs the RCF, the Term Loans and the
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TLC LCF, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time.
“Credit Facilities” means, collectively, the RCF, the Term Loans, the TLC LCF and the Bilateral LCF.
“Cumulus Affiliates” means, collectively, Cumulus Growth Holdings, Cumulus Digital Holdings and their respective subsidiaries.
“Cumulus Coin” means Cumulus Coin LLC, a direct subsidiary of Cumulus Coin Holdings that owns a 75% equity interest in Nautilus as of March 31, 2024.
“Cumulus Coin Holdings” means Cumulus Coin Holdings LLC, a direct subsidiary of Cumulus Digital that, through its direct subsidiary, Cumulus Coin, owns an equity interest in Nautilus. Talen Energy Supply and Talen Growth previously held voting, convertible preferred equity interests in this entity. In September 2022, in connection with the Cumulus Digital Equity Conversion, the preferred equity interests in this entity were converted to common equity interests in Cumulus Digital Holdings.
“Cumulus Data” means Cumulus Data LLC, formerly Susquehanna Data LLC, a direct subsidiary of Cumulus Data Holdings that, prior to the Cumulus Data Campus Sale, was developing the Cumulus Data Campus.
“Cumulus Data Campus Sale” or “Data Center Campus Sale” means the Company’s sale, on March 1, 2024, of certain assets of Cumulus Data, which included all of the land, power infrastructure, powered shell and intangibles of Cumulus Data Campus, to AWS for gross proceeds of $650 million, $300 million of which is to be released from escrow upon achievement of certain development milestones.
“Cumulus Data Holdings” means Cumulus Data Holdings LLC, a direct subsidiary of Cumulus Digital and the direct parent of Cumulus Data. Talen Energy Supply and Talen Growth previously held voting, convertible preferred equity interests in this entity. In September 2022, in connection with the Cumulus Digital Equity Conversion, the preferred equity interests in this entity were converted to common equity interests in Cumulus Digital Holdings.
“Cumulus Digital” means Cumulus Digital LLC, a direct subsidiary of Cumulus Digital Holdings and the direct parent of Cumulus Data Holdings and Cumulus Coin Holdings.
“Cumulus Digital Equity Conversion” means the conversion of preferred equity in Cumulus Coin Holdings and Cumulus Data Holdings held by TES, Talen Growth and Riverstone V Coin Holdings L.P., and the conversion of class B units of Cumulus Digital Holdings held by Orion affiliates, in each case into common equity of Cumulus Digital Holdings, as contemplated by the Cumulus Term Sheet, dated as of August 29, 2022, by and among TES, TEC, Cumulus Digital Holdings, Orion, Riverstone and certain of their respective affiliates, which was an attachment to the fifth amendment to the RSA.
“Cumulus Digital Holdings” means Cumulus Digital Holdings LLC, a subsidiary of TES and the direct parent of Cumulus Digital. Prior to September 2022, Cumulus Digital Holdings was a subsidiary of Cumulus Growth. As a result of the Cumulus Digital Equity Conversion, TES obtained a controlling financial interest in Cumulus Digital Holdings. Accordingly, TES consolidates this entity and its subsidiaries in accordance with accounting rules. As of March 28, 2024, TES owns 100% of the common equity of Cumulus Digital Holdings.
“Cumulus Digital TLF” means the Cumulus Digital term loan facility, due September 2027, under that certain Credit Agreement, dated as of September 20, 2021, by and among Cumulus Digital and its subsidiaries, Cumulus Digital Holdings and affiliates of Orion, as the same was amended, amended and restated, supplemented or otherwise modified from time-to-time, under which Cumulus Digital borrowed $175 million to support Cumulus Coin’s required contributions to Nautilus, as well as Cumulus Data’s construction of certain shared infrastructure supporting both Nautilus and the Cumulus Data Center Campus. The Cumulus Digital TLF was paid in full on March 1, 2024.
“Cumulus Growth Holdings” means Cumulus Growth Holdings LLC, a direct subsidiary of TES that owns interests in real estate and renewable development projects.
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“Cumulus Term Sheet” means Term Sheet, dated as of August 29, 2022, by and among, TES, TEC, Cumulus Digital Holdings, Orion, Riverstone and certain of their respective affiliates.
“Dartmouth” means a Talen-owned and operated generation facility in Dartmouth, Massachusetts.
“Debtors” means, (a) prior to December 12, 2022, Talen Energy Supply and all of its direct and indirect subsidiaries, other than: (i) LMBE-MC Holdco and its subsidiaries, (ii) TRF and (iii) the Cumulus Affiliates and (b) from and after December 12, 2022, the foregoing Debtors together with TEC. See Note 3 in Notes to the Annual Financial Statements for additional information.
“DIP Facilities” means, collectively, the DIP RCF, DIP TLB and DIP LCF.
“DIP LCF” means the letter of credit facility established under the Debtors’ Superpriority Secured Debtor-In-Possession Letter of Credit Facility Agreement, dated as of May 11, 2022, which provided for LCs outstanding under the Prepetition RCF as of commencement of the Restructuring to remain outstanding with superpriority status.
“DIP RCF” means the revolving credit facility that provided aggregate revolving commitments of $300 million, including a letter of credit sub-facility of up to $75 million, under the Debtors’ Superpriority Secured Debtor-In-Possession Credit Agreement, dated as of May 11, 2022.
“DIP Secured ISDAs” means certain bilateral secured International Swaps and Derivatives Association (“ISDA”) agreements and Base Contracts for Sale and Purchase of Natural Gas as published by the North American Energy Standards Board (“NAESB”) of Talen Energy Marketing, the obligations under which were secured by a superpriority lien and security interest in substantially all of the assets of Talen Energy Supply and the Debtors.
“DIP TLB” means the term loan B facility in an aggregate principal amount of $1 billion under the Debtors’ Superpriority Secured Debtor-In-Possession Credit Agreement, dated as of May 11, 2022.
“EGU” means Electric Generating Unit.
“EIS” means the Environmental Impact Statement related to mining permits.
“Emergence” means May 17, 2023, the date that the Plan of Reorganization became effective in accordance with the terms thereof and the Debtors emerged from the Restructuring.
“EPA” means the U.S. Environmental Protection Agency.
“EPA 2015 Ozone Standard” means the EPA’s 2015 revision to the 8-hour ozone EPA NAAQS for ground-level ozone to 70 parts per billion, based on extensive scientific evidence about ozone’s effects on public health and welfare.
“EPA CCR Rule” means the national regulatory standards required by the EPA for the management of CCRs in landfills and surface impoundments.
“EPA CSAPR” means the Cross-State Air Pollution Rule. Requires 28 states in the eastern half of the U.S. to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. A cap-and-trade system is used to reduce the target pollutants—sulfur dioxide and nitrogen oxides.
“EPA ELG Rule” means the effluent limitation guidelines, which are national regulatory standards required by the EPA for wastewater discharged from specific industrial categories, including but not limited to coal-fired electric generation facilities, to surface waters and municipal sewage treatment plants.
“EPA MATS Rule” means the Mercury and Air Toxics Standards, EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 megawatts.
“EPA NAAQS” means the National Ambient Air Quality Standards, which define the maximum amount of a pollutant averaged over a specified period of time that can be present in outdoor air without harming public health.
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“EPA NESHAP” means the National Emissions Standards for Hazardous Air Pollutants, an EPA standard that is applicable to the emissions of hazardous air pollutants produced by corporations, institutions and government agencies.
“EPA RTR” means the EPA’s Risk and Technology Review of the EPA NESHAP, which is a combined effort to evaluate both risk and technology as required by the Clean Air Act after the application of maximum achievable control technology standards.
“EPS” means earnings per share.
“ERCOT” means the Electric Reliability Council of Texas, operator of the electricity transmission network and electricity energy market in most of Texas, which is responsible for, among other things, scheduling electric deliveries and performing financial settlements for the competitive wholesale bulk-power market.
“ERCOT Sale” means the sale of our ERCOT fleet to CPS Energy in May 2024.
��ESG” means environmental, social and corporate governance.
“Exchange Act” means the Securities Exchange Act of 1934, as amended.
“Exit Financings” means TES’s issuance of the Secured Notes and entry into the Credit Facilities in connection with Emergence.
“Federal Quiet Title Act” means the federal statute that provides for legal proceedings to determine ownership of real property.
“FERC” means the U.S. Federal Energy Regulatory Commission. FERC regulates interstate transmission and wholesale sales of electricity, interstate transportation of natural gas and oil, hydropower projects and natural gas terminals.
“GAAP” means Generally Accepted Accounting Principles in the United States.
“GW” means Gigawatt, one million kilowatts of electric power.
“GWh” means Gigawatts of electric power per hour.
“H.A. Wagner” means a Talen-owned and operated generation facility in Curtis Bay, Maryland.
“IBEW” means International Brotherhood of Electrical Workers, a labor union.
“Indenture” means the Indenture, dated as of May 12, 2023, as supplemented by the First Supplemental Indenture, dated as of May 17, 2023, as further supplemented by the Second Supplemental Indenture, dated as of October 6, 2023, each between TES, the Subsidiary Guarantors and Wilmington Savings Fund Society, FSB, as trustee, which governs the Secured Notes, as the same may be further amended, amended and restated, supplemented or otherwise modified from time-to-time.
“Inflation Reduction Act” means the Inflation Reduction Act of 2022, which was signed into law in August 2022. Among the Inflation Reduction Act’s provisions are: (i) amendments to the Code to create a nuclear production tax credit program; (ii) the creation, extension and modification of tax credit programs for certain clean energy projects, such as solar, wind and battery storage; and (iii) adjustments to corporate tax rates.
“Interim Financial Statements” means the unaudited condensed consolidated balance sheet of TEC as of March 31, 2024 the related condensed consolidated statements of operations, statements of comprehensive income (loss), statements of cash flows, and statements of equity for the three months ended March 31, 2024 (Successor) and 2023 (Predecessor), and the related notes.
“ISO” means Independent System Operator.
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“Keystone” means a generation facility located in Shelocta, Pennsylvania, in which Talen Generation, through a direct subsidiary, owns a 12.34% undivided interest. Keystone is operated by an unaffiliated party. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities.
“Keystone Fuels” means Keystone Fuels, LLC, an entity in which Talen Generation owns a 12.34% equity interest, which engages in the purchase of coal, the subsequent sale of coal to Keystone and other fuel-related activities.
“KWh” means kilowatts of electric power per hour.
“Laredo” means a generation facility in Laredo, Texas, owned and operated by Talen prior to the ERCOT Sale.
“LC” means letter of credit.
“LMBE-MC” means LMBE-MC HoldCo II LLC, a former direct subsidiary of LMBE-MC Holdco that, through its subsidiaries, owned generation facility operations in Pennsylvania and was the borrower under the LMBE-MC TLB and LMBE-MC RCF. Following termination of the LMBE-MC Credit Agreement, LMBE-MC was dissolved and its generation subsidiaries were distributed to Talen Generation.
“LMBE-MC Credit Agreement” means the Credit and Guaranty Agreement, dated as of December 3, 2018, among LMBE-MC, as borrower, LMBE-MC Holdco, as holdings, the guarantors named therein, MUFG Union Bank, N.A., as initial issuing bank and MUFG Bank, LTD, as administrative agent, which governs the LMBE-MC RCF and the LMBE-MC TLB, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time. The LMBE-MC Credit Agreement was terminated in August 2023.
“LMBE-MC Holdco” means LMBE-MC HoldCo I LLC, a former direct subsidiary of Talen Generation and the parent of LMBE-MC that, through its subsidiaries, owned generation facility operations in Pennsylvania. Following termination of the LMBE-MC Credit Agreement, LMBE-MC Holdco was dissolved and its generation subsidiaries were distributed to Talen Generation.
“LMBE-MC RCF” means the revolving credit facility, including a letter of credit sub-facility, maturing in December 2023, established under the LMBE-MC Credit Agreement. Obligations under the LMBE-MC RCF were guaranteed by LMBE-MC Holdco and its subsidiaries and secured by a first priority lien and security interest in substantially all of their assets. The LMBE-MC RCF was terminated in August 2023. See Note 13 in Notes to the Annual Financial Statements for additional information.
“LMBE-MC TLB” means the term loan B facility, due December 2025, established under the LMBE-MC Credit and Guaranty Agreement. Obligations under the LMBE-MC TLB were guaranteed by LMBE-MC Holdco and its subsidiaries and secured by a first priority lien and security interest in substantially all of their assets. The LMBE-MC TLB was repaid in full and terminated in August 2023. See Note 13 in Notes to the Annual Financial Statements for additional information.
“Lower Mt. Bethel” means a Talen-owned and operated generation facility in Bangor, Pennsylvania.
“Martins Creek” means a Talen-owned and operated generation facility in Bangor, Pennsylvania.
“MBER” means Montana Board of Environmental Review, a state-level government agency responsible for administering environmental regulatory, clean up, monitoring, pollution prevention and energy conservation laws.
“MDEQ” means Montana Department of Environmental Quality, which is responsible for regulating air, water and ground resources to administer Montana’s environmental and mine reclamation laws.
“MEIC” means Montana Environmental Information Center, a non-partisan, non-profit environmental advocacy group.
“MMBtu” means one million British Thermal Units.
“Montour” means a Talen-owned and operated generation facility in Washingtonville, Pennsylvania.
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“MW” means megawatt, one thousand kilowatts (one million watts) of electric power.
“MWh” means megawatt hour, or megawatts of electric power per hour.
“Nautilus” means Nautilus Cryptomine LLC, a joint venture owned, as of March 31, 2024, 75% by Cumulus Coin and 25% by TeraWulf, which owns and operates a cryptomining project on land at the Cumulus Data Campus.
“NAV” means net asset value.
“NCI” means non-controlling interest.
“NDT” means the nuclear facility decommissioning trust for Susquehanna.
“NEIL” means Nuclear Electric Insurance Limited.
“NEPA” means National Environmental Policy Act, which requires federal agencies to assess the environmental effects of their proposed actions prior to making decisions. The range of actions covered by NEPA is broad and includes making decisions on permit applications, adopting federal land management actions and constructing highways and other publicly-owned facilities.
“NERC” means the North American Electric Reliability Corporation, a not-for-profit international regulatory authority whose mission is to assure the effective and efficient reduction of risks to the reliability and security of the grid.
“NOL” means net operating loss.
“NorthWestern” means NorthWestern Corporation d/b/a NorthWestern Energy, a co-owner in Colstrip.
“NRC” means the U.S. Nuclear Regulatory Commission, which was created as an independent agency by Congress in 1974 to ensure the safe use of radioactive materials for beneficial civilian purposes while protecting people and the environment. The NRC regulates commercial nuclear power plants and other uses of nuclear materials, such as in nuclear medicine, through licensing, inspection and enforcement of its requirements.
“Nuclear PTC” means the nuclear production tax credit under the Inflation Reduction Act.
“Nueces Bay” means a generation facility in Corpus Christi, Texas, owned and operated by Talen prior to the ERCOT Sale.
“OCI” means other comprehensive income or loss.
“Operating Reserve Demand Curve” means ERCOT’s Operating Reserve Demand Curve, which is a market mechanism that values operating reserves in the wholesale electric market based on the scarcity of those reserves and reflects that value in energy prices.
“Orion” means Orion Energy Partners, whose affiliates were third-party lenders under in the Cumulus Digital TLF.
“OSM” means the U.S. Office of Surface Mining Reclamation and Enforcement.
“Ozone Season” means a period of time in which ground-level ozone reaches its highest concentrations in the air.
“Ozone Transport Commission” means a multi-state organization created under the Clean Air Act responsible for advising the EPA and implementing regional solutions to ground-level ozone issues.
“PA DEP” means the Pennsylvania Department of Environmental Protection, the agency in the state of Pennsylvania responsible for protecting and preserving the land, air, water and public health through enforcement of the state’s environmental laws.
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“Pattern Energy” means Pattern Renewables 2 LP, an unaffiliated third party in which Riverstone holds a minority interest.
“PEDFA Bonds” means the following series of Pennsylvania Economic Development Financing Authority (“PEDFA”) Exempt Facilities Revenue Refunding Bonds: Series 2009A due December 2038 (“PEDFA 2009A Bonds”); Series 2009B due December 2038 (“PEDFA 2009B Bonds”); and Series 2009C due December 2037 (“PEDFA 2009C Bonds”). All series of the PEDFA Bonds were guaranteed by certain of the Prepetition Guarantors. Holders of the PEDFA 2009A Bonds received TEC common stock in connection with the Restructuring in satisfaction of their claims. The PEDFA 2009B Bonds and PEDFA 2009C Bonds currently remain outstanding and are guaranteed by certain of the Subsidiary Guarantors.
“Petition Date” means, with respect to a Debtor, the date on which such Debtor commenced its Restructuring, either May 9, 2022 or May 10, 2022.
“PIK” means paid-in-kind.
“PJM” means PJM Interconnection, L.L.C., the RTO that operates the electricity transmission network and wholesale power market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
“PJM ACR” means PJM’s “Avoidable Cost Rate” defined under the PJM Open Access Transmission Tariff, if the formula that serves as the PJM MSOC.
“PJM Base Residual Auction” means a component of the PJM RPM, the PJM Base Residual Auction, is intended to secure power supply resources from market participants in advance of the PJM Capacity Year. It is usually held during the month of May three years prior to the start of the PJM Capacity Year.
“PJM Capacity Year” means the PJM capacity revenues delivery years cover the period from June 1 to May 31.
“PJM IMM” means the Independent Market Monitor for PJM, who is intended to operate independently from PJM staff and members to objectively monitor, investigate, evaluate and report on PJM’s markets and is responsible for guarding against the exercise of market power.
“PJM MOPR” means the Minimum Offer Price Rule, which limits the minimum price at which certain units can bid into the auction due to certain external subsidization.
“PJM MSOC” means the PJM Market Seller Offer Cap, which is the price ceiling applied by PJM to certain capacity sell offers and is based on the PJM ACR.
“PJM RPM” means PJM’s capacity market, or the Reliable Pricing Model, formed under PJM’s Open Access Transmission Tariff, which is intended to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted energy demand in the future. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.
“Plan of Reorganization” means the Joint Chapter 11 Plan of Reorganization of Talen Energy Supply, LLC and Its Affiliated Debtors [Docket No. 1206], as subsequently amended, supplemented or otherwise modified, and any exhibits or schedules thereto.
“PP&E” means property, plant and equipment.
“PPL” means PPL Corporation, the former indirect parent holding company of Talen Energy Supply and Talen Energy Corporation until 2015.
“Predecessor” relates to the financial position or results of operations of Talen Energy Supply for periods prior to Emergence, or May 17, 2023.
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“Prepetition CAF” means the Credit Agreement, dated as of December 14, 2021, as subsequently amended, supplemented or otherwise modified, among Talen Energy Supply, as parent, Talen Energy Marketing and Susquehanna, as borrowers, the lenders party thereto, and Alter Domus (US) LLC, as administrative agent, which established a senior secured commodity accordion revolving credit facility. Obligations under the Prepetition CAF were guaranteed by the Prepetition Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors.
“Prepetition Deferred Capacity Obligations” means the prepetition obligations arising under an auction specific MW transaction confirmation, executed in March 2021, between Talen and an unaffiliated third party, which involved the transfer by a Talen subsidiary to the third party of capacity rights and revenues associated with physical MW of capacity cleared under the PJM capacity auctions for planning years 2020/2021 and 2021/2022. These obligations had been fully performed as of June 2022.
“Prepetition Guarantors” means certain wholly owned subsidiaries of Talen Energy Supply that guaranteed obligations under the Prepetition Indebtedness and the Prepetition Secured ISDAs.
“Prepetition Indebtedness” means, collectively, the Prepetition RCF, Prepetition TLB, Prepetition CAF, Prepetition Secured Notes, Prepetition Unsecured Notes and PEDFA Bonds.
“Prepetition Inventory Repurchase Obligations” means the prepetition obligations arising under a product purchase and sale agreement, executed in December 2019, pursuant to which certain Prepetition Guarantors sold coal and fuel oil to an unaffiliated third party and then repurchased that fuel on a periodic basis for generation purposes, The remaining fuel was repurchased in May 2022 in connection with the termination of the arrangement. See Note 8 in Notes to the Annual Financial Statements for additional information.
“Prepetition LCFs” means, collectively, TES’s prepetition unsecured, bilateral LC facilities (i) with Credit Suisse International, which expired in June 2023; and (ii) with Goldman Sachs Bank USA, which was terminated in May 2023. Obligations under the Prepetition LCFs were guaranteed by the Prepetition Guarantors.
“Prepetition RCF” means the Credit Agreement dated as of June 1, 2015, as subsequently amended, supplemented or otherwise modified, among Talen Energy Supply, as borrower, Citibank, N.A., as administrative agent and collateral trustee, and the lenders party thereto, which established a senior secured revolving credit facility, including an LC sub-facility, which was subsequently amended to an LC-only facility. Obligations under the Prepetition RCF were guaranteed by the Prepetition Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors.
“Prepetition Secured Indebtedness” means, collectively, the Prepetition RCF, Prepetition TLB, Prepetition CAF and Prepetition Secured Notes.
“Prepetition Secured ISDAs” means certain prepetition bilateral secured ISDA and NAESB agreements of Talen Energy Marketing. Obligations under the Prepetition Secured ISDAs were secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors.
“Prepetition Secured Notes” means the following series of prepetition senior secured notes issued by Talen Energy Supply, which were guaranteed by the Prepetition Guarantors and secured by a first priority lien on and security interest in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors: (i) 7.25% Senior Secured Notes due 2027; (ii) 6.625% Senior Secured Notes due 2028; and (iii) 7.625% Senior Secured Notes due 2028.
“Prepetition TLB” means the Term Loan Credit Agreement, dated as of July 8, 2019, as subsequently amended, supplemented or otherwise modified, among Talen Energy Supply, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, which established a senior secured term loan B facility. Obligations under the Prepetition TLB were guaranteed by the Prepetition Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors.
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“Prepetition Unsecured Notes” means the following series of prepetition senior unsecured notes issued by Talen Energy Supply, which were guaranteed by certain Prepetition Guarantors: (i) 4.6% Senior Notes due December 2021; (ii) 9.5% Senior Notes due July 2022; (iii) 6.5% Senior Notes due September 2024; (iv) 6.5% Senior Notes due June 2025; (v) 10.5% Senior Notes due January 2026; (vi) 7.0% Senior Notes due October 2027; and (vii) 6.0% Senior Notes due December 2036.
“Price-Anderson Act” means a federal law governing liability related issues and ensuring the availability of funds for public liability claims arising from an incident at any United States licensed nuclear facility.
“PUCT” means the Public Utility Commission of Texas, which regulates the Texas electric, telecommunication and water and sewer utilities, implements respective legislation and offers customer assistance in resolving consumer complaints.
“PUCT PCM” means the Performance Credit Mechanism, a market mechanism adopted by the PUCT in 2023.
“Puget Sound” means Puget Sound Energy Inc., an energy utility company based in the U.S. state of Washington that provides electrical power and natural gas to the Puget Sound region.
“RACT” means Reasonably Available Control Technology, a pollution control standard.
“RCF” means the senior secured revolving credit facility that provides aggregate revolving commitments of $700 million, including letter of credit commitments of $475 million, under the Credit Agreement. Obligations under the RCF are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
“Reg Rights Holders” means certain designated holders of TEC common stock and warrants to purchase TEC common stock that are party to the Registration Rights Agreement, and other holders of our common stock and warrants from time to time party thereto.
“Registration Rights Agreement” means the Registration Rights Agreement dated as of May 17, 2023 between TEC and the Reg Rights Holders that, among other things, granted customary registration rights to the Reg Rights Holders and certain of their permitted transferees, including customary shelf registration rights and piggyback rights.
“Reliability Must Run” refers to a generating unit that is slated to be retired by its owners but is needed to be available for reasons of reliability. It is typically requested to remain operational beyond its proposed retirement date until transmission upgrades are completed. These arrangements have been used to keep certain power plants operating past their planned retirement dates in order to prevent reliability problems.
“Restructuring” means the voluntary cases commenced by the Debtors under Chapter 11 of the Bankruptcy Code in the Bankruptcy Court, together with the related financial restructuring of the Debtors’ existing debt, existing equity interests and certain other obligations pursuant to the Plan of Reorganization.
“Retail PPA Incentive Equity” means the right of Riverstone, pursuant to the Plan of Reorganization and TEC Global Settlement, to receive additional TEC common stock at and after Emergence based on the prices to be paid by Cumulus Data to Talen Generation for electricity generated at Susquehanna under retail electricity supply agreements. At Emergence, TEC issued approximately 243,000 shares of TEC common stock to Riverstone in respect of the Retail PPA Incentive Equity. In addition, the Retail PPA Incentive Equity also included a right of Riverstone to receive additional TEC common stock (or, at TEC’s option, a cash payment) in the event Cumulus Data exercised an additional option to purchase power from Talen Generation. In September 2023, Riverstone waived its right to these additional amounts in exchange for a cash payment. See Note 16 in Notes to the Annual Financial Statements for additional information.
“RGGI” means the Regional Greenhouse Gas Initiative, a mandatory market-based program among certain states, including Maryland, New Jersey and Massachusetts, to cap and reduce carbon dioxide emissions from the power sector. RGGI requires certain electric power generators to hold allowances equal to their carbon dioxide emissions over a three-year control period. RGGI allowances, as issued by each participating state, represent an
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authorization for a power generation facility to emit one short ton of carbon dioxide. Allowances may be acquired by auction or through secondary markets. Pennsylvania has proposed joining this market-based program.
“Rights Offering” means the equity rights offering conducted in April and May 2023 in accordance with the RSA, resulting in subscriptions to purchase $1.4 billion of TEC common stock pursuant to the Plan of Reorganization.
“Riverstone” means Riverstone Holdings LLC and certain of its affiliates.
“Rosebud Mine” means a coal mine in Montana owned by Westmoreland Rosebud Mining, LLC that supplies coal to the Colstrip Units.
“RSA” means the Restructuring Support Agreement (and all exhibits and schedules thereto), dated as of May 9, 2022, by and between the Debtors, certain holders of claims under the Prepetition Unsecured Notes, Prepetition CAF, Prepetition TLB and Prepetition Secured Notes, Riverstone and TEC, as subsequently amended, supplemented or otherwise modified, and any exhibits or schedules thereto.
“RTO” means Regional Transmission Organization.
“Secured ISDAs” means certain bilateral secured ISDA and NAESB agreements of Talen Energy Marketing. Obligations under the Secured ISDAs are secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
“Secured Notes” means the 8.625% Senior Secured Notes due 2030 issued by Talen Energy Supply. Obligations under the Secured Notes are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
“Securities Act” means the Securities Act of 1933, as amended.
“SNF” means spent nuclear fuel.
“SOFR” means Secured Overnight Financing Rate.
“Spark Spread” means the measure of margin representing the difference between power price received and the cost of natural gas to produce that power.
“Stockholders Agreement” means the Stockholders Agreement, dated as of May 17, 2023, between TEC and the holders of TEC common stock at Emergence.
“Subsidiary Guarantors” means the subsidiaries of TES that guarantee (i) the obligations of TES under the Credit Facilities and the Secured Notes and (ii) the obligations of Talen Energy Marketing under the Secured ISDAs.
“Successor” relates to the financial position or results of operations of Talen Energy Corporation for periods after Emergence, or May 18, 2023.
“Susquehanna” means a nuclear-powered generation facility located near Berwick, Pennsylvania.
“Susquehanna Nuclear” means Susquehanna Nuclear, LLC, a direct subsidiary of Talen Energy Supply. Susquehanna Nuclear operates and owns a 90% undivided interest in Susquehanna.
“Talen,” the “Company,” “we,” “us,” or “our” means (i) for periods after May 17, 2023, Talen Energy Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise and (ii) for periods on or before May 17, 2023, Talen Energy Supply and its consolidated subsidiaries, unless the context clearly indicates otherwise.
“Talen Energy Corporation” or “TEC” means Talen Energy Corporation, the parent company of Talen Energy Supply, and its consolidated subsidiaries.
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“Talen Energy Marketing” means Talen Energy Marketing, LLC, a direct subsidiary of Talen Energy Supply that provides energy management services to Talen-owned and operated generation facilities and engages in wholesale commodity marketing activities.
“Talen Energy Supply” or “TES” means Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation that, thorough subsidiaries, indirectly holds all of Talen’s assets and operations.
“Talen Generation” means Talen Generation, LLC, a direct subsidiary of Talen Energy Supply that, through its subsidiaries, owns and operates generation facilities, and holds interests in other jointly owned, third-party operated generation facilities, in Pennsylvania, New Jersey and Maryland.
“Talen Montana” means Talen Montana, LLC, a direct subsidiary of Talen Montana Holdings, LLC that operates the Colstrip Units and owns an undivided interest in Colstrip Unit 3 and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
“TEC Global Settlement” means the settlement of all claims, interests and controversies among the Debtors, Riverstone, TEC and certain other creditors in the Restructuring, the terms of which are set out in the fifth amendment to the RSA and the attachments thereto.
“TeraWulf” means TeraWulf Inc. and its affiliates.
“Term Loans” means, collectively, the TLB and the TLC.
“TERP” means the Talen Energy Retirement Plan, which is Talen’s principal defined-benefit pension plan.
“TLB” means the senior secured term loan B facility in an aggregate principal amount of $580 million (and subsequently increased to $870 million in August 2023) under the Credit Agreement. Obligations under the TLB are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
“TLC” means the senior secured term loan C facility in an aggregate principal amount of $470 million under the Credit Agreement, the proceeds of which are available to support the issuance of standby and trade LCs under the TLC LCF via 100% cash collateralization. Obligations under the TLC are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
“TLC LCF” means the $470 term letter of credit facility established under the Credit Agreement. The TLC LCF is cash collateralized with the proceeds of the TLC, and commitments thereunder are reduced to the extent that borrowings under the TLC are prepaid.
“TRF” means Talen Receivables Funding, LLC, a direct subsidiary of Talen Energy Marketing that, prior to the Restructuring, purchased certain receivables from Talen Energy Marketing and sold them to an unaffiliated financial institution. That agreement was terminated during the second quarter 2022 as a result of the Restructuring. In November 2023, TRF was merged with and into Talen Energy Marketing.
“UMWA” means United Mine Workers of America.
“VEBA” means Voluntary Employee Benefit Association, a trust vehicle holding assets dedicated to payment of benefits under designated health and welfare plans (or successor plans) for future benefit payments to employees, retirees or their beneficiaries.
“VIE” means variable interest entity.
“WECC” means the Western Electricity Coordinating Council, a not-for-profit entity that ensures the reliability of the electricity transmission network and energy market in all or parts of Arizona, California, Idaho, Montana, Nevada, New Mexico, Oregon, South Dakota, Texas, Utah, Washington, the Canadian provinces of Alberta and British Columbia and the northern portion of the Mexican state of Baja California.
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“Winter Storm Elliott” means an extra-tropical cyclone that occurred in December 2022 that created a storm of snow, rain and wind across the country. The winter cyclone had widespread impacts across the United States and caused PJM to declare a Maximum Generation Emergency Action.
“Winter Storm Uri” means a major winter and ice storm that occurred in February 2021 that had widespread impacts across the United States, including systemic energy market disruptions and price volatility throughout ERCOT.
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PART II
INFORMATION NOT REQUIRED IN PROSPECTUS
Item 13. Other Expenses of Issuance and Distribution.
The following table indicates the expenses to be incurred in connection with this registration statement and the listing of our common stock, all of which will be paid by us. All amounts are estimated except the SEC registration fee.
| Amount | |||||
| SEC registration fee | $ | 648,724.45 | |||
| Printing fees and expenses | $ | 200,000.00 | |||
| Legal fees and expenses | $ | 3,500,000.00 | |||
| Accounting fees and expenses | $ | 750,000.00 | |||
| Other advisors’ fees | $ | 575,000.00 | |||
| Total | $ | 5,673,724.45 | |||
Item 14. Indemnification of Directors and Officers.
Section 145 of the DGCL authorizes a court to award, or a corporation’s board of directors to grant, indemnity to directors and officers in terms sufficiently broad to permit such indemnification under certain circumstances for liabilities, including reimbursement for expenses incurred, arising under the Securities Act. Our Charter permits indemnification of our directors and officers to the maximum extent permitted by the DGCL, and our Bylaws provide that we will indemnify our directors and officers and permit us to indemnify our employees and other agents, in each case to the maximum extent permitted by the DGCL.
We have entered into indemnification agreements with our directors and officers, whereby we have agreed to indemnify our directors and officers to the fullest extent permitted by law, including indemnification against expenses and liabilities incurred in legal proceedings to which the director or officer was, or is threatened to be made, a party by reason of the fact that such director or officer is or was a director or officer of ours, provided that such director or officer acted in good faith, in a manner that the director or officer reasonably believed to be in, or not opposed to, our best interest, and with respect to any criminal proceeding, had no reasonable cause to believe their conduct was unlawful.
The indemnification provisions in our Charter, Bylaws and the indemnification agreements that we have entered into, or will enter into, with our directors and executive officers may discourage stockholders from bringing a lawsuit against our directors and executive officers for breach of their fiduciary duties. They may also reduce the likelihood of derivative litigation against our directors and executive officers, even though an action, if successful, might benefit us and other stockholders. Further, a stockholder’s investment may be adversely affected to the extent that we pay the costs of settlement and damage awards against directors and executive officers as required by these indemnification provisions. At present, there is no pending litigation or proceeding involving a director or officer of ours regarding which indemnification is sought, nor is the registrant aware of any threatened litigation that may result in claims for indemnification.
We maintain insurance policies that indemnify our directors and officers against various liabilities arising under the Securities Act and the Exchange Act that might be incurred by any director or officer in his or her capacity as such.
Certain of our non-employee directors may, through their relationships with their employers, be insured and/or indemnified against certain liabilities incurred in their capacity as members of our Board of Directors.
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Item 15. Recent Sales of Unregistered Securities.
Common Stock
At Emergence, and in reliance on the exemption from registration provided in Section 1145 of the Bankruptcy Code, 4,757,642 shares of common stock were issued to the holders of claims under TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds in satisfaction of such claims.
At Emergence, Riverstone and Talen MidCo LLC and certain of their respective designees received 833,701 shares of common stock issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act in connection with the settlement of certain claims.
Backstopped Equity Rights Offering
In connection with Emergence, in April 2023, the Company commenced the Rights Offering. Pursuant to the Rights Offering, TEC offered holders of claims under TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds the right to purchase common stock of the reorganized, post-Emergence Company, for an aggregate purchase price of $1.4 billion. Such Rights Offering was backstopped by certain of the Consenting Noteholders that held claims under TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds.
Pursuant to the Rights Offering, (i) the Company issued 43,750,000 shares of common stock at a purchase price of $32.00 per share to participating holders for an aggregate purchase price of approximately $1.4 billion, of which (a) 690,813 shares of common stock were issued in reliance on the exemption from registration provided in Section 1145 of the Bankruptcy Code and (b) 43,059,187 shares of common stock were issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act and (ii) the Company issued 9,687,500 shares of common stock, comprising of shares issuable as part of the fee payable to the Backstop Parties, in reliance on the exemption from registration provided in Section 1145 of the Bankruptcy Code.
Warrants
At Emergence, certain affiliates of Riverstone received warrants to purchase up to 5.00%, or 3,106,781 shares, of common stock, with (i) a tenor of five years, (ii) a strike price of $52.92, subject to adjustment in certain circumstances, and (iii) Black-Scholes protection in the event of certain change of control transactions, the terms of which are set forth in the those certain Warrant Certificates No. 1-3, dated May 17, 2023, issued by TEC. The warrants were issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act in connection with the settlement of certain claims. In connection with the consummation of the Riverstone Buyout, such warrants were surrendered and cancelled in exchange for a $40 million cash payment by TES.
Pursuant to that certain Employment Agreement, dated December 12, 2022, by and between Talen Energy Supply, LLC and Leonard LoBiondo, at Emergence Mr. LoBiondo acquired warrants to purchase up to 457,142 shares common stock with a tenor of seven years and a strike price of at a strike price of $43.75, subject to adjustment in certain circumstances, the terms of which are set forth in the that certain Warrant Certificate No. L-1, dated May 17, 2023, issued by TEC. Such warrants were issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act.
Senior Notes
On May 12, 2023, TES issued $1.2 billion aggregate principal amount of the Secured Notes in reliance on the exemptions from registration provided by Section 4(a)(2) of the Securities Act and resold pursuant to Rule 144A and Regulation S under the Securities Act. The offering of the Secured Notes was part of the series Exit Financings undertaken in connection with the Restructuring and was used to fund the distributions provided for under the Plan of Reorganization, including the repayment of claims under certain of the Debtors’ pre-petition indebtedness, and to pay certain fees, commissions and expenses relating to the foregoing and Emergence and for general corporate purposes.
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Item 16. Exhibits and Financial Statement Schedules.
(a)Exhibits.
| Exhibit Number | Description of Exhibit | |||||||
| 3.1* | ||||||||
| 3.2* | ||||||||
| 4.1†* | ||||||||
| 4.2†* | ||||||||
| 4.3* | ||||||||
| 5.1 | ||||||||
| 10.1†* | ||||||||
| 10.2* | ||||||||
| 10.3†* | ||||||||
| 10.4†* | ||||||||
| 10.5* | ||||||||
| 10.6* | ||||||||
| 10.7* | ||||||||
| 10.8* | ||||||||
| 10.9+* | ||||||||
| 10.10+* | ||||||||
| 10.11+* | ||||||||
| 10.12+* | ||||||||
| 10.13+* | ||||||||
| 10.14+* | ||||||||
| 10.15+* | ||||||||
| 10.16#+* | ||||||||
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| 10.17#+* | ||||||||
| 10.18#+* | ||||||||
| 10.19#+* | ||||||||
| 10.20#+* | ||||||||
| 10.21#+* | ||||||||
| 10.22#+* | ||||||||
| 10.23+* | ||||||||
| 10.24†#* | ||||||||
| 21.1* | ||||||||
| 23.1 | ||||||||
| 23.2 | ||||||||
| 24.1* | ||||||||
| 107* | ||||||||
__________________
*Previously filed.
†Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request.
+Indicates management contract or compensatory plan.
#Certain information has been redacted pursuant to Item 601(a)(6) of Regulation S-K. A copy of any redacted information will be furnished to the SEC upon request.
(b)Financial Statement Schedules.
All financial statement schedules are omitted because the information required to be set forth therein is not applicable or is shown in the consolidated financial statements or the notes thereto.
Item 17. Undertakings.
The undersigned registrant hereby undertakes:
(1)To file, during any period in which offers or sales are being made, a post-effective amendment to this registration statement:
(i)To include any prospectus required by Section 10(a)(3) of the Securities Act.
(ii)To reflect in the prospectus any facts or events arising after the effective date of the registration statement (or the most recent post-effective amendment thereof) which, individually or in the aggregate, represent a fundamental change in the information set forth in the registration statement. Notwithstanding the foregoing, any increase or decrease in volume of securities offered (if the total dollar value of securities offered would not exceed that which was registered) and any deviation from the low or high end of the estimated maximum offering range may be reflected in the form of prospectus filed with the Securities and Exchange Commission pursuant to Rule 424(b) if, in the aggregate, the changes in volume and price represent no more than 20% change in the maximum aggregate offering price set forth in the “Calculation of Registration Fee” table in the effective registration statement;
(iii)To include any material information with respect to the plan of distribution not previously disclosed in the registration statement or any material change to such information in the registration statement.
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(2)That, for the purpose of determining any liability under the Securities Act, each such post-effective amendment shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
(3)To remove from registration by means of a post-effective amendment any of the securities being registered which remain unsold at the termination of the offering.
Insofar as indemnification for liabilities arising under the Securities Act may be permitted to directors, officers, and controlling persons of the registrant pursuant to provisions described in Item 14 above, or otherwise, the registrant has been advised that in the opinion of the Securities and Exchange Commission such indemnification is against public policy as expressed in the Securities Act and is, therefore, unenforceable. In the event that a claim for indemnification against such liabilities (other than the payment by the registrant of expenses incurred or paid by a director, officer, or controlling person of the registrant in the successful defense of any action, suit, or proceeding) is asserted by such director, officer, or controlling person in connection with the securities being registered, the registrant will, unless in the opinion of its counsel the matter has been settled by controlling precedent, submit to a court of appropriate jurisdiction the question whether such indemnification by it is against public policy as expressed in the Securities Act and will be governed by the final adjudication of such issue.
The undersigned registrant hereby undertakes that:
(1)For purposes of determining any liability under the Securities Act, the information omitted from the form of prospectus filed as part of this registration statement in reliance upon Rule 430A and contained in a form of prospectus filed by the registrant pursuant to Rule 424(b)(1) or (4) or 497(h) under the Securities Act shall be deemed to be part of this registration statement as of the time it was declared effective.
(2)For the purpose of determining any liability under the Securities Act, each post-effective amendment that contains a form of prospectus shall be deemed to be a new registration statement relating to the securities offered therein, and the offering of such securities at that time shall be deemed to be the initial bona fide offering thereof.
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SIGNATURES
Pursuant to the requirements of the Securities Act of 1933, the registrant has duly caused this registration statement to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on July 3, 2024.
| TALEN ENERGY CORPORATION | |||||
| By: | /s/ Mark A. McFarland | ||||
| Mark A. McFarland | |||||
| Chief Executive Officer | |||||
Pursuant to the requirements of the Securities Act of 1933, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||||||||
| /s/ Mark A. McFarland | Chief Executive Officer and Director (Principal Executive Officer) | July 3, 2024 | ||||||||||||
| Mark A. McFarland | ||||||||||||||
| * | Chief Financial Officer (Principal Financial Officer) | July 3, 2024 | ||||||||||||
| Terry L. Nutt | ||||||||||||||
| * | Chief Accounting Officer (Principal Accounting Officer) | July 3, 2024 | ||||||||||||
| Tony Plagens | ||||||||||||||
| * | Chairman of the Board of Directors and Director | July 3, 2024 | ||||||||||||
| Stephen Schaefer | ||||||||||||||
| * | Director | July 3, 2024 | ||||||||||||
| Gizman Abbas | ||||||||||||||
| * | Director | July 3, 2024 | ||||||||||||
| Anthony Horton | ||||||||||||||
| * | Director | July 3, 2024 | ||||||||||||
| Karen Hyde | ||||||||||||||
| * | Director | July 3, 2024 | ||||||||||||
| Joseph Nigro | ||||||||||||||
| * | Director | July 3, 2024 | ||||||||||||
| Christine Benson Schwartzstein | ||||||||||||||
| *By: | /s/ Mark A. McFarland | ||||
| Mark A. McFarland | |||||
| Attorney-in-fact | |||||
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