Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
As confidentially submitted to the Securities and Exchange Commission on October 23, 2023.
This draft registration statement has not been publicly filed with the Securities and Exchange Commission and all information herein remains strictly confidential.
Registration No. 333-
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
Confidential Draft Submission No. 2
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.
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 , 2023.
TALEN ENERGY CORPORATION
49,877,272 Shares of Common Stock
This prospectus relates to the registration of up to 49,877,272 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 , the closing sales price of our common stock as reported on the OTCQX U.S. Market was $ per share. We intend to apply 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 .
Investing in our common stock involves risks. See the section titled “Risk Factors” beginning on page 17 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 , 2023.
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 (the “Initial Debtors”) each filed a voluntary petition for relief under Chapter 11 of the Bankruptcy Code (the “Restructuring”) in the United States Bankruptcy Court for the Southern District of Texas (Houston Division) (the “Bankruptcy Court”). While TEC’s management continued to operate the Initial Debtors as debtors-in-possession during the pendency of the Restructuring, the activities that most significantly impacted the 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 the Initial Debtors. On December 20, 2022, the Bankruptcy Court confirmed the Plan of Reorganization.
On May 17, 2023 (the “Emergence Date”), the Plan of Reorganization became effective and we emerged from the Restructuring (the “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 transaction’s economic substance, in which certain creditors of TES effectively equitized
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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 condensed consolidated financial statements of TEC after the Emergence Date are not comparable to its condensed 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.
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. Unless the context otherwise requires, all references in this prospectus to “we,” “us,” “our,” “our company,” “Talen” and “TEC” refer to Talen Energy Corporation and its consolidated subsidiaries.
Our Business
Talen is an independent power producer and infrastructure company committed to the energy transition. We own and operate over 10 GW of high-quality 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 continuing to reduce the carbon profile of our fleet through conversions and retirements of wholly-owned coal facilities. In addition, as part of our Cumulus digital infrastructure and energy transition platform, 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. We believe our data center project provides both an attractive source of demand for the plant and a new source of incremental revenues for us. In 2022, we generated enough power for 3.4 million average American homes (based on the U.S. Energy Information Administration’s 2021 estimate of 10,632 KWh per home). In the first half of 2023, Talen generated $496 million of net income and $774 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 60% of our generation carbon-free in the first half of 2023. We believe Susquehanna may benefit from the Nuclear PTC beginning in 2024, providing increased cash flow stability through 2032. Our 8.0 GW natural gas, oil and peaking fleet in PJM and ERCOT (of which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after conversion from coal) 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. The plants in PJM generate material annual capacity revenues, and a seasoned operating team in both PJM and ERCOT lead the monetization of seasonal commodity volatility. We have already completed the conversion of approximately 2.9 GW of our legacy coal fleet to natural gas, with an additional 300 MW coal-to-oil conversion nearing completion, 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, anchored by the world’s first 24x7 carbon-free, direct-connect data center campus. The Cumulus Digital campus, an up to 1.0 GW hyperscale data center campus adjacent to the Susquehanna facility, will provide digital infrastructure powered by “behind-the-fence” generation directly from Susquehanna. With limited remaining capital expenditures planned for the first phase of operations, we are now focused on 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 our data center business 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
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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 and other projects, please see “Business—Properties.”
Note: Fleet as of 6/30/2023.
1.Brunner Island: Coal-to-dual fuel conversion completed in 2016; coal-fired generation is already restricted during the EPA Ozone Season, which is May 1 to September 30 of each year and will cease by year-end 2028. Montour: Coal-to-gas conversion completed in August 2023. Wagner unit 3: Conversion from coal to oil to be complete by year-end 2023. However, in the fourth quarter of 2023, we provided notice to PJM that requests deactivation of Wagner on June 1, 2025.
2.A notice was provided to PJM that requested deactivation of Brandon Shores on June 1, 2025.
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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 2022, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a top-quartile low all-in cost of approximately $22 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. We believe the facility is now also poised to benefit substantially from the Nuclear PTC enacted under the Inflation Reduction Act, which, starting in 2024, will 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. The co-located data center campus under development by Cumulus Data, which is planned to be a zero-carbon data center campus adjacent to Susquehanna (“Cumulus Data Center Campus”) provides Susquehanna with additional opportunities to maximize future revenue, including through long-term power sale arrangements that create value for both the plant and the data center.
Susquehanna’s efficient cost structure is supported in part by a portfolio of supply contracts for all stages of the nuclear fuel cycle. We have already procured substantially all of the physical fuel required to operate the facility through 2025 and all required conversion and fabrication are secured through the end of 2029. We also recently accelerated certain fuel deliveries to eliminate ongoing 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.
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Natural gas, oil and peaking units. Our generation portfolio includes 10 geographically and technologically diverse natural gas, oil and peaking facilities across the generation stack in PJM and ERCOT, with certain units capable of utilizing multiple fuel sources.
•PJM. Our PJM assets benefit from both a wholesale and a capacity market. Lower Mount 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 lives and enables us to maintain both the associated capacity revenues and the additional commodity upside potential.
•ERCOT. Our ERCOT assets are highly dispatchable and operate at low heat rates, leaving them well positioned to take advantage of market demand for flexible generation, especially since 2021 when ERCOT increased its ancillary service procurement volumes to provide additional operating reserves. Our Barney Davis and Nueces Bay facilities, both located in growing Corpus Christi, TX, have significant duct-firing capabilities that enable them to optimize between ancillary services and energy during periods of market volatility. Our Laredo plant is one of the most efficient and operationally flexible peakers in ERCOT, with a 10-minute quick start for ancillary capability. The operational flexibility of our Texas assets enables them to respond quickly to pricing signals to capture value in ERCOT.
Our Cumulus platform opportunities. As described below, we have a number of growth opportunities in our Cumulus platform. 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:
•Hyperscale data center campus. Cumulus Data, in which we own an approximate 95% equity interest, is developing an up-to-1.0 GW hyperscale data center campus adjacent to Susquehanna, which will provide first-of-its-kind digital infrastructure powered by carbon-free energy. Construction of the core and shell of the first data center building, with capacity of 48 MW or more, is largely complete, along with electrical infrastructure that can accommodate three total buildings of similar size. Further expansion up to approximately 1.0 GW is possible across the 1,200-acre campus with additional substation infrastructure and buildings. We believe the Cumulus Data Center Campus represents an opportunity to secure contracts with high-quality counterparties at attractive power prices, structured with limited incremental capital investments from us. The supply of power directly from Susquehanna creates the potential for long-term PPA pricing that could exceed the Nuclear PTC “floor” and still provide data center customers with attractive terms. Both Cumulus Data and its customers may further benefit from the data center’s exemption from Pennsylvania sales and use tax, which provides significant savings on eligible purchases of equipment for the campus.
•Renewables, battery and growth opportunities. Our Cumulus Affiliates’ renewables and battery storage initiatives 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 Center Campus. This 150 gross MW facility 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.
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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 nearly 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 the third quarter of 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 is expected to be completed by the end of 2023, with substantially all required capital expenditures already made; however, for economic reasons, we have requested deactivation of Wagner in mid-2025, and we currently anticipate that the plant will not operate after that time. 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 currently anticipate that the plant will not operate after that time unless required for reliability reasons.
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. When measured by the operational and safety standards adopted by the nuclear industry, Susquehanna is one of the top performers in the United States. In 2022, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a low all-in cost of approximately $22 per MWh while maintaining leading safety performance.
Going forward, our commercial strategy at Susquehanna will 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 from 2024 to 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 can monetize remaining credits through the sale to an eligible taxpayer. The Cumulus Data Center Campus creates additional incremental value for Susquehanna, providing the opportunity to maximize future cash flows through long-term PPAs. Based on recent data center market dynamics, we believe these PPAs could provide contracted revenue streams at prices meaningfully above the Nuclear PTC “floor” while remaining attractive to high-quality customers.
Flexible and highly dispatchable natural gas, oil and peaking fleet provides the ability to capture significant incremental revenue and benefit from shifting market dynamics. Our 8.0 GW natural gas, oil and peaking fleet (of which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after conversion 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 through our PJM and ERCOT assets while also generating predictable capacity revenues in PJM. Our seasoned operating teams in both PJM and ERCOT lead the monetization of seasonal commodity volatility. Our natural gas, oil and peaking fleet provides meaningful operational flexibility, with certain units capable of achieving full load in as little as 10 minutes, enabling us to respond quickly 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.
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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, oil and peaking fleet is also poised to benefit from potential regulatory reforms and shifting market dynamics. In PJM, retirements in the coming years are expected to tighten reserve margins, and PJM is working to reform the capacity market, which could improve the risk-reward proposition for existing generators. Meanwhile, ERCOT pricing volatility is expected to increase, leading to significant value opportunity for facilities that can quickly respond to pricing signals, and proposed marked redesign is expected to improve scarcity pricing (ORDC) and create new ancillary services. We believe our fleet is well positioned to benefit from these developments.
Zero-carbon digital infrastructure optimally positioned for monetization and value creation. The demand for colocation data centers in the United States has significantly outpaced supply over the last few years, which we believe has favorable impacts for Cumulus Data. The development of Cumulus Data’s hyperscale data campus is expected to provide an integrated power and digital infrastructure solution to end use data center customers. This development capitalizes on a clear synergy by bringing a growing electricity demand (i.e., data storage) directly to Susquehanna’s low-cost, reliable and carbon-free power supply. The near-term completion of the data center’s first 48 MW building unlocks the significant value of the investment capex deployed in prior years and is expected to result in higher net income and Adjusted EBITDA to free cash flow conversion, possibly as early as 2024.
We are now focused on realizing the value of our prior investments in the data center and are engaging with a variety of potential counterparties regarding a possible strategic transaction. We are considering a number of possible structures, including but not limited to joint ventures, asset sales or long-term leases, to maximize the value of these assets to our business in both the near-term and the long-term. The Cumulus Data Center Campus is accretive to our core generation business, providing an opportunity to maximize Susquehanna’s future cash flows through large-scale, long-term power contracts at mutually attractive rates, and any strategic transaction will seek to maximize value not only for the data center but also for Susquehanna.
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 June 30, 2023, we have unrestricted cash of approximately $127 million and our revolving credit facility is undrawn with $700 million of available commitments, resulting in liquidity of approximately $827 million. 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
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on capital discipline and commercial and risk management to ensure stable and predictable cash-flow generation and preserve margin.
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.
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 $496 million of net income and $774 million of Adjusted EBITDA in the first half of 2023. “—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 2022, our PJM fleet generated approximately $377 million in capacity revenues. We now also have substantive federal support for nuclear generation, which is accretive to our portfolio, with the Nuclear PTC materially 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 reforms in the PJM and ERCOT 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. Importantly, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service requirements.
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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, 2022, we have reduced our annual carbon dioxide emissions by approximately 69%, nitrogen oxide emissions by approximately 81% and sulfur dioxide emissions by approximately 86% when compared to 2010 levels.
Our environmental position is firmly anchored by Susquehanna, which enabled us to generate approximately 50% of our electricity output carbon-free in 2022 and over 60% carbon-free in the first half of 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 0.35 metric tons per MWh in 2022, which is over 40% better than our carbon intensity in 2010. We expect to continue reducing our carbon footprint through the recently- and nearly-completed conversions of 3.2 GW of our legacy coal fleet (including Wagner Unit 3) 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. 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.
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, whether through long-term power sales to the Cumulus Data Center Campus or 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 several strong growth options already under development, with the majority of our
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planned capital expenditures on them already spent and are now focused on monetizing our prior investments. 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.
Reorganization and Emergence
On May 9, 2022, TES and 71 of our 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 United States Bankruptcy Court for the Southern District of Texas 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 available 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 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 condensed 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.
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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.
•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 in connection with our investment, through the Cumulus Affiliates, in (i) the development of digital infrastructure projects adjacent to Susquehanna and (ii) a pipeline of renewable energy and battery storage projects (collectively, the “Cumulus Projects”) may consume a significant portion of our management’s focus and resources, and if not completed or successful, reduce our profitability.
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•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.
•Cumulus Data’s business depends upon the demand for data centers.
•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.
•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 49,877,272 shares. | ||||
Common stock outstanding | 59,028,843 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 17. | ||||
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 the Emergence Date and the Predecessor and its consolidated subsidiaries for periods prior to the Emergence Date. The financial statements of the Successor are not entirely comparable to the financial statements of the Predecessor as those periods prior to the Emergence Date 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 June 30, 2023 and for the six months ended June 30, 2023 is derived from the Predecessor’s and the Successor’s unaudited condensed consolidated financial statements included elsewhere in this prospectus, which have been prepared on a basis consistent with the Predecessor’s audited consolidated financial statements. The summary historical consolidated financial information as of and for the years ended December 31, 2022, 2021 and 2020 is derived from the Predecessor’s audited consolidated financial statements included elsewhere in this prospectus.
The pro forma information reflects the condensed consolidated financial information of the Predecessor for the year ended December 31, 2022 and the period from January 1, 2023 through May 17, 2023 and the Successor for the period from May 18, 2023 through June 30, 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 statements of income (loss) for the six months ended June 30, 2023 and for the year ended December 31, 2022 give effect to the pro forma adjustments as if each adjustment had occurred on January 1, 2022, 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 condensed consolidated results of operations would have been had the adjustments occurred on the dates assumed, nor is it necessarily indicative of future condensed 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,” the Annual Financial Statements and the Interim 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 will be taken into account in our future financial statements.
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| Successor | Predecessor | Pro Forma | ||||||||||||||||||||||||||||||||||||||||||||||||
Period From May 18, 2023 Through June 30, 2023 | Period From January 1, 2023 Through May 17, 2023 | Year Ended December 31, | Six Months Ended June 30, 2023 | Year Ended December 31, 2022 | ||||||||||||||||||||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | ||||||||||||||||||||||||||||||||||||||||||||||||
| (in millions, except per share amounts) | ||||||||||||||||||||||||||||||||||||||||||||||||||
Operating revenues | $ | 301 | $ | 1,210 | $ | 3,089 | $ | 928 | $ | 1,726 | $ | 1,511 | $ | 3,089 | ||||||||||||||||||||||||||||||||||||
Impairments | — | (381) | — | — | (681) | $ | (381) | $ | — | |||||||||||||||||||||||||||||||||||||||||
Operating income (loss) | 55 | (76) | 241 | (1,100) | (716) | $ | 27 | $ | 280 | |||||||||||||||||||||||||||||||||||||||||
Net income (loss) | 31 | 465 | (1,293) | (977) | (664) | $ | (15) | $ | (361) | |||||||||||||||||||||||||||||||||||||||||
Weighted average shares of common stock outstanding — basic | 59,029 | — | — | — | — | 59,029 | 59,029 | |||||||||||||||||||||||||||||||||||||||||||
Weighted average shares of common stock outstanding — diluted | 59,088 | — | — | — | — | 59,088 | 59,088 | |||||||||||||||||||||||||||||||||||||||||||
Net income(loss) per weighted average share of common stock outstanding — basic | $ | 0.49 | — | — | — | — | $ | (0.05) | $ | (6.05) | ||||||||||||||||||||||||||||||||||||||||
Net income (loss) per weighted average share of common stock outstanding — diluted | $ | 0.49 | — | — | — | — | $ | (0.05) | $ | (6.04) | ||||||||||||||||||||||||||||||||||||||||
| Successor | Predecessor | |||||||||||||||||||
| As of June 30, 2023 | As of December 31, | |||||||||||||||||||
| 2022 | 2021 | |||||||||||||||||||
| (in millions) | ||||||||||||||||||||
Total assets | $ | 7,023 | $ | 10,722 | $ | 10,053 | ||||||||||||||
Long term debt (including current portion) | 2,846 | 3,504 | 3,894 | |||||||||||||||||
Total liabilities | 4,563 | 11,204 | 9,320 | |||||||||||||||||
Total equity | 2,460 | (482) | 733 | |||||||||||||||||
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 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. 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 consider them along with their most directly comparable GAAP financial measure. Adjusted EBITDA has 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
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of Directors, shareholders, creditors, analysts and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.
Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) nonrecurring 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 including 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. 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.
The following table presents a reconciliation of the GAAP financial measure of net income to the non-GAAP financial measure of Adjusted EBITDA:
| Successor | Predecessor | Predecessor | |||||||||||||||
Period From May 18, 2023 Through June 30, 2023 | Period From January 1, 2023 Through May 17, 2023 | Year Ended December 31, 2022 | |||||||||||||||
| (in millions) | |||||||||||||||||
Net Income (Loss) | $ | 31 | $ | 465 | $ | (1,293) | |||||||||||
Less: Bankruptcy, Liability Management, and Restructuring Activities | |||||||||||||||||
Hedge termination losses, net (1) | — | — | 158 | ||||||||||||||
Reorganization (gain) loss, net (2) | — | (799) | 812 | ||||||||||||||
Operational and other restructuring activities (3) | 8 | 17 | 522 | ||||||||||||||
Bankruptcy exit fees | 4 | — | — | ||||||||||||||
Liability management costs and other professional fees | — | — | 46 | ||||||||||||||
Total Bankruptcy, Liability Management and Restructuring Activities | $ | 12 | $ | (782) | $ | 1,538 | |||||||||||
Other Adjustments | |||||||||||||||||
Interest expense and other finance charges | 33 | 163 | 365 | ||||||||||||||
| Income tax (benefit) expense | 19 | 212 | (35) | ||||||||||||||
| Depreciation, amortization and accretion | 28 | 200 | 520 | ||||||||||||||
| Nuclear fuel amortization | 25 | 33 | 94 | ||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | (41) | 63 | (625) | ||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | (39) | (57) | 184 | ||||||||||||||
| Stock-based compensation expense | 16 | — | — | ||||||||||||||
Environmental and ARO revisions on fully depreciated property, plant and equipment (4) | — | — | 18 | ||||||||||||||
(Gain) loss on non-core asset sales, net (5) | — | (50) | (3) | ||||||||||||||
| Non-cash impairments | — | 381 | — | ||||||||||||||
Unusual market events (6) | 1 | 14 | 33 | ||||||||||||||
Net periodic defined benefit cost (7) | — | (3) | 12 | ||||||||||||||
| Development expenses | 2 | 10 | 17 | ||||||||||||||
Impairments, canceled projects, obsolescence, and receivables allowance (8) | — | — | (2) | ||||||||||||||
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Non-cash fuel inventory net realizable value and obsolescence charges (9) | 3 | 56 | — | ||||||||||||||
| Liquidated damages | — | — | (2) | ||||||||||||||
Legal settlements and litigation costs (10) | — | — | 20 | ||||||||||||||
Consolidation of subsidiary (gain) loss (11) | — | — | 170 | ||||||||||||||
| Cumulus Digital activities including noncontrolling interests | (8) | (14) | 3 | ||||||||||||||
| Other | (3) | 4 | 1 | ||||||||||||||
| Total Adjusted EBITDA | $ | 79 | $ | 695 | $ | 1,015 | |||||||||||
__________________
(1)2022 relates to a nonrecurring charge on terminated power contracts. See Note 5 in Notes to the Interim Financial Statements and Note 4 in Notes to the Annual Financial Statements for additional information.
(2)Represents amounts incurred directly related to the Restructuring. See Note 3 in Notes to the Interim Financial Statements and Note 3 in Notes to the Annual Financial Statements for additional information.
(3)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.
(4)See Note 15 in Notes to the Annual Financial Statements for additional information on accrued environmental costs and ARO revisions.
(5)See Note 21 in Notes to the Interim Financial Statements and Note 25 in Notes to the Annual Financial Statements for additional information.
(6)2023 relates to the true up of capacity penalty charges due to the receipt of finalization of amounts by PJM compared to estimates recognized in 2022 related to Winter Storm Elliot.
(7)Consists of “Postretirement benefits service cost” and “Postretirement benefits gains (loss), net” presented on the Condensed Consolidated Statements of Operations for the period ended June 30, 2023 and for the year ended December 31, 2022.
(8)See Notes 4, 9 and 14 in Notes to the Annual Financial Statements for additional information.
(9)See Note 8 in the Notes to the Interim Financial Statements for additional information.
(10)2022 primarily relates to expense incurred related to the Kinder Morgan litigation. See Note 12 in Notes to the Annual Financial Statements for additional information.
(11)See Note 12 in Notes to the Annual Financial Statements for additional information on the consolidation of Cumulus Digital Holdings in 2022.
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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 June 30, 2023, approximately 84% of our capacity was located in PJM and 14% was located in ERCOT. 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, particularly in ERCOT, 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 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 both PJM and ERCOT. 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. Except with respect to our operations in ERCOT, 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 PJM’s 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 PJM and ERCOT.”
Our generation assets (including those in ERCOT) 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 2022, 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 to Cumulus Data, 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 Nuclear 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 issued LCs to the lenders of the Cumulus Digital TLF 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 5 in Notes to the Interim Financial Statements and Note 4 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. 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 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-
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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 September 30, 2023, we had 2,118 full-time employees, 41% 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, 2022, our qualified defined benefit pension plans for our retirees and certain employees were underfunded by an estimated $276 million with a total benefit liability of an estimated $1.27 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 Pension Litigation (see “Business—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
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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.
There is also unpredictability around capacity revenues due to lack of reliable pricing and PJM Base Residual Auctions. The PJM and ERCOT markets are 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 12 to the Annual Financial Statements included elsewhere in this prospectus for more information on the capacity market and systemic risks in PJM and ERCOT.
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 that significantly reduces the application of the existing 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 therefore PJM’s MOPR tariff language went into effect in September 2021 by operation of law. Appeals relating to the narrowed PJM MOPR are pending before the U.S. Court of Appeals for the Third Circuit. As a result, the final impact on Talen’s financial condition, results of operations or liquidity is not known at this time.
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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 Reliability Pricing Model. The delay schedules the PJM Base Residual Auctions for 2025/2026 in June 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 adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased costs to purchase and operate emissions control systems, acquire emissions allowances or comply with new regulatory or reporting requirements. Any such 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 (the “CAA”), 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. Moreover, federal and state laws and regulations may change or impose additional requirements in the future that could affect the expected timing, scope of work and its complexity, expected costs for labor and materials, removal and remediation techniques. Future adjustments to the Talen Montana ARO estimates may be required due to the ongoing remediation requirements under MDEQ obligations and the EPA CCR Rule, 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
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currently estimated. Please see Note 15 to the Annual Financial Statements included elsewhere in this prospectus for more information on 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 Nuclear 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 Nuclear maintains property and liability insurance for losses related to nuclear operations at Susquehanna and is subject to NRC insurance requirements and the Price-Anderson Act scheme, there may be limitations on the amounts and types of insurance commercially available, or we may have insufficient coverage with respect to any such losses. Uninsured losses and other liabilities and expenses resulting from an incident at Susquehanna, to the extent not recovered from insurers or the nuclear industry, could be borne by us. Additionally, an accident or other significant event at a nuclear facility within the United States or abroad, whether owned by us or others, could result in increased regulation and reduced public support for nuclear-fueled energy. If an incident did occur at Susquehanna, any resulting operational loss, damages and injuries would likely have a material adverse effect on our results of operations, cash flows, financial condition and liquidity.
Our 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
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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 changes in rules and regulations, such as those pertaining to air emissions (including GHG regulations) and CCRs, we have spent, and expect to continue to spend, substantial amounts on measures regarding environmental control and compliance. The EPA regulates GHG emissions from the power sector and certain states regulate carbon dioxide emissions from power generation facilities. These regulations primarily affect higher-emitting units in the national power fleet like our coal-fired generation facilities. 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. 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. In particular, 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. 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.
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.
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 and ERCOT.
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 expect to incur certain Capacity Performance penalties charged by PJM for our under-performing facilities and earn 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, but no assurance can be provided that they will be successful in reducing net exposure to penalties assessed by PJM.
Additionally, Talen incurred an estimated $78 million pre-tax nonrecurring commercial loss associated with its ERCOT activities during Winter Storm Uri for the year ended December 31, 2021. Due to defaults of other ERCOT market participants, ERCOT instituted “short payments” by withholding certain amounts owed to non-defaulting market participants. Given the uncertainty of when and how the short payments would be recovered from ERCOT, Talen recognized a charge of approximately $9 million during the year ended December 31, 2021 to fully reserve
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the short payments due to Talen. The outstanding reserve was approximately $4 million and $9 million as of December 31, 2022 and 2021, respectively. No assurance can be provided that these losses will not vary based on the final market settlements or any legal and (or) regulatory actions.
The Texas Legislature, the PUCT and ERCOT have implemented new requirements and continue to consider future market design and other rule changes in response to Winter Storm Uri and other extreme weather events. We cannot fully predict the impacts that any future market designs or rule changes may have on our liquidity or results of operations.
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 repurchases of stock 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 we expect electricity produced and sold by Susquehanna after December 31, 2023 through December 31, 2032 to qualify for the Nuclear PTC, which is subject to potential adjustments, the Inflation Reduction Act’s provisions are subject to implementation regulations, whose terms are not yet known. As such, we cannot fully predict the impacts that any such tax credits may have on our liquidity or results of operations. We are continuing to evaluate the Inflation Reduction Act and its requirements, as well as its application to us. Any elimination of the Nuclear PTC may adversely affect our business and financial condition.
In addition, our tax reporting is subject to audit by tax authorities. We may enter into transactions and arrangements in the ordinary course of business in which the tax treatment is not entirely certain. We must therefore make estimates and judgments in determining our consolidated tax provisions and accruals. The final outcome of any audits by tax authorities may differ from estimates and assumptions used in determining our consolidated tax provisions and accruals, and the resolution of tax assessments or audits by tax authorities could impact operations. This could result in a material effect on our consolidated income tax provision, financial position and the net income/loss for the period for which such determinations are made.
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Our ability to utilize our tax attributes, including net operating loss carryforwards, remaining following Emergence, if any, may be limited.
As of December 31, 2022, we had approximately $1.3 billion of U.S. federal net operating loss (“NOL”) carryforwards and approximately $1.0 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 read Note 16 of the Annual Financial Statements, Note 12 to the Interim Financial Statements and “Business—Legal Matters” for more information regarding our ongoing 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 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.
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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 and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the Indenture and the agreements governing the Credit Facilities contain certain restrictions with respect to TES’s ability to distribute cash to TEC.” and “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
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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, the agreements governing the Credit Facilities and the Cumulus Digital Credit Agreement, 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 in connection with the Cumulus Projects 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 pursuant to corporate and administrative service agreements. As a result, the operations and activities of the Cumulus Affiliates may divert the attention and impact the availability of TES personnel. The Cumulus Projects may also require us to spend significant sums for engineering, construction, permitting, legal, financial advisory and other expenses before we determine whether a development project is feasible, economically attractive or capable of being financed. In addition, the economic assumptions underlying one or more of the Cumulus Projects may prove to be incorrect or materially different than projected, which may cause us to reevaluate pursuing or further investing in a particular project.
Our Cumulus Projects are typically planned to be large and 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.
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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 for potential solar and wind projects. Additionally, we own an approximately 95% equity interest in Cumulus Digital Holdings with affiliates of Orion as minority investors, and 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, Cumulus Data’s and Nautilus’ 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.
Cumulus Data’s business depends upon the demand for data centers.
A reduction in the demand for data center capacity could have an adverse effect on the further development of the Cumulus Data Center Campus and Cumulus Data’s financial condition. Any such slowdown or adverse development in the data center, Internet and data communications and broader technology industries could reduce corporate IT spending or demand for data center space, which could materially adversely affect Cumulus Data’s financial condition and results of operations. In addition, Cumulus Data’s only tenant is Nautilus. If Cumulus Data does not attract tenants, it will not produce revenue, which could ultimately result in cessation of operations without additional financing. Incremental investment will be dependent on our ability to secure profitable long-term leases with credit-worthy third-party tenants to generate predictable cash flows.
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 they have historically experienced significant intraday and long-term price volatility. If the price of Bitcoin declines, Cumulus Coin’s profitability will decline, which would adversely affect the business, prospects, financial condition, results of operation of Nautilus and Cumulus Coin, and in turn adversely affect the ability of Cumulus Digital to service debt under the Cumulus Digital TLF, which has direct recourse to us, to the extent of the $50 million TES LC and the TEC guarantee provided to the lenders thereunder.
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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 Digital’s operations, regulation of Bitcoin under U.S. or other securities laws or restrict or eliminate the Bitcoin market, which would negatively affect the value of Cumulus Digital’s operations and may result in expense or burdens to us. As a result, we may decide to cease certain operations and change our digital asset business model. Any disruption of our operations in response to the changed regulatory circumstances may be at a time that is disadvantageous to us.
A change in regulatory or financial accounting standards for Bitcoin could result in the necessity to change the accounting methods we currently intend to employ in respect of our anticipated revenues and assets and restate any financial statements produced based on those methods. Such a restatement could adversely affect Cumulus Digital’s business, prospects, financial condition and results of operation.
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 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
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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 and 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 and Cumulus Digital Holdings 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’ pro forma consolidated total net leverage ratio is less than or equal to 1.5 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 2.25 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. The Cumulus Digital Credit Agreement also restricts the ability of Cumulus Digital Holdings to pay TES (and, consequently, TEC) dividends or
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distributions, subject to certain exceptions, which include customary tax distributions. 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 35.1% 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;
•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
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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 a concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not statements of historical fact constitute “forward-looking statements.” 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:
•any continued effects of the Restructuring on our liquidity, results of operations or business prospects or the interests of various constituents;
•our ability to comply with the covenants under the agreements governing our post-Emergence 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-fired power generation business 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
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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 ISO, or changes to the capacity auction rules and procedures;
•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 carbon deleveraging plans, including our renewable energy, battery storage and 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;
•construction and development risks relating to projects undertaken as part of our carbon deleveraging plans, including risks relating to our ability to acquire the necessary permits, the performance of third-party contractors and fluctuating construction costs;
•operational risks relating to the data center and coin campus, including the risk of interruptions to the provision of power, as well as cyber or other breaches of its infrastructure;
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•risks relating to our ability to attract and retain customers, including data center tenants or power purchasers for our renewable energy projects, on reasonable business terms or at all;
•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 of the 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 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 beginning June 23, 2023 through June 30, 2023) | $ | 52.50 | $ | 46.40 | |||||||
| Third Quarter 2023 (for the period beginning July 1, 2023 through July 23, 2023) | $ | 52.50 | $ | 49.50 | |||||||
| OTCQX U.S. Market | |||||||||||
| Third Quarter 2023 (for the period beginning July 24, 2023 through September 30, 2023) | $ | 55.25 | $ | 51.50 | |||||||
| Fourth Quarter 2023 (for the period beginning October 1, 2023 through , 2023) | $ | $ | |||||||||
On , the closing price of our common stock as reported on the OTCQX U.S. Market was $ per share. As of , there was one stockholder 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’ 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 June 30, 2023. You should read the information set forth below together with our consolidated financial statements and the related notes contained elsewhere in this prospectus.
| As of June 30, 2023 | |||||
| (in millions) | |||||
Cash and cash equivalents | $ | 127 | |||
| Debt: | |||||
| Revolving credit facilities | $ | — | |||
| Long-term debt | 2,832 | ||||
| Total debt | 2,832 | ||||
Stockholders’ deficit: | |||||
Common stock, $0.001 par value, 350,000,000 shares authorized as of May 17, 2023 and June 30, 2023; 59,028,843 and 59,028,843 shares issued and outstanding as of May 17, 2023 and June 30, 2023 | — | ||||
Additional paid-in capital | 2,325 | ||||
Accumulated retained earnings | 29 | ||||
Accumulated other comprehensive income | (3) | ||||
Total stockholders’ (deficit) equity | 2,351 | ||||
| Noncontrolling interests | 109 | ||||
| Total equity | 2,460 | ||||
| Total capitalization | $ | 5,292 | |||
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 six months ended June 30, 2023 and the Unaudited Pro Forma Condensed Consolidated Statement of Operations for the year ended December 31, 2022. 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, 2022. 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 Condensed Consolidated Balance Sheet as of June 30, 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: (i) Talen Energy Corporation and Subsidiaries Condensed Consolidated Statements of Operations (Unaudited) for the Period from January 1, 2023 through May 17, 2023 and for the Period from May 18, 2023 through June 30, 2023 and (ii) Talen Energy Supply, LLC and Subsidiaries, Consolidated Statements of Operations for the year ended December 31, 2022.
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. To the extent any proceeds are recovered by the Debtors pursuant to the PPL/Talen Montana litigation, 10% of the net proceeds recovered will be contributed to the pool of cash, subject to a cap of $11 million. See Note 12 in Notes to the Interim Financial Statements for information on the PPL/Talen Montana litigation.
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 the Emergence Date occurred on January 1, 2022.
46
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Unaudited Pro Forma Condensed Consolidated Statement of Operations
for the Six Months Ended June 30, 2023
| (Millions of Dollars, except share data) | |||||||||||||||||||||||||||||||||||||||||
| Successor Historical | Predecessor Historical | Transaction Accounting Adjustments | |||||||||||||||||||||||||||||||||||||||
| May 18, 2023 through June 30, 2023 | January 1 through May 17, 2023 | Reorganization Adjustments | Fresh Start Adjustments | Pro Forma | |||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 26 | $ | 108 | $ | — | $ | — | $ | 134 | |||||||||||||||||||||||||||||||
| Energy and other revenues | 188 | 1,042 | — | — | 1,230 | ||||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 87 | 60 | — | — | 147 | ||||||||||||||||||||||||||||||||||||
Operating Revenues | 301 | 1,210 | — | — | 1,511 | ||||||||||||||||||||||||||||||||||||
| Energy Expenses | |||||||||||||||||||||||||||||||||||||||||
| Fuel and energy purchases | (57) | (176) | — | — | (233) | ||||||||||||||||||||||||||||||||||||
| Nuclear fuel amortization | (25) | (33) | — | (1) | (d) | (59) | |||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (46) | (123) | — | — | (169) | ||||||||||||||||||||||||||||||||||||
Total Energy Expenses | (128) | (332) | — | (1) | (461) | ||||||||||||||||||||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||||||||||||||||||||
| Operation, maintenance and development | (69) | (285) | — | — | (354) | ||||||||||||||||||||||||||||||||||||
| General and administrative | (18) | (51) | — | — | (69) | ||||||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | (28) | (200) | — | 49 | (e) | (179) | |||||||||||||||||||||||||||||||||||
| Impairments | — | (381) | — | — | (381) | ||||||||||||||||||||||||||||||||||||
| Other operating income (expense), net | (3) | (37) | — | — | (40) | ||||||||||||||||||||||||||||||||||||
Operating Income (Loss) | 55 | (76) | — | 48 | 27 | ||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 39 | 57 | — | — | 96 | ||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | (33) | (163) | 66 | (a) | — | (130) | |||||||||||||||||||||||||||||||||||
| Reorganization income (expense), net | — | 799 | (1,259) | (b) | 460 | (b) | — | ||||||||||||||||||||||||||||||||||
| Other non-operating income (expense), net | (11) | 60 | — | — | 49 | ||||||||||||||||||||||||||||||||||||
Income (Loss) Before Income Taxes | 50 | 677 | (1,193) | 508 | 42 | ||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (19) | (212) | 192 | (c) | (18) | (c) | (57) | ||||||||||||||||||||||||||||||||||
Net Income (Loss) | 31 | 465 | (1,001) | 490 | (15) | ||||||||||||||||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 2 | (14) | — | — | (12) | ||||||||||||||||||||||||||||||||||||
Net Income (Loss) Attributable to Stockholders | $ | 29 | $ | 479 | $ | (1,001) | $ | 490 | $ | (3) | |||||||||||||||||||||||||||||||
| Earnings Per Common Share | |||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | 0.49 | $ | (0.05) | |||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | 0.49 | (0.05) | |||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 59,029 | 59,029 | |||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 59,088 | 59,088 | |||||||||||||||||||||||||||||||||||||||
The accompanying Notes to the Unaudited Pro Forma Financial Information are an integral part of the financial statements.
47
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Unaudited Pro Forma Condensed Consolidated Statement of Operations
for the Year Ended December 31, 2022
| (Millions of Dollars, except share data) | |||||||||||||||||||||||||||||
| Predecessor Historical | Transaction Accounting Adjustments | ||||||||||||||||||||||||||||
| January 1 through December 31, 2022 | Reorganization Adjustments | Fresh Start Adjustments | Pro Forma | ||||||||||||||||||||||||||
| Capacity revenues | $ | 377 | $ | — | $ | — | $ | 377 | |||||||||||||||||||||
| Energy and other revenues | 2,035 | — | — | 2,035 | |||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 677 | — | — | 677 | |||||||||||||||||||||||||
Operating Revenues | 3,089 | — | — | 3,089 | |||||||||||||||||||||||||
| Energy Expenses | |||||||||||||||||||||||||||||
| Fuel and energy purchases | (938) | — | — | (938) | |||||||||||||||||||||||||
| Nuclear fuel amortization | (94) | — | (69) | (d) | (163) | ||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (52) | — | — | (52) | |||||||||||||||||||||||||
Total Energy Expenses | (1,084) | — | (69) | (1,153) | |||||||||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||||||||
| Operation, maintenance and development | (610) | — | — | (610) | |||||||||||||||||||||||||
| General and administrative | (106) | — | — | (106) | |||||||||||||||||||||||||
| Depreciation, amortization and accretion | (520) | — | 108 | (e) | (412) | ||||||||||||||||||||||||
| Operation restructuring | (488) | — | — | (488) | |||||||||||||||||||||||||
| Other operating income (expense), net | (40) | — | — | (40) | |||||||||||||||||||||||||
Operating Income (Loss) | 241 | — | 39 | 280 | |||||||||||||||||||||||||
| Interest expense and other finance charges | (359) | 113 | (a) | (246) | |||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | (184) | — | — | (184) | |||||||||||||||||||||||||
| Reorganization income (expense), net | (812) | 812 | (b) | — | — | ||||||||||||||||||||||||
| Subsidiary gain (loss), net | (170) | — | — | (170) | |||||||||||||||||||||||||
| Other non-operating income (expense), net | (44) | — | — | (44) | |||||||||||||||||||||||||
Income (Loss) Before Income Taxes | (1,328) | 925 | 39 | (364) | |||||||||||||||||||||||||
| Income tax benefit (expense) | 35 | (24) | (c) | (8) | (c) | 3 | |||||||||||||||||||||||
Net Income (Loss) | (1,293) | 901 | 31 | (361) | |||||||||||||||||||||||||
| Less: Net Income (loss) attributable to noncontrolling interest | (4) | — | — | (4) | |||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | (1,289) | $ | 901 | $ | 31 | $ | (357) | |||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | (6.05) | |||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | (6.04) | ||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 59,029 | ||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 59,088 | ||||||||||||||||||||||||||||
The accompanying Notes to the Unaudited Pro Forma Financial Information are an integral part of the financial statements.
48
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 Predecessor period, from January 1 through May 17, 2023 or January 1, 2022 through December 31, 2022, (ii) Talen Energy Corporation (“TEC” or the “Successor”) for the Successor period, from May 18 through June 30, 2023 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, 2022.
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 at 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 less than $1 million and $2 million in interest expense for the six months ended June 30, 2023 and the year ended December 31, 2022, respectively.
(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 six months ended June 30, 2023, and the following reorganization adjustments for the six months ended June 30, 2023, and the year ended December 31, 2022.
| (Millions of Dollars) | Six months ended June 30, 2023 | Year ended December 31, 2022 | |||||||||
| Gain on debt discharge | $ | 1,459 | $ | — | |||||||
| Backstop Premium | (70) | (310) | |||||||||
| 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) | |||||||||
| Gains (losses) on contract terminations | — | (4) | |||||||||
| Other | (7) | (5) | |||||||||
Pro Forma Reorganization Adjustments | $ | 1,259 | $ | (812) | |||||||
(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 six months ended June 30, 2023 also takes into consideration the Successor amortization that was reported during the period.
49
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(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, 2022 and for the six months ended June 30, 2023:
| (Millions of Dollars) | Year ended 31, December, 2022 | Six months ended 30, June, 2023 | |||||||||
| Depreciation expense | (355) | (155) | |||||||||
| Amortization expense | (12) | (6) | |||||||||
| Accretion expense | (45) | (18) | |||||||||
Pro forma depreciation, amortization and accretion expense | (412) | (179) | |||||||||
| Historical depreciation, amortization and accretion expense - Successor | — | (28) | |||||||||
| Historical depreciation, amortization and accretion expense - Predecessor | (520) | (200) | |||||||||
Net (increase) / decrease in depreciation, amortization and accretion expense | 108 | 49 | |||||||||
50
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 is an independent power producer and infrastructure company committed to the energy transition. We own and operate over 10 GW of high-quality 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 continuing to reduce the carbon profile of our fleet through conversions and retirements of wholly-owned coal facilities. In addition, as part of our Cumulus digital infrastructure and energy transition platform, 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. We believe our data center project provides both an attractive source of demand for the plant and a new source of incremental revenues for us. In the first half of 2023, Talen generated $496 million of net income and $774 million of Adjusted EBITDA. “Prospectus Summary—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.
See “Organizational Structure” and “Generation Fleet” for additional information on our organization and generation portfolio.
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” and Notes 5 and 12 in Notes to the Interim Financial Statements and Notes 4 and 16 in Notes to the Annual Financial Statements for additional information on our risks.
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 our financial statements beginning in the second quarter 2023 (the period in which we emerged from the Restructuring) and may cause them not to be comparable to our financial statements for prior periods.
Through consummation of the Exit Financings and the Plan of Reorganization, we achieved a significant reduction in debt and interest, provided for full repayment of TES’s Prepetition Secured Indebtedness and completed the consensual equitization of all of TES’s Prepetition Unsecured Notes and PEDFA 2009A Bonds.
See Notes 2, 3 and 4 in Notes to the Interim 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 Interim Financial Statements for additional information on Talen’s indebtedness.
51
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Brandon Shores Conversion
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 provided a generator deactivation notice to PJM that requested deactivation on June 1, 2025. Accordingly, we incurred an aggregate $379 million of non-cash, pre-tax charges, including $361 million for an impairment of the generation facility’s asset group and $18 million for net realizable value and obsolescence charges on materials and supplies inventories and coal inventories. See Notes 8 and 10 in Notes to the Interim Financial Statements for additional information.
Unusual Market Events
Winter Storm Elliott. During December 2022, as a result of Winter Storm Elliott, PJM experienced extreme cold weather conditions that contributed to PJM declaring their first system-wide Maximum Generation Emergency Action since implementing Capacity Performance. PJM claimed that 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: (i) incurred certain Capacity Performance penalties charged by PJM for some of its generation facilities; and (ii) earned bonus revenues from PJM for others of its generation facilities. Talen has recognized an aggregate penalty liability of $51 million, net of expected bonus revenues and has elected to pay its charges to PJM over a nine-month period beginning in April 2023. In 2023, $13 million of penalties were charged for the period January 1 through May 17, 2023, as a reduction to “Capacity revenues” on the unaudited Condensed Consolidated Statement of Operations. See Note 12 in Notes to the Interim Financial Statements for additional information on Winter Storm Elliott, complaints filed at FERC disputing charges, risks regarding revisions to penalties and other regulatory matters.
Winter Storm Uri. 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 commercial loss associated with its ERCOT activities during Winter Storm Uri for the year ended December 31, 2021. Additionally, due to defaults of other ERCOT market participants, ERCOT has instituted short payments as described below. Due to uncertainty of when and how such short payments would ultimately be recovered from ERCOT, Talen recognized an additional charge of $9 million during the year ended December 31, 2021 to fully reserve the amount due to Talen that is the subject of short payments, net of a November 2021 receipt of a non-material amount for certain short payment reimbursements. See “ERCOT Market Systemic Risks” in Note 16 in Notes to the Annual Financial Statements for additional information.
Commodity Markets
Below-average temperatures during the second quarter 2023 resulted in lower demand for cooling needs in the PJM and ERCOT regions and were a contributor to reduced power load during the quarter when compared to the prior year quarter. Natural gas storage levels increased compared to prior year levels due to the combined effect of higher natural gas production and below normal heating demand in the 2022 and winter 2023 periods. These factors contributed to quarterly average natural gas prices for Texas Eastern M-3 and Houston Ship Channel settling below each of their ten-year averages, despite higher generation from natural gas generation sources.
In the WECC region, above-average temperatures during the quarter resulted in lower demand for heating needs. Natural gas storage levels in the Mountain and Pacific regions continue to increase due to higher natural gas production. These factors contributed to Sumas quarterly average natural gas prices settling below prior year levels.
52
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
PJM. The average settled market prices for the three months ended June 30 were:
| 2023 | 2022 | ||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 35.40 | $ | 93.27 | |||||||
| PJM PL Zone Day Ahead Peak - $/MWh | 25.97 | 78.39 | |||||||||
| PJM BGE Zone Day Ahead Peak - $/MWh | 42.70 | 109.07 | |||||||||
| Texas Eastern M-3 - $/MMBtu | 1.50 | 6.78 | |||||||||
The average January and February forward market prices as of June 30 were:
| 2023 | 2022 | ||||||||||
| 2024 PJM West Hub Day Ahead Peak - $/MWh | $ | 66.89 | $ | 94.87 | |||||||
| 2025 PJM West Hub Day Ahead Peak - $/MWh | 70.86 | 89.38 | |||||||||
| 2024 Texas Eastern M-3 - $/MMBtu | 7.21 | 10.64 | |||||||||
| 2025 Texas Eastern M-3 - $/MMBtu | 7.51 | 8.85 | |||||||||
In PJM, the reduced demand resulting from the mild temperatures along with lower natural gas prices contributed to the PJM West Hub Day Ahead Peak quarter average settled prices declining approximately 62% since the prior year quarter.
ERCOT. The average settled market prices for the three months ended June 30 were:
| 2023 | 2022 | ||||||||||
| ERCOT South Hub Day Ahead Peak - $/MWh | $ | 58.65 | $ | 84.51 | |||||||
ERCOT South Hub Day Ahead Spark Spreads - $/MWh(a) | 44.90 | 34.33 | |||||||||
| Houston Ship Channel - $/MMBtu | 1.96 | 7.17 | |||||||||
__________________
(a)Spark Spreads are computed based on a heat rate of 7 MMBtu/MWh.
The average July and August forward market prices as of June 30 were:
| 2023 | 2022 | ||||||||||
2023 ERCOT South Hub Real Time Spark Spreads - $/MWh (a) | $ | 99.55 | $ | 51.10 | |||||||
2024 ERCOT South Hub Real Time Spark Spreads - $/MWh (a) | 61.80 | 39.73 | |||||||||
2025 ERCOT South Hub Real Time Spark Spreads - $/MWh (a) | 49.35 | 36.24 | |||||||||
__________________
(a)Spark Spreads are computed based on a heat rate of 7 MMBtu/MWh.
In ERCOT, due to reduced demand resulting from the milder temperatures and lower natural gas prices, the ERCOT South Hub Day Ahead Peak quarter average settled prices declined approximately 30% compared to the prior year quarter.
The ERCOT South Hub 2024 and 2025 July and August average on-peak forward spark spreads prices increased by approximately 56% and 36%, respectively, since prior year quarter.
WECC. The average settled market prices for the three months ended June 30 were:
| 2023 | 2022 | ||||||||||
| Mid-Columbia Day Ahead Peak - $/MWh | $ | 57.43 | $ | 58.33 | |||||||
| Sumas - $/MMBtu | 2.45 | 6.87 | |||||||||
53
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The average third quarter forward market prices as of June 30 were:
| 2023 | 2022 | ||||||||||
| 2023 Mid-Columbia Day Ahead Peak - $/MWh | $ | 173.51 | $ | 129.87 | |||||||
| 2024 Mid-Columbia Day Ahead Peak - $/MWh | 170.06 | 115.69 | |||||||||
| 2025 Mid-Columbia Day Ahead Peak - $/MWh | 159.48 | 98.70 | |||||||||
In WECC, the Mid-Columbia Day Ahead Peak quarter average settled prices remained relatively flat since prior year quarter.
The Mid-Columbia 2024 and 2025 first quarter average on-peak forward prices increased by approximately 47% and 62%, respectively, since prior year quarter.
Capacity Market
Approximately 84% of our generation capacity is located in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, ISO demand forecasts and reserve margin targets and adjustments to PJM MSOC as determined by the PJM IMM.
See “—Capacity Prices” below for additional information on capacity prices and see Note 12 in Notes to the Interim Financial Statements for additional information on the PJM RPM and other PJM matters.
Capacity Prices. The following table displays the PJM Base Residual Auction’s cleared capacity prices for the markets and zones in which we primarily operate as of June 30, 2023:
| 2021/2022 | 2022/2023 | 2023/2024 | 2024/2025 | ||||||||||||||||||||
PJM Capacity Performance ($/MW-day) (a) | |||||||||||||||||||||||
| MAAC | $ | 140.00 | $ | 95.79 | $ | 49.49 | $ | 49.49 | |||||||||||||||
| PPL | 140.00 | 95.79 | 49.49 | 49.49 | |||||||||||||||||||
| BGE | 200.30 | 126.50 | 69.95 | 73.00 | |||||||||||||||||||
| EMAAC | 165.73 | 97.86 | 49.49 | 54.95 | |||||||||||||||||||
| PSEG | 204.29 | 97.86 | 49.49 | 54.95 | |||||||||||||||||||
| PS North | 204.29 | 97.86 | 49.49 | 54.95 | |||||||||||||||||||
__________________
(a)Displayed prices are from the applicable market publications.
Seasonality/Scheduled Maintenance
The demand for and market prices of electricity and natural gas are affected by weather. As a result, our operating results in the future may fluctuate substantially on a seasonal basis. For example, a lack of sustained cold weather in the Mid-Atlantic region may suppress regional natural gas prices and reduce our future capacity and energy revenues. Alternatively, above-average temperatures in the summer tend to increase summer cooling electricity demand, energy prices and revenues, and below-average temperatures in the winter tend to increase winter heating electricity demand, energy prices and revenues. Inversely, the milder weather during spring and fall tend to decrease the need for both cooling electricity demand and heating electricity demand. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region and during the summer in Texas.
We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance
54
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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. Susquehanna Unit 2 entered its spring refueling outage on March 20, 2023 and successfully completed the outage on April 24, 2023.
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 included elsewhere in the prospectus. Our financial results for the period from January 1 through May 17, 2023 and for the six-month period from January 1 through June 30, 2022 are referred to as the “Predecessor” period. Our financial results for the period from May 18 through June 30, 2023 are referred to as the “Successor” period. The operating results of May 18 through June 30, 2023 cannot be adequately compared against any of the previous periods reported in the Interim Financial Statements or Annual Financial Statements. Our results of operations as reported in the Interim Financial Statements and Annual Financial Statements are prepared in accordance with GAAP.
55
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Results for the period from May 18 through June 30, 2023, the period from January 1 through May 17, 2023 and the six months ended June 30, 2022
The following table and subsequent sections display the results of operations for the Predecessor and Successor periods:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Capacity revenues | $ | 26 | $ | 108 | $ | 247 | ||||||||||||||
| Energy and other revenues | 188 | 1,042 | 657 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 87 | 60 | 184 | |||||||||||||||||
Operating Revenues | 301 | 1,210 | 1,088 | |||||||||||||||||
| Energy Expenses | ||||||||||||||||||||
| Fuel and energy purchases | (57) | (176) | (417) | |||||||||||||||||
| Nuclear fuel amortization | (25) | (33) | (47) | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (46) | (123) | 22 | |||||||||||||||||
Total Energy Expenses | (128) | (332) | (442) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (69) | (285) | (317) | |||||||||||||||||
| General and administrative | (18) | (51) | (59) | |||||||||||||||||
| Depreciation, amortization and accretion | (28) | (200) | (270) | |||||||||||||||||
| Impairments | — | (381) | — | |||||||||||||||||
| Operational restructuring | — | — | (447) | |||||||||||||||||
| Other operating income (expense), net | (3) | (37) | (17) | |||||||||||||||||
Operating Income (Loss) | 55 | (76) | (464) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 39 | 57 | (191) | |||||||||||||||||
| Interest expense and other finance charges | (33) | (163) | (172) | |||||||||||||||||
| Reorganization income (expense), net | — | 799 | (331) | |||||||||||||||||
| Other non-operating income (expense), net | (11) | 60 | (44) | |||||||||||||||||
Income (Loss) Before Income Taxes | 50 | 677 | (1,202) | |||||||||||||||||
| Income tax benefit (expense) | (19) | (212) | 48 | |||||||||||||||||
Net Income (Loss) | 31 | 465 | (1,154) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 2 | (14) | — | |||||||||||||||||
Net Income (Loss) Attributable to Members | $ | 29 | $ | 479 | $ | (1,154) | ||||||||||||||
Successor Period — May 18, 2023 through June 30, 2023
Net income totaled $31 million for the period of May 18, 2023 through June 30, 2023. Results were driven by the following:
•Capacity Revenues totaled $26 million for the 2023 Successor period, which were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $131 million for the 2023 Successor period. “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. Other revenues relate to Bitcoin operations of
56
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Nautilus that commenced operations in February 2023. Fuel and energy purchases includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases. Activity in this period included $136 million in third-party wholesale electricity sales and ancillary revenues, coupled with $17 million in net realized gains from hedging activities and $15 million in other revenue; partially offset by $37 million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $41 million of net gains for the 2023 Successor period, which was comprised of unrealized gains from hedging activities reflecting a decrease in forward power prices and a reversal of previously recorded unrealized losses on settled positions. Unrealized gains (losses) on derivatives instruments result from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” on the Consolidated Statements of Operations. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities.
•Nuclear Fuel Amortization totaled $25 million for the 2023 Successor period and was related to the amortization of nuclear fuel costs that were previously capitalized to property, plant and equipment. Activity in this period included $14 million of additional amortization related to certain nuclear contracts as a result of fair value adjustments.
•Operation, Maintenance, and Development totaled $(69) million for the 2023 Successor period. This consists of generation facility operating costs. Such costs include salary and benefit costs for generation-facility employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs and certain materials and supplies.
•Depreciation, Amortization and Accretion totaled $28 million for the 2023 Successor period. This consists of depreciation of long-lived property, plant and equipment, and accretion related to AROs. The 2023 Successor period reflects the effect of fair value adjustments made to property, plant and equipment and AROs upon emergence from Restructuring.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $39 million for the 2023 Successor period and was related to realized and unrealized gains (losses) that occurred in Talen’s NDT fund. The activity for the 2023 Successor period was driven by unrealized gains on equity securities. See Notes 9 and 14 in Notes to the Interim Financial Statements for additional information on the NDT.
•Interest Expense and Other Finance Charges totaled $33 million for the 2023 Successor period and primarily consisted of interest expense incurred on the Secured Notes, Term Loans and LMBE-MC TLB.
•Income Tax Benefit (Expense) totaled $(19) million for the 2023 Successor period and primarily related to federal/state income taxes, nuclear decommissioning trust taxes and changes in the valuation allowance. See Note 7 in Notes to the Interim Financial Statements for additional information.
Predecessor Period — January 1, 2023 through May 17, 2023
Net income totaled $465 million for the period of January 1, 2023 through May 17, 2023. Results were driven by:
•Capacity Revenues totaled $108 million for the 2023 Predecessor period and were primarily 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 extreme weather event.
•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $866 million for the 2023 Predecessor period and consisted of $343 million in third-party wholesale electricity sales and ancillary revenues and $637 million in net realized gains from hedging activities and $27 million in other revenue, partially offset by $141 million in fuel and purchased power costs. “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the
57
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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. Other revenues relate to Bitcoin operations of Nautilus that commenced operations in February 2023. Fuel and energy purchases includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
•Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million for the 2023 Predecessor period and was comprised of unrealized losses from hedging activities reflecting a reversal of previously recorded unrealized gains on settled positions, partially offset by unrealized gains resulting from decreases in forward power prices. Unrealized gains (losses) on derivatives instruments result from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” on the Consolidated Statements of Operations. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities.
•Nuclear Fuel Amortization totaled $33 million for the 2023 Predecessor period and was related to the amortization of nuclear fuel costs that were previously capitalized to property, plant and equipment.
•Operation, Maintenance, and Development totaled $(285) million for the 2023 Predecessor period. This consists of generation facility operating costs. Such costs include salary and benefit costs for generation-facility 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 for the 2023 Predecessor period. This consisted of depreciation of long-lived property, plant and equipment, intangibles and accretion related to AROs. The 2023 Predecessor period was impacted by new depreciation rates related to a change in useful lives for the generation facilities.
•Other Operating Income (Expense), net, totaled $(37) million for the 2023 Predecessor period, reflecting fuel inventory net realizable value adjustment expense. See Note 8 in Notes to the Interim Financial Statements for additional information.
•Reorganization Income (Expense), net, totaled $799 million for the 2023 Predecessor period, primarily due to the $1,459 million gain on debt discharge recognized upon Emergence partially offset by a $460 million loss on revaluation adjustments. See Note 4 in Notes to the Interim Financial Statements for additional information.
•Impairments totaled $381 million in the 2023 Predecessor period. The majority of the balance consisted of the assessment of Brandon Shores asset group recoverability associated with a decision to deactivate electric generation at Brandon Shores on June 1, 2025. Other impairment activities are comprised of immaterial items. See Note 10 in Notes to the Interim Financial Statements for additional information on impairments.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, was $57 million for the 2023 Predecessor period and was related to realized and unrealized gains (losses) that occurred in Talen’s NDT fund. The activity in the 2023 Successor period was driven by realized and unrealized gains on equity securities. See Notes 9 and 14 in Notes to the Interim Financial Statements for additional information on the NDT.
•Interest Expense and Other Finance Charges totaled $163 million for the 2023 Predecessor period and primarily consisted of interest expense incurred on the Prepetition Secured Notes, Prepetition RCF, Prepetition TLB, LMBE-MC TLB and certain LC fees.
•Other Non-operating Income (Expense), net, totaled $60 million, primarily due to non-recurring sales during the 2023 Predecessor period. See Note 21 in Notes to the Interim Financial Statements for additional information on the sales.
58
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
•Income Tax Benefit (Expense) totaled $(212) million for the 2023 Predecessor period and was primarily related to federal/state income taxes, reorganization adjustments and changes in the valuation allowance. See Note 7 in Notes to the Interim Financial Statements for additional information.
Predecessor Period — Six Months Ended June 30, 2022
Net loss totaled $1,154 million for the period of January 1, 2022 through June 30, 2022. Results were driven by:
•Capacity Revenues totaled $247 million for the 2022 Predecessor period and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2021/2022 delivery period.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $240 million for the 2022 Predecessor period and consisted of $1,123 million in third-party wholesale electricity sales and ancillary revenues, partially offset by $490 million in fuel and purchased power costs, $236 million in net realized losses from hedging activities, and $157 million in losses incurred on the termination of certain outstanding economic hedges. “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. Fuel and energy purchases includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
•Unrealized Gain (Loss) on Derivative Instruments totaled $206 million of net gains for the 2022 Predecessor period, which was comprised of unrealized gains from hedging activities reflecting a reversal of previously recorded unrealized losses on settled positions, partially offset by unrealized losses incurred as a result of increases in forward power prices. Unrealized gains (losses) on derivatives instruments result from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” on the Consolidated Statements of Operations. We evaluate them collectively because it represents the changes in fair value of Talen’s economic hedging activities.
•Nuclear Fuel Amortization totaled $47 million for the 2022 Predecessor period and was related to the amortization of nuclear fuel costs that were previously capitalized to property, plant and equipment.
•Operation, Maintenance, and Development totaled $(317) million for the 2022 Predecessor period. This consists of generation facility operating costs. Such costs include salary and benefit costs for generation-facility employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs and certain materials and supplies.
•Depreciation, Amortization and Accretion totaled $270 million for the 2022 Predecessor period and consisted of depreciation of long-lived property, plant and equipment, intangibles and accretion related to AROs. The 2022 Predecessor period was impacted by new rates related to the change in useful lives for the generation facilities.
•Operational Restructuring totaled $447 million for the 2022 Predecessor period consisting of a charge recognized in the second quarter of 2022 related to Talen Energy Marketing retail power contracts that were rejected in connection with the Restructuring. See Note 3 in Notes to the Interim Financial Statements for additional information on the Restructuring.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $(191) million for the 2022 Predecessor period and was related to realized and unrealized gains (losses) that occur in Talen’s NDT fund. The activity during the 2022 Predecessor period was driven by unrealized losses on equity securities, net of realized gains. See Notes 9 and 14 in Notes to the Interim Financial Statements for additional information on the NDT.
59
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
•Interest Expense and Other Finance Charges totaled $172 million for the 2022 Predecessor period and primarily consisted of interest expense incurred on the Prepetition Unsecured Notes, Prepetition Secured Notes, Prepetition RCF, Prepetition TLB, LMBE-MC TLB and certain LC fees.
•Reorganization Income (Expense), net, totaled $(331) million for the 2022 Predecessor period and primarily consisted of losses on debt acceleration and financing and professional fees related to the Restructuring.
•Other Non-operating Income (Expense), net, totaled $(44) million for the 2022 Predecessor period due to non-recurring professional fees incurred related to liability and other management initiatives.
•Income Tax Benefit (Expense) totaled $48 million for the 2022 Predecessor period and was related to federal/state income taxes, nuclear decommissioning trust taxes and changes in the valuation allowance. See Note 7 in Notes to the Interim Financial Statements for additional information.
Predecessor Period — Comparison of the Years Ended December 31, 2022, 2021 and 2020
In the comparative tables and subsequent explanations below, increases in revenue and income or decreases in expense are favorable variances and are displayed without brackets. Decreases in revenue and income or increases in
60
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
expense are unfavorable variances and are shown with brackets. The following table and subsequent sections display the results of operations and the changes between the years ended December 31:
| Predecessor | |||||||||||||||||||||||||||||
| 2022 | 2021 | 2020 | 2022 vs 2021 Change | 2021 vs 2020 Change | |||||||||||||||||||||||||
| Capacity revenues | $ | 377 | $ | 444 | $ | 315 | $ | (67) | $ | 129 | |||||||||||||||||||
| Energy and other revenues | 2,035 | 1,331 | 1,480 | 704 | (149) | ||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 677 | (847) | (69) | 1,524 | (778) | ||||||||||||||||||||||||
Operating Revenues | 3,089 | 928 | 1,726 | 2,161 | (798) | ||||||||||||||||||||||||
| Energy Expenses | |||||||||||||||||||||||||||||
| Fuel and energy purchases | (938) | (856) | (649) | (82) | (207) | ||||||||||||||||||||||||
| Nuclear fuel amortization | (94) | (96) | (106) | 2 | 10 | ||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (52) | 135 | 36 | (187) | 99 | ||||||||||||||||||||||||
Total Energy Expenses | (1,084) | (817) | (719) | (267) | (98) | ||||||||||||||||||||||||
| — | |||||||||||||||||||||||||||||
| Operating Expenses | |||||||||||||||||||||||||||||
| Operation, maintenance and development | (610) | (584) | (595) | (26) | 11 | ||||||||||||||||||||||||
| General and administrative | (106) | (88) | (82) | (18) | (6) | ||||||||||||||||||||||||
| Depreciation, amortization and accretion | (520) | (524) | (452) | 4 | (72) | ||||||||||||||||||||||||
| Operational restructuring | (488) | — | — | (488) | — | ||||||||||||||||||||||||
| Impairments | — | — | (681) | — | 681 | ||||||||||||||||||||||||
| Other operating income (expense), net | (40) | (15) | 87 | (25) | (102) | ||||||||||||||||||||||||
Operating Income (Loss) | 241 | (1,100) | (716) | 1,341 | (384) | ||||||||||||||||||||||||
| Interest expense and other finance charges | (359) | (325) | (363) | (34) | 38 | ||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | (184) | 196 | 172 | (380) | 24 | ||||||||||||||||||||||||
| Consolidation of subsidiary gain (loss) | (170) | — | — | (170) | — | ||||||||||||||||||||||||
| Reorganization income (expense), net | (812) | — | — | (812) | — | ||||||||||||||||||||||||
| Deconsolidation of subsidiary gain (loss), net | — | — | 71 | — | (71) | ||||||||||||||||||||||||
| Other non-operating income (expense), net | (44) | (48) | (9) | 4 | (39) | ||||||||||||||||||||||||
Income (Loss) Before Income Taxes | (1,328) | (1,277) | (845) | (51) | (432) | ||||||||||||||||||||||||
| Income tax benefit (expense) | 35 | 300 | 181 | (265) | 119 | ||||||||||||||||||||||||
Net Income (Loss) | (1,293) | (977) | (664) | (316) | (313) | ||||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | (4) | — | — | (4) | — | ||||||||||||||||||||||||
Net Income (Loss) Attributable to Members | $ | (1,289) | $ | (977) | $ | (664) | $ | (312) | $ | (313) | |||||||||||||||||||
61
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The following variance explanations are based on the market areas in which our generation fleet operates and the manner in which our senior management team reviews our financial and operating performance and allocates resources.
Predecessor Period — Comparison of the Years Ended December 31, 2022 and 2021
Operating Revenues, net of Total Energy Expenses. There was $1.9 billion overall favorable increase, which was comprised of changes in “Capacity revenue,” “Energy Revenues, net of Fuel and Energy Purchases,” “Unrealized Gains (Losses) on Derivative Instruments” and “Nuclear fuel amortization”:
| Change | ||||||||
| Capacity Revenue | ||||||||
| $ | (125) | Unfavorable decrease primarily due to lower cleared capacity prices and less MWs compared to the 2021/2022 PJM Capacity Year. See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Market” above for information on capacity prices. | ||||||
| (33) | Unfavorable decrease due to a net capacity penalty related to the 2022 Winter Storm Elliot extreme weather event. See “—Factors Affecting Our Financial Condition and Results of Operations—Unusual Market Events—Winter Storm Elliott” for additional information. | |||||||
| 91 | Favorable increase primarily due to higher cleared capacity prices and additional MWs for the 2021/2022 PJM Capacity Year. See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Market” above for information on capacity prices. | |||||||
| (67) | Total Capacity Revenue | |||||||
Energy Revenues, net of Fuel and Energy Purchases | ||||||||
| 1,058 | Favorable increase in margin associated with electric generation primarily due to: (i) higher around-the-clock settled power prices received at Susquehanna; (ii) higher power prices received at our fossil-fueled generation facilities; (iii) higher realized Spark Spread received; partially offset by (iv) decreased generation volumes at our fossil-fueled generation portfolio and generation facilities | |||||||
| 78 | Favorable increase due to the losses incurred to the 2021 Winter Storm Uri extreme winter weather event | |||||||
| (357) | Unfavorable decrease in hedge results primarily due to higher settled day ahead on-peak power prices and higher realized Spark Spreads, excluding the price effects of Winter Storm Uri | |||||||
| (124) | Unfavorable decrease in hedge results due to the termination of certain outstanding economic hedges between Talen Energy Marketing and a commercial counterparty that were scheduled to be priced and deliver from April 2022 through December 2022 | |||||||
| (33) | Unfavorable decrease in hedge results due to losses incurred on early terminated commodity contract agreements | |||||||
| 622 | Total Energy Revenues, net of Fuel and Energy Purchases | |||||||
| Unrealized Gains (Losses) on Derivative Instruments | ||||||||
| 474 | Favorable increase primarily due to the “roll-off” of $392 million in loss positions during 2022 compared to the “roll-off” of $(83) million in gain positions during 2021 | |||||||
| 457 | Favorable increase primarily due to newly executed trades transacted in 2022 which resulted in gain positions compared to trades transacted in 2021 which resulted in loss positions | |||||||
| 243 | Favorable increase primarily due to the “roll-off” of premium losses in 2022 compared to the “roll-off” of premium gains in 2021 | |||||||
| 163 | Favorable increase primarily due to lower losses in 2022 compared to 2021 on positions existing in both periods | |||||||
| 1,337 | Total Unrealized Gains (Losses) on Derivative Instruments | |||||||
| 2 | Nuclear Fuel Amortization | |||||||
| $ | 1,894 | Total | ||||||
“Energy revenues” and “Fuel and energy purchases” are evaluated collectively as Energy Revenues, net of Fuel and Energy Purchases because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand.
62
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Unrealized gains (losses) on derivatives are presented separately as both revenues and expenses within “Operating Revenues, net of Total Energy Expenses” on the Consolidated Statements of Operations. We evaluate them collectively because it represents the changes in fair value of Talen’s economic hedging activities. See Notes 4 and 20 in Notes to the Annual Financial Statements for additional information on unrealized gains and losses associated with commodity derivatives.
Operational Restructuring. There was a $(488) million charge recognized in 2022 due to: a $(453) million charge related to Talen Energy Marketing retail power contracts that were rejected in connection with the Restructuring and $(35) million of charges for long-term service agreements that were rejected in connection with the Restructuring. These charges are management’s estimates of damages for allowed claims from counterparties and were approved by the Bankruptcy Court. See Note 3 in Notes to the Annual Financial Statements for additional information on the Restructuring.
Nuclear Decommissioning Trust Funds Gain (Loss), net. There was a $380 million unfavorable increase in expense due to a realized loss of $83 million as a result of asset portfolio re-balancing activity. Inflation, geopolitics and rising interest rates weighed on the equity markets in the 2022 period resulting in an unrealized loss of $297 million. See Notes 13 and 20 in Notes to the Annual Financial Statements for additional information on the NDT.
Consolidation of Subsidiary Gain (Loss), net. $(170) million of unfavorable losses were recognized from the consolidation of Cumulus Digital Holdings due to a change of control. See Note 12 in Notes to the Annual Financial Statements for additional information.
Reorganization income (expense), net. There was an $(812) million unfavorable increase to losses due to:
| Change | ||||||||
| (310) | Backstop Premium. See “Backstop Commitment Letter” in Note 3 in Notes to the Annual Financial Statements for additional information. | |||||||
| (210) | Restructuring professional fees | |||||||
| (183) | Make-whole premiums and accrued interest on certain indebtedness. See “Reorganization Income (Expense), net” Note 3 in Notes to the Annual Financial Statements for additional information. | |||||||
| (70) | Professional fees incurred to obtain the DIP Facilities | |||||||
| (30) | Write-off of the aggregate prepetition debt issuance cost carrying value | |||||||
| (9) | Other | |||||||
| $ | (812) | Total | ||||||
See Note 3 in Notes to the Annual Financial Statements for additional information on the Restructuring.
Income Tax Benefit (Expense). There was a $(265) million unfavorable decrease in corporate tax benefit (expense), primarily due to:
| Change | ||||||||
| $ | (198) | Increase in valuation allowance expense | ||||||
| (94) | Increase in unfavorable permanent differences | |||||||
| (53) | Decrease in federal and state tax benefit due to change in pre-tax book income | |||||||
| 56 | Decrease in Nuclear Decommissioning Trust net tax expense | |||||||
| 24 | Remeasurement of deferred taxes related to change in Pennsylvania state rate | |||||||
| $ | (265) | Total | ||||||
See Note 6 in Notes to the Annual Financial Statements for additional information.
63
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Predecessor Period — Comparison of the Years Ended December 31, 2021 and 2020
Operating Revenues, net of Total Energy Expenses. There was an $(896) million overall unfavorable change, which was comprised of changes in “Capacity revenue,” “Energy Revenues, net of Fuel and Energy Purchases,” “Unrealized Gains and Losses on Derivative Instruments” and “Nuclear fuel amortization”:
| Change | ||||||||
| Capacity Revenue | ||||||||
| $ | 127 | Favorable increase primarily due to higher cleared capacity prices and additional volume of cleared MWs compared to the 2020/2021 PJM Capacity Year. See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Market—Capacity Prices” for additional information on capacity prices. | ||||||
| 2 | Other | |||||||
| 129 | Total Capacity Revenue | |||||||
Energy Revenues, net of Fuel and Energy Purchases | ||||||||
| (580) | Unfavorable decrease in hedge results primarily due to higher settled: (i) day ahead on-peak power prices; and (ii) day ahead Spark Spreads | |||||||
| (78) | Unfavorable decrease due to the nonrecurring extreme winter weather event during Winter Storm Uri. See “—Factors Affecting Our Financial Condition and Results of Operations—Unusual Market Events—Winter Storm Uri” for additional information. | |||||||
| 277 | Favorable increase in margin associated with electric generation primarily due to: (i) higher around-the-clock settled power prices received at Susquehanna; (ii) higher Capacity Factors of our fossil-fueled generation portfolio in 2021; and (iii) increased generation volumes due to higher operational availability at Lower Mt. Bethel. | |||||||
| 25 | Favorable increase primarily due to lower contracted amendment fees incurred in 2021. During 2020, fees were incurred to reduce contracted coal deliveries as Talen reached its storage capacity limits due to the effects of warm weather and low Capacity Factors. | |||||||
| (356) | Total Energy Revenues, net of Fuel and Energy Purchases | |||||||
| Unrealized Gains (Losses) on Derivative Instruments | ||||||||
| (679) | Unfavorable decrease in unrealized hedge results are primarily due to the effects of: (i) higher forward day-ahead on-peak prices for the 2022/2023 delivery years; and (ii) higher forward summer 2022/2023 Spark Spreads | |||||||
| (679) | Total Unrealized Gains (Losses) on Derivative Instruments | |||||||
| 10 | Nuclear Fuel Amortization. | |||||||
| $ | (896) | Total | ||||||
“Energy revenues” and “Fuel and energy purchases” are evaluated collectively as Energy Revenues, net of Fuel and Energy Purchases, because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand.
Unrealized gains (losses) on derivatives are presented separately as both revenues and expenses within “Operating Revenues, net of Total Energy Expenses” presented in the Audited Consolidated Statements of Operations. We evaluate them collectively because it represents the changes in fair value of Talen’s economic hedging activities. See Notes 4 and 20 in Notes to the Annual Financial Statements for additional information on unrealized gains and losses associated with commodity derivatives.
Depreciation, Amortization and Accretion. There was a $(72) million unfavorable increase due to higher depreciation expense at Brandon Shores, Newark Bay and Montour for accelerated retirement dates. See “Property, Plant and Equipment” of Note 2 in Notes to the Annual Financial Statements for additional information on retirement date revisions.
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Impairments. There was a $681 million favorable decrease due to the aggregation non-cash impairment charge of property, plant and equipment in 2020 for Montour, Keystone and Conemaugh and other assets. See Note 14 in Notes to the Annual Financial Statements for additional information on impairments.
Other Operating Income (Expense), net. There was a $(102) million unfavorable decrease in income due to $144 million gain on sale of IEC in January 2020 partially offset by $29 million lower non-cash net realizable value and obsolescence fuel charges between periods. See Note 7 in Notes to the Annual Financial Statements for additional information.
Deconsolidation of Subsidiary Gain (Loss), net. There was a $(71) million unfavorable decrease to income due to a $131 million (gain) and $60 million loss related to the non-cash gain due to the derecognition of NorthEast Gas Gen’s assets and liabilities and the recognition of a non-material investment in NorthEast Gas Gen in April 2020. See Note 19 in Notes to the Annual Financial Statements for additional information.
Income Tax Benefit (Expense). There was a $119 million favorable increase to tax benefit primarily due to:
| Change | ||||||||
| $ | 139 | Increase in pre-tax book loss | ||||||
| (20) | State deferred tax rate change | |||||||
| $ | 119 | Total | ||||||
See Note 6 in Notes to the Annual Financial Statements for additional information.
Liquidity and Capital Resources
Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our 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 debt issuance proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging 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. Importantly, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service requirements. See “Business—Our Hedging Strategy” for an overview of our hedging strategy.
We are 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 requirements. 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 Financing” 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 “—Significant
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Confidential Treatment Requested by Talen Energy Corporation
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Transactions and Developments” above for additional information on the Restructuring and related financings. After funding of claims, which were paid pursuant to the Plan of Reorganization, Talen had unrestricted cash on hand of $127 million at June 30, 2023 (Successor).
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, 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 2.25 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. The Cumulus Digital Credit Agreement also restricts the ability of Cumulus Digital Holdings to pay TES (and, consequently, TEC) dividends or distributions, subject to certain exceptions, which include customary tax distributions. See “Risk Factors—Risks Related to Ownership of Our Common Stock—TEC is a holding company and its ability to obtain funds from its subsidiaries is structurally subordinated to existing and future liabilities and preferred equity of its subsidiaries, and the Indenture and the agreements governing the Credit Facilities contain certain restrictions with respect to TES’s ability to distribute 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 19 in Notes to the Interim Financial Statements for additional information regarding various liquidity topics contained below.
Talen Liquidity
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| RCF | $ | 700 | $ | — | ||||||||||
| Unrestricted cash and cash equivalents | 127 | 724 | ||||||||||||
DIP RCF (a) | — | 267 | ||||||||||||
Available liquidity | $ | 827 | $ | 991 | ||||||||||
__________________
(a)Facility was extinguished post-Emergence in May 2023. See Note 13 in Notes to the Interim Financial Statements for additional information.
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 | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Outstanding surety bonds | $ | 240 | $ | 248 | ||||||||||
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Pursuant to 17 C.F.R. Section 200.83
TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including, but not limited to, environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.
Forecasted Uses of Cash
Capital Expenditures 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.
| 2023 | 2024 | ||||||||||
| Generation facilities | |||||||||||
| Nuclear fuel | $ | 95 | $ | 90 | |||||||
| PJM nuclear generation facility | 45 | 50 | |||||||||
| PJM fossil generation facilities | 55 | 50 | |||||||||
| ERCOT and WECC | 20 | 30 | |||||||||
Total generation facilities (a) | $ | 215 | $ | 220 | |||||||
| Investments | |||||||||||
Fuel conversion (a)(b) | 65 | — | |||||||||
Development and other (c) | 25 | 10 | |||||||||
Total | $ | 305 | $ | 230 | |||||||
__________________
(a)Aggregate interest expected to be capitalized is $8 million in 2023 and $2 million in 2024.
(b)See “—Montour Coal-to-Natural Gas Conversion Project” below for information.
(c)Primarily represents Cumulus Data funding by Talen Energy Supply. See “—Cumulus Data Funding” below for additional information.
Montour Coal-to-Natural Gas Conversion Project. In connection with Talen’s plans to cease coal operations at wholly-owned generation facilities, Talen spent approximately $90 million in capital expenditures to convert the generation fuel for Montour from coal to natural gas or dual-fuel, completing the conversion in August 2023. Montour Unit 1 is now dispatchable on gas, while Unit 2 is dispatchable on either coal or gas.
Cumulus Data Funding. In connection with the development activities of Cumulus Data, Talen Energy Supply, at its discretion, provides incremental funding for Cumulus Data for its development activities. During 2023, Talen Energy Supply has funded an aggregate $15 million in Cumulus Data. As of June 30, 2023, Cumulus Data expects to require an additional $5 million of funding from Talen Energy Supply to complete electrical infrastructure. 2024 funding requirements for Cumulus Data include a non-material amount for non-electrical infrastructure. Aggregate capital expenditures for Cumulus Data, funded by cash held by Cumulus Data and such additional funding from Talen Energy Supply, is expected to be approximately $60 million for 2023 and $10 million for 2024. See Note 12 in Notes to the Annual Financial Statements for additional information on Cumulus Data.
Projected ARO Cash Flows
We have significant legal obligations related to our ARO and accrued environmental liabilities. As part of the Restructuring, ARO and accrued environmental liabilities were adjusted to fair value, resulting in a new credit-adjusted risk free rate of 8-12% based on timing of cash flows for each underlying obligation.
Our undiscounted projected spending on AROs and accrued environmental liabilities from 2023 through 2028 is presented in the table below. The majority of the estimated spend in that time period is related to ash impoundments
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at Colstrip and Brunner Island. Projections are subject to revision based on changes in estimated inflation rates, changes in the estimated timing of settling AROs and escalating retirement costs.
| (in millions) | 2023 | 2024 | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||||||
| Expected AROs and accrued environmental liabilities | $ | 14 | $ | 17 | $ | 41 | $ | 56 | $ | 54 | $ | 59 | |||||||||||||||||||||||
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;
•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.
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| 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 2/9/24 in connection with a repricing transaction | ||||||||||||||||||||||
| TLC (TLC LCF) | May 2030 | Term SOFR | 4.50% per annum applicable margin No amortization | 1.00% to the extent prepaid prior to 11/17/23 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 (letters of credit) | May 2028 | Federal Funds Rate | None | None | ||||||||||||||||||||||
| Bilateral LCF | May 2028 | Prime Rate | None | None | ||||||||||||||||||||||
Credit Agreement
Obligations under the Credit Agreement are guaranteed by the Subsidiary Guarantors and are secured by liens covering substantially all of TES’s (and its restricted subsidiaries’) consolidated assets, rights and properties, subject to certain exceptions. The Credit Agreement also provides for affirmative and negative covenants applicable to TES (and its restricted subsidiaries), including affirmative covenants requiring it to provide financial and other information to the agents under the Credit Agreement and to not change its lines of business, and negative covenants restricting its (and its restricted subsidiaries’) ability to incur additional indebtedness, make investments, dispose of assets, pay dividends, grant liens or take certain other actions, in each case subject to certain exceptions. TES’s ability to borrow under the Credit Agreement is subject to the satisfaction of certain customary conditions precedent. The Credit Agreement also provides for certain customary events of default, including events of default resulting from non-payment of principal, interest or fees when due, material breaches of representations and warranties, material breaches of covenants in the Credit Agreement or ancillary loan documents, cross-defaults under other material agreements or instruments and the entry of material judgments against TES. 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 $50 million) exceed 35% of the revolving commitments), the Credit Agreement includes a covenant that requires the 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 quarterly step-ups to 4.25 to 1.00 as of June 30, 2024 and
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Confidential Treatment Requested by Talen Energy Corporation
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thereafter. TES has a right to cure a breach of the financial covenant by way of an equity contribution. The financial covenant does not apply to the TLB, the TLC or the TLC LCF.
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 $462 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.
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 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
On May 12, 2023, TES issued $1.2 billion aggregate principal amount of the Secured Notes, which bear interest at 8.625%. 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 mature on June 1, 2030, unless redeemed on an earlier date. The Secured Notes are guaranteed on a senior secured basis by the Subsidiary Guarantors. The secured obligations under the Secured ISDAs were approximately $65 million at June 30, 2023 (Successor).
Secured ISDAs
Talen Energy Marketing is party to the 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 and security interest (which ranks pari passu with the liens securing the Credit Facilities and the Secured Notes) against certain assets in lieu of posting collateral in the form of cash equivalents or LCs.
LMBE-MC Refinancing
In August 2023, we incurred an additional $290 million in aggregate principal amount under the 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 repay in full the $293 million in aggregate principal amount outstanding under the LMBE-MC TLB, following which the LMBE-MC Credit Agreement (including the LMBE-MC TLB and LMBE-MC RCF) was terminated. The outstanding LC issued under the LMBE-MC RCF, which supported debt service reserve requirements under the LMBE-MC TLB, was likewise terminated.
PEDFA Bonds
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, the Secured Notes and the Secured ISDAs. 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 the Subsidiary Guarantors’ other senior unsecured indebtedness, and are effectively subordinated to the secured obligations of the Subsidiary Guarantors, including the Credit Facilities, the Secured Notes and the Secured ISDAs.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
In February 2021, Talen completed a remarketing of (i) $50 million aggregate principal amount of its PEDFA 2009B Bonds and (ii) $80.57 million aggregate principal amount of its PEDFA 2009C Bonds, each of which were issued by the PEDFA on behalf of Talen. Talen received the proceeds from the original issuance of each series of PEDFA Bonds in 2009 pursuant to a separate exempt facilities loan agreement, each of which was amended in connection with the February 2021 remarketing. An unsecured promissory note of Talen corresponding to each series of PEDFA Bonds contains principal, interest and prepayment provisions of the respective series of PEDFA Bonds.
The PEDFA Bonds accrue interest at a variable rate in accordance with the provisions of the trust indentures which is payable monthly. Obligations under the PEDFA 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.
The PEDFA Bonds are subject to customary affirmative and negative covenants appropriate for such indebtedness. The trust indentures governing the PEDFA Bonds do not limit Talen’s ability to incur additional unsecured indebtedness. The PEDFA Bonds also contain customary events of default. If an event of default occurs, the holders of PEDFA Bonds will be entitled to take various actions, including the acceleration of any outstanding amounts due.
Cumulus Digital TLF
The Cumulus Digital Credit Agreement provides for a senior secured delayed draw term loan facility in the aggregate maximum committed principal amount of $175 million. The Cumulus Digital Credit Agreement matures in 2027 and bears interest at a rate of 12.50%. All interest accruing thereunder from July 1, 2022 through June 30, 2023, unless Cumulus Digital elects to pay in cash, will be capitalized as additional principal, i.e. paid-in-kind (“PIK”), and thereafter will be paid in cash.
Obligations under the Cumulus Digital Credit Agreement are guaranteed by Cumulus Digital Holdings and certain of Cumulus Digital’s subsidiaries and are secured by first priority liens and security interests in substantially all the assets of Cumulus Digital and each of its subsidiaries (other than the assets of Nautilus but including a pledge of Cumulus Coin’s equity in Nautilus), subject to customary exceptions.
The Cumulus Digital Credit Agreement contains customary representations and warranties, affirmative covenants, negative covenants and events of default. Notable covenants include limitations on incurrence of liens and additional indebtedness, payment of dividends and asset sales. In March 2023, the Cumulus Digital Credit Agreement 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.
Under the Cumulus Digital Credit Agreement, Talen is obligated to procure LCs to backstop certain of Cumulus Digital’s obligations under the Cumulus Digital Credit Agreement, and has procured two such LCs totaling $50 million in the aggregate (the “Orion Support LCs”). The Orion Support LCs can be drawn upon, among other events: (i) the acceleration of the facility under the Cumulus Digital Credit Agreement due to an event of default or (ii) a bankruptcy of Cumulus Digital. The amount of the Orion Support LCs will be decreased from time to time based on the outstanding principal balance of the Cumulus Digital Credit Agreement. To the extent of any draw under any of the Orion Support LCs, Cumulus Digital Holdings has agreed to issue additional common equity to Talen to reimburse it for the amount drawn. Cumulus Digital has agreed to reimburse Talen for fees associated with the Orion Support LCs with payment of such amounts 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. Talen will have the option to receive payment for the deferred fees in cash payments ratably over the next succeeding 24 months or in additional common units of Cumulus Digital Holdings, subject to certain caps.
Additionally, TEC has 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 will terminate if the principal amount of loans
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Pursuant to 17 C.F.R. Section 200.83
outstanding is reduced to $50 million or less. Amounts are not payable under the guarantee until all available amounts under the Orion Support LCs have been drawn.
Cash Flow Activities
The net cash provided by (used in) operating, investing and financing activities for the Successor period from May 18, 2023 through June 30, 2023 and the Predecessor period from January 1, 2023 through May 17, 2023 were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Operating activities | $ | (1) | $ | 462 | $ | 24 | ||||||||||||||
| Investing activities | (38) | (157) | (173) | |||||||||||||||||
| Financing activities | — | (539) | 535 | |||||||||||||||||
Successor Period — May 18, 2023 through June 30, 2023
Operating Cash Flows – Cash (used in) operating activities was immaterial.
Investing Cash Flows – Cash (used in) investing activities totaled $(38) million and consisted of capital expenditures.
Capital expenditures (outflows), including those for nuclear fuel, totaled $(34) million and consisted of: $(20) million across the Company for current projects including the Montour gas co-fire project and the Cumulus Data Center Campus; and $(14) million related to nuclear-fuel expenditures as Talen purchased its uranium needs for 2024 and 2025 future during this period.
Financing Cash Flows – Cash provided by financing activities was not material.
Predecessor Period — January 1, 2023 through May 17, 2023
Operating Cash Flows – Cash provided by operating activities totaled $462 million and 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.
Investing Cash Flows – Cash (used in) investing activities totaled $(157) million and consisted of capital expenditures offset by $46 million in proceeds from the sale of non-core assets. See Note 21 in Notes to the Interim Financial Statements for additional information on the sales.
Capital expenditures (outflows), including those for nuclear fuel, totaled $(187) million and consisted of: $(138) million across the Company for current projects including the Montour gas co-fire project, the Cumulus Data Center Campus and Nautilus crypto mining projects and projects at Susquehanna; and $(49) million related to nuclear-fuel expenditures.
Financing Cash Flows – Cash (used in) financing activities totaled $(539) million and consisted of the net effect of issuances and repayments of prepetition debt and make-whole premiums of about $(1.9) billion net cash outflow partially offset by $1.4 billion cash inflow for a contribution from member.
Predecessor Period — Six Months Ended from January 1, 2022 through June 30, 2022
Operating Cash Flows – Cash provided by operating activities totaled $24 million and consisted of cash provided from the operations of the Company and changes in working capital from increases to accounts payable and accrued liabilities due to the Restructuring commencement in May 2022 and increases to ISO and RTO related-accounts receivable.
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Investing Cash Flows – Cash (used in) investing activities totaled $(173) million and consisted of capital expenditures and investments in equity method and preferred equity, primarily in Consolidated Cumulus Digital and its subsidiaries before they became fully consolidated subsidiaries.
Capital expenditures (outflows) totaled $(106) million and consisted of: $(61) million across the Company for current projects including the Montour gas co-fire project and projects at Talen’s nuclear generation facility; and $(45) million related to nuclear-fuel expenditures.
Financing Cash Flows – Cash provided by financing activities totaled $535 million and consisted of the issuance of DIP Facilities net proceeds of $930 million, after discount and debt issuance costs, and partially offset by repayments on the Deferred Capacity Obligation and Inventory Repurchase Obligations of $(341) million.
Predecessor Period — Year Ended December 31, 2022 vs. December 31, 2021
| 2022 | 2021 | 2020 | 2022 vs 2021 Change | 2021 vs 2020 Change | |||||||||||||||||||||||||
| Operating activities | $ | 187 | $ | (294) | $ | 102 | $ | 481 | $ | (396) | |||||||||||||||||||
| Investing activities | (368) | (280) | 11 | (88) | (291) | ||||||||||||||||||||||||
| Financing activities | 426 | 956 | 65 | (530) | 891 | ||||||||||||||||||||||||
Net cash provided by (used in) operating activities.
| Change | ||||||||
| $ | 622 | Higher Energy Revenues, net of Fuel and Energy Purchases between periods | ||||||
| (50) | Increase in cash collateral deposits paid to counterparties | |||||||
| 35 | Overall lower recourse interest payments due to lower aggregate payments on indebtedness that was stayed 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. | |||||||
| (67) | Lower capacity payments between periods (See “—Results of Operations”) | |||||||
| (26) | Lower operation and maintenance expenditures between periods (See “—Results of Operations”) | |||||||
| (33) | Other changes in cash provided by (used in) operating activities | |||||||
| $ | 481 | Total | ||||||
See Note 18 in Notes to the Annual Financial Statements for additional information on the PEDFA remarketing.
Net cash provided by (used in) investing activities.
| Change | ||||||||
| $ | (97) | Higher contributions to equity method and preferred equity investments. See Notes 11 and 12 in Notes to the Annual Financial Statements for additional information on the equity method and preferred equity investments. | ||||||
| (87) | Higher capital expenditures between periods for the Montour natural gas conversion project | |||||||
| (22) | Higher capital expenditures between periods on the renewable, battery and digital infrastructure growth projects | |||||||
| (12) | Lower return of cash from equity method investments between periods | |||||||
| 123 | Increase in cash and restricted cash due to consolidation of affiliate subsidiaries, TRF and Cumulus Digital Holdings | |||||||
| 19 | Lower capital expenditures at generation facilities | |||||||
| (12) | Other changes in cash provided by (used in) investing activities | |||||||
| $ | (88) | Total | ||||||
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
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Confidential Treatment Requested by Talen Energy Corporation
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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. See Note 12 in Notes to the Annual Financial Statements for additional information TES’s equity interests Cumulus Digital Holdings.
Net cash provided by (used in) financing activities.
| Change | ||||||||
| $ | (827) | Proceeds, net of premium paid on Talen Commodity Accordion RCF in 2021 | ||||||
| (337) | Net proceeds and repayments of the Prepetition Deferred Capacity Obligations between periods | |||||||
| (165) | Net proceeds and repayments of the Prepetition Inventory Repurchase Obligations in 2022 | |||||||
| (131) | Proceeds from the issuance of PEDFA Bonds in 2021 | |||||||
| (104) | Payments made on the termination of certain economic hedge contracts | |||||||
| (52) | LMBE-MC 2025 TLB repayments in 2022 | |||||||
| (36) | Higher debt issuance costs between periods | |||||||
| 987 | Proceeds, net of premium paid on DIP TLB in 2022 | |||||||
| 114 | Repayment of 4.6% Senior Notes due December 2021 at maturity | |||||||
| 27 | LMBE-MC 2025 TLB repayments in 2021 | |||||||
| (6) | Other changes in cash flows provided by (used in) financing activities | |||||||
| $ | (530) | Total | ||||||
See Notes 17 and 18 in Notes to the Annual Financial Statements for additional information on revolving and other credit facilities and long-term debt.
Predecessor Period — Year Ended December 31, 2021 vs. December 31, 2020
Net cash provided by (used in) operating activities.
| Change | ||||||||
| $ | (356) | Lower Energy Revenues, net of Fuel and Energy Purchases between periods | ||||||
| (102) | Increase in cash collateral deposits paid to counterparties | |||||||
| (14) | Overall higher recourse interest payments due to higher payments on the Talen 2028 Secured Notes that were issued in the second quarter 2020 | |||||||
| 129 | Higher capacity payments between periods, partially offset by the April 2020 deconsolidation of NorthEast Gas Gen (See “—Results of Operations”) | |||||||
| (53) | Other changes in cash provided by (used in) operating activities | |||||||
| $ | (396) | Total | ||||||
See Notes 17 and 18 in Notes to the Annual Financial Statements for additional information on revolving and other credit facilities and long-term debt.
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Net cash provided by (used in) investing activities.
| Change | ||||||||
| $ | (153) | Proceeds from the sale of IEC in January 2020 | ||||||
| (59) | Higher contributions to equity method and preferred equity investments. See Notes 11 and 12 in Notes to the Annual Financial Statements for additional information on the equity method methods and preferred equity investments. | |||||||
| (34) | Higher capital expenditures between periods on the renewable, battery and digital infrastructure growth projects | |||||||
| (27) | Increase in nuclear fuel expenditures between periods | |||||||
| (28) | Lower casualty insurance proceeds in 2021 compared to 2020 for forced outages at Lower Mt. Bethel and Martins Creek | |||||||
| 10 | Other changes in cash provided by (used in) investing activities | |||||||
| $ | (291) | Total | ||||||
In September 2021, a TES subsidiary sold its ownership interests in Cumulus Data, the company constructing the Cumulus Data Center Campus, to a subsidiary of Cumulus Growth. In the preceding table, capital expenditures from January 2021 through August 2021 by Cumulus Data are displayed as changes on renewable, battery and digital infrastructure growth projects. See Note 12 in Notes to the Annual Financial Statements for additional information on the Cumulus Projects’ equity investments.
Net cash provided by (used in) financing activities.
| Change | ||||||||
| $ | 827 | Proceeds, net of premium paid on Prepetition CAF in 2021 | ||||||
| 161 | Proceeds, net of discount and net of subsequent repayments of $209 million related to Prepetition Deferred Capacity Obligations in 2021 | |||||||
| 131 | Proceeds from the issuance of PEDFA bonds in 2021 | |||||||
| 131 | Repayments of PEDFA bonds in 2020 that were subsequently reissued in 2021 (see above) | |||||||
| 105 | Prepetition RCF net repayments in 2020 | |||||||
| 72 | Prepetition TLB repayments in 2020 | |||||||
| 33 | LMBE-MC TLB repayments in 2020 | |||||||
| (400) | 2028 Prepetition Secured Notes issuance proceeds in 2020 | |||||||
| (114) | Repayment of 2021 Prepetition Unsecured Notes at maturity | |||||||
| (27) | LMBE-MC TLB repayments in 2021 | |||||||
| (15) | Net proceeds from the Prepetition Inventory Repurchase Obligations in 2020 | |||||||
| (14) | Higher debt issuance costs between periods | |||||||
| 1 | Other changes in cash flows provided by (used in) financing activities | |||||||
| $ | 891 | Total | ||||||
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 16 in Notes to the Annual Financial Statements for additional information regarding guarantees.
Quantitative and Qualitative Disclosures About Market Risk
See Note 5 in Notes to our Interim Financial Statements and Note 4 in Notes to the Annual Financial Statements included elsewhere in this prospectus for a description of our market risk.
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Critical Accounting Policies and Estimates
Management’s discussion and analysis of our financial condition and results of operations is based on our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our financial statements requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities at the date of the financial statements, as well as the reported revenue generated and expenses incurred during the reporting periods, as well as related disclosures. Our estimates are based on our historical experience and on various other factors that we believe are reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities and the amount of revenue and expenses that are not readily apparent from other sources. Actual results may differ from these estimates under different assumptions or conditions, and any such differences may be material. We believe that the accounting policies discussed below are critical to understanding our historical and future performance, as these policies relate to the more significant areas involving management’s judgments and estimates.
Financial statements prepared in conformity with GAAP inherently contain the application of appropriate accounting policies and require management to make judgments, estimates and assumptions that affect the carrying values of assets and liabilities, the reported amounts of revenues and expenses and the recognition and disclosures of commitments and contingencies. Relevant historical experience and other various assumptions that are believed to be reasonable form the basis for these judgments, estimates and assumptions. Additionally, certain accounting policies involve judgments and uncertainties 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 changes in estimates. For a more complete discussion of our accounting policies, please see Note 2 to the Interim Financial Statements, as well as the Annual Financial Statements for more information regarding our accounting policies.
Derivative Instruments
Derivative instruments, which assist with commodity-price and interest-rate risk management by our commercial and treasury functions, are presented on our consolidated balance sheet at fair value, either as an asset or liability, and are comprised primarily of commodity contracts and interest rate 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 which 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.
Many derivative contracts economically hedge commodity market prices or interest rates for borrowings, but they do not qualify for, or we do not elect, specialized “hedge accounting.” In these instances, the income effect of a derivative instrument is presented on our consolidated statement of operations. The cumulative realized net gains or losses for commodity contract derivatives that are physical energy sales, hedge our generation and hedge other sale activities are presented within “operating revenues” on our consolidated statements of operations. The cumulative realized net gains or losses for commodity contract derivatives that are physical energy purchases, hedge our fuel costs and emissions costs or other purchase activities are presented within “fuel expenses” on our consolidated statement of operations. 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 expenses,” in a consistent manner with the presentation of its realized net gains or losses. The cumulative net gains or losses for interest rate contracts are presented within “interest expense and other finance charges” on our consolidated statements of operations.
See Note 5 in Notes to the Interim Financial Statements and Note 4 in the Annual Financial Statements for more information on derivative instruments.
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Nuclear Decommissioning Asset Retirement Obligations
We have significant legal obligations associated with Susquehanna Nuclear’ s decommissioning, whose Unit 1 and Unit 2 licenses expire in 2042 and 2044, respectively.
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 several years, or decades, in the future. Additionally, 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. We periodically review ARO carrying values and assess for updates by applying our experience, knowledge and professional judgment to the specific characteristics of the obligation.
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 Interim Financial Statements and Note 15 in the Annual Financial Statements for more 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 at 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 as “other operating income (expense), net” in our consolidated statements of operations in the period in which the impairment determination is made.
See Note 10 in Notes to the Interim Financial Statements and Note 14 in the Annual Financial Statements for information impairments recognized in 2023.
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 statement 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 Interim Financial Statements and Note 21 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 at December 31, 2022.
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, 2022.
| Sensitivity | ||||||||||||||
| Actuarial Assumption | 1% Increase | 1% Decrease | ||||||||||||
| Discount rate | ||||||||||||||
| Postretirement benefit obligation | $ | (127) | $ | 152 | ||||||||||
| Net periodic pension cost | 2 | 1 | ||||||||||||
| Expected return on plan assets | ||||||||||||||
| Net periodic pension cost | $ | (12) | $ | 12 | ||||||||||
Income Taxes
Significant management estimates and judgment are involved to determine the provision for income taxes, deferred tax assets and liabilities and valuation allowances.
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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 recorded 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. Please see Note 7 in Notes to the Interim Financial Statements and Note 6 in the Annual Financial Statements for information on income taxes.
Recent Accounting Pronouncements
See Note 2 in Notes to our Interim Financial Statements and Note 2 in Notes to the Annual Financial Statements included elsewhere in this prospectus for a description of recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted.
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BUSINESS
Our Business
Talen is an independent power producer and infrastructure company committed to the energy transition. We own and operate over 10 GW of high-quality 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 continuing to reduce the carbon profile of our fleet through conversions and retirements of wholly-owned coal facilities. In addition, as part of our Cumulus digital infrastructure and energy transition platform, 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. We believe our data center project provides both an attractive source of demand for the plant and a new source of incremental revenues for us. In the first half of 2023, Talen generated $496 million of net income and $774 million of Adjusted EBITDA. “Prospectus Summary—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 60% of our generation carbon-free in the first half of 2023. We believe Susquehanna may benefit from the Nuclear PTC beginning in 2024, providing increased cash flow stability through 2032. Our 8.0 GW natural gas, oil and peaking fleet in PJM and ERCOT (of which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after conversion from coal) 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. The plants in PJM generate material annual capacity revenues, and a seasoned operating team in both PJM and ERCOT lead the monetization of seasonal commodity volatility. We have already completed the conversion of approximately 2.9 GW of our legacy coal fleet to natural gas, with an additional 300 MW coal-to-oil conversion nearing completion, 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, anchored by the world’s first 24x7 carbon-free, direct-connect data center campus. The Cumulus Digital campus, an up to 1.0 GW hyperscale data center campus adjacent to the Susquehanna facility, will provide digital infrastructure powered by “behind-the-fence” generation directly from Susquehanna. With limited remaining capital expenditures planned for the first phase of operations, we are now focused on 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 our data center business 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 and other projects, please see “—Properties.”
Note: Fleet as of 6/30/2023.
1.Brunner Island: Coal-to-dual fuel conversion completed in 2016; coal-fired generation is already restricted during the EPA Ozone Season, which is May 1 to September 30 of each year and will cease by year-end 2028. Montour: Coal-to-gas conversion completed in August 2023. Wagner unit 3: Conversion from coal to oil to be complete by year-end 2023. However, in the fourth quarter of 2023, we provided notice to PJM that requests deactivation of Wagner on June 1, 2025.
2.A notice was provided to PJM that requested deactivation of Brandon Shores on June 1, 2025.
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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 2022, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a top-quartile low all-in cost of approximately $22 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. We believe the facility is now also poised to benefit substantially from the Nuclear PTC enacted under the Inflation Reduction Act, which, starting in 2024, will 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. The Cumulus Data Center Campus, which is planned to be a zero-carbon data center campus adjacent to Susquehanna, provides Susquehanna with additional opportunities to maximize future revenue, including through long-term power sale arrangements that create value for both the plant and the data center.
Susquehanna’s efficient cost structure is supported in part by a portfolio of supply contracts for all stages of the nuclear fuel cycle. We have already procured substantially all of the physical fuel required to operate the facility through 2025 and all required conversion and fabrication are secured through the end of 2029. We also recently accelerated certain fuel deliveries to eliminate ongoing 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.
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Natural gas, oil and peaking units. Our generation portfolio includes 10 geographically and technologically diverse natural gas, oil and peaking facilities across the generation stack in PJM and ERCOT, with certain units capable of utilizing multiple fuel sources.
•PJM. Our PJM assets benefit from both a wholesale and a capacity market. Lower Mount 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 lives and enables us to maintain both the associated capacity revenues and the additional commodity upside potential.
•ERCOT. Our ERCOT assets are highly dispatchable and operate at low heat rates, leaving them well positioned to take advantage of market demand for flexible generation, especially since 2021 when ERCOT increased its ancillary service procurement volumes to provide additional operating reserves. Our Barney Davis and Nueces Bay facilities, both located in growing Corpus Christi, TX, have significant duct-firing capabilities that enable them to optimize between ancillary services and energy during periods of market volatility. Our Laredo plant is one of the most efficient and operationally flexible peakers in ERCOT, with a 10-minute quick start for ancillary capability. The operational flexibility of our Texas assets enables them to respond quickly to pricing signals to capture value in ERCOT.
Our Cumulus platform opportunities. As described below, we have a number of growth opportunities in our Cumulus platform. Collectively referred to as the “Cumulus Projects,” we have, through our Cumulus Affiliates, invested in: (i) a pipeline of renewable energy projects via our joint ventures with Pattern Energy and BQ Energy; (ii) the development of digital infrastructure projects through our indirect subsidiary, Cumulus Data, including the development of an up to approximately 1 GW hyperscale data center powered by Susquehanna and (iii) the development and operation of the world’s first zero-carbon digital currency facility through Nautilus, our joint venture with TeraWulf in which we own a 75% equity interest in through our indirect subsidiary, Cumulus Coin. Any further investments in our Cumulus Projects are expected to be (i) grounded in a solid and highly-justified returns profile that exceeds returns and benefits compared to our other capital priorities and investment opportunities, (ii) to a large extent, funded from new investors, partners and ventures, and (iii) with respect to Cumulus Data, include executed customer contracts. 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:
•Hyperscale data center campus. Cumulus Data, in which we own an approximate 95% equity interest, is developing an up-to-1.0 GW hyperscale data center campus adjacent to Susquehanna, which will provide first-of-its-kind digital infrastructure powered by carbon-free energy. Construction of the core and shell of the first data center building, with capacity of 48 MW or more, is largely complete, along with electrical infrastructure that can accommodate three total buildings of similar size. Further expansion up to approximately 1.0 GW is possible across the 1,200-acre campus with additional substation infrastructure and buildings. We believe the Cumulus Data Center Campus represents an opportunity to secure contracts with high-quality counterparties at attractive power prices, structured with limited incremental capital investments from us. The supply of power directly from Susquehanna creates the potential for long-term PPA pricing that could exceed the Nuclear PTC “floor” and still provide data center customers with attractive terms. Both Cumulus Data and its customers may further benefit from the data center’s exemption from Pennsylvania sales and use tax, which provides significant savings on eligible purchases of equipment for the campus.
•Renewables, battery and growth opportunities. Our Cumulus Affiliates’ renewables and battery storage initiatives are focused on the opportunity to leverage our substantial existing asset base in the development
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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 Center Campus. This 150 gross MW facility 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 nearly 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 the third quarter of 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 is expected to be completed by the end of 2023, with substantially all required capital expenditures already made; however, for economic reasons, we have requested deactivation of Wagner in mid-2025, and we currently anticipate that the plant will not operate after that time. 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 currently anticipate that the plant will not operate after that time unless required for reliability reasons.
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. When measured by the operational and safety standards adopted by the nuclear industry, Susquehanna is one of the top performers in the United States. In 2022, Talen produced over 18,000 GWh of reliable, zero-carbon power from Susquehanna at a low all-in cost of approximately $22 per MWh while maintaining leading safety performance.
Going forward, our commercial strategy at Susquehanna will 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 from 2024 to 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 can monetize remaining credits through the sale to an eligible taxpayer. The Cumulus Data Center Campus creates additional incremental value for Susquehanna, providing the opportunity to maximize future cash flows through long-term PPAs. Based on recent data center market dynamics, we believe these PPAs could provide contracted revenue streams at prices meaningfully above the Nuclear PTC “floor” while remaining attractive to high-quality customers.
Flexible and highly dispatchable natural gas, oil and peaking fleet provides the ability to capture significant incremental revenue and benefit from shifting market dynamics. Our 8.0 GW natural gas, oil and peaking fleet (of
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which 3.2 GW is from Brunner Island, Montour and Wagner Unit 3 after conversion 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 through our PJM and ERCOT assets while also generating predictable capacity revenues in PJM. Our seasoned operating teams in both PJM and ERCOT lead the monetization of seasonal commodity volatility. Our natural gas, oil and peaking fleet provides meaningful operational flexibility, with certain units capable of achieving full load in as little as 10 minutes, enabling us to respond quickly 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, oil and peaking fleet is also poised to benefit from potential regulatory reforms and shifting market dynamics. In PJM, retirements in the coming years are expected to tighten reserve margins, and PJM is working to reform the capacity market, which could improve the risk-reward proposition for existing generators. Meanwhile, ERCOT pricing volatility is expected to increase, leading to significant value opportunity for facilities that can quickly respond to pricing signals, and proposed marked redesign is expected to improve scarcity pricing (ORDC) and create new ancillary services. We believe our fleet is well positioned to benefit from these developments.
Zero-carbon digital infrastructure optimally positioned for monetization and value creation. The demand for colocation data centers in the United States has significantly outpaced supply over the last few years, which we believe has favorable impacts for Cumulus Data. The development of Cumulus Data’s hyperscale data campus is expected to provide an integrated power and digital infrastructure solution to end use data center customers. This development capitalizes on a clear synergy by bringing a growing electricity demand (i.e., data storage) directly to Susquehanna’s low-cost, reliable and carbon-free power supply. The near-term completion of the data center’s first 48 MW building unlocks the significant value of the investment capex deployed in prior years and is expected to result in higher net income and Adjusted EBITDA to free cash flow conversion, possibly as early as 2024.
We are now focused on realizing the value of our prior investments in the data center and are engaging with a variety of potential counterparties regarding a possible strategic transaction. We are considering a number of possible structures, including but not limited to joint ventures, asset sales or long-term leases, to maximize the value of these assets to our business in both the near-term and the long-term. The Cumulus Data Center Campus is accretive to our core generation business, providing an opportunity to maximize Susquehanna’s future cash flows through large-scale, long-term power contracts at mutually attractive rates, and any strategic transaction will seek to maximize value not only for the data center but also for Susquehanna.
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 June 30, 2023, we have unrestricted cash of approximately $127 million and our revolving credit facility is undrawn with $700 million of available commitments, resulting in liquidity of approximately $827 million. 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.”
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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.
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.
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 $496 million of net income and $774 million of Adjusted EBITDA in the first half of 2023. “—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 2022, our PJM fleet generated approximately $377 million in capacity revenues. We now also have substantive federal support for nuclear generation, which is accretive to our portfolio, with the Nuclear PTC materially 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 reforms in the PJM and ERCOT 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
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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. 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, 2022, we have reduced our annual carbon dioxide emissions by approximately 69%, nitrogen oxide emissions by approximately 81% and sulfur dioxide emissions by approximately 86% when compared to 2010 levels.
Our environmental position is firmly anchored by Susquehanna, which enabled us to generate approximately 50% of our electricity output carbon-free in 2022 and over 60% carbon-free in the first half of 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 0.35 metric tons per MWh in 2022, which is over 40% better than our carbon intensity in 2010. We expect to continue reducing our carbon footprint through the recently- and nearly-completed conversions of 3.2 GW of our legacy coal fleet (including Wagner Unit 3) 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. 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.
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
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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, whether through long-term power sales to the Cumulus Data Center Campus or 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 several strong growth options already under development, with the majority of our planned capital expenditures on them already spent and are now focused on monetizing our prior investments. 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
Our power generation facilities as of June 30, 2023 are as follows:
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(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 Interim Financial Statements and Note 14 in the Notes to the Annual Financial Statements for additional information regarding jointly owned facilities.
(3)A notice was provided to ERCOT that requested suspension of operations for Barney Davis Unit 1 on November 24, 2023.
(4)LMBE-MC deactivated 33 MW of peaking unit capacity in June 2023.
(5)The 1.5 GW Montour coal-to-gas conversion is nearly complete: Unit 2 went commercial (fully operational) on natural gas in early August; Unit 1 is expected to be commercial on natural gas in the second half of 2023.
(6)Coal-based generation will cease by December 31, 2028. Coal-fired electric generation is restricted during the EPA Ozone Season, which is May 1 to September 30 of each year.
(7)H.A Wagner is transitioning its coal-fired unit to fuel oil, with the conversion expected to be completed in 2023. However, in the fourth quarter of 2023, we provided notice to PJM that requests deactivation of Wagner on June 1, 2025.
(8)A notice was provided to PJM that requested deactivation of Brandon Shores on June 1, 2025. See Note 10 in Notes to the Interim Financial Statements for additional information.
Our Segments
We have two reportable segments, which are primarily based on the market areas in which our generation fleet operates and the manner in which our senior management team reviews our financial and operating performance and
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allocates resources. Our segments, PJM and ERCOT and Other, are engaged in electricity generation, marketing activities, commodity risk and fuel management within their respective RTO or ISO markets. Descriptions of segments are:
•PJM – a grouping that includes the operating and marketing activities within the PJM market. PJM is comprised of Susquehanna along with Talen’s natural gas, oil and coal generation facilities located within the PJM market; and
•ERCOT and Other – a grouping that includes the operating and marketing activities (i) within the ERCOT market for the operations of the Talen Texas natural gas-fired power generation facilities and (ii) for Talen Montana’s proportionate share of the Colstrip Units, as well as the operating and marketing activities within the New York ISO market for the operations of the Talen NE power generation facilities (including Millennium and Athens when owned in 2020 and prior).
Our Key Markets
We are one of the largest independent power producers in the United States with generation capacity of 12,402 MW (summer rating) as of June 30, 2023. The substantial majority of our generation capacity is located in either our PJM segment or the ERCOT portion of our ERCOT and Other segment. We consider these regions to be among the most well-developed, transparent and liquid energy markets in the United States. The following table illustrates our portfolio breakdown by market as of June 30, 2023:
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 June 30, 2023, it is the largest competitive wholesale power market in the United States, coordinating the dispatch of more than 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 over 90% of its available capacity as of June 30, 2023. 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 Market Seller Offer Caps (the maximum price at which certain units can bid into the market) as determined by the PJM IMM and/or PJM. The future PJM Base Residual Auctions have been delayed and will be conducted as follows: 2025/2026 PJM Base Residual Auctions in June 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.
ERCOT and Other
ERCOT is an ISO that manages the flow of electricity from approximately 98,000 MW of installed generation capacity to approximately 26 million Texas customers, representing 90% of the state’s electric load and covering approximately 75% of its geography. ERCOT is an attractive wholesale power market with historically above-average demand growth, tight reserve margins and an increasing reliance on flexible and quickly dispatchable natural gas-fired assets. ERCOT was established in September 1996 and, as such, is the oldest ISO in the United States.
As an energy-only market, ERCOT’s market design is different from other competitive electricity markets in the United States. Other markets, including PJM, maintain a minimum reserve margin through regulated planning, resource adequacy requirements or capacity markets. In contrast, ERCOT’s resource adequacy is predominately dependent on free market processes and energy market price signals. All electricity prices are subject to a system-wide offer cap. In 2022, the system-wide offer cap was set at $5,000 per MWh, although the cap can be reduced to $2,000 per MWh, if certain conditions are met. ERCOT uses a scarcity pricing mechanism known as the ORDC that administratively adds value to the real-time locational marginal prices as reserves get below a certain level. In January 2023, the PUCT adopted the PCM market design to address market reliability concerns in Texas. The details of how the PCM market will operate are to be developed by the PUCT, ERCOT and the ERCOT stakeholder group and will consider guidelines established in House Bill 1500 passed during the 2023 legislative session. In January 2023, the PUCT directed ERCOT to evaluate bridging options to retain existing assets and build new dispatchable generation until the PCM can be fully implemented. In response, the ERCOT Board and PUCT approved a multi-step ORDC floor as a short-term bridge solution, which is pending implementation. There remains significant uncertainty surrounding the details of the proposed PCM design and the timing for implementation. At this time, we cannot fully predict the impacts of the PCM market design, when and if implemented, on our results of operation and liquidity.
Generation facilities in the region include many natural gas-fired facilities, a large wind fleet, an expanding solar fleet, two nuclear facilities and coal-fired assets. The combination of these assets has historically led to lower marginal cost of production during most periods compared to other markets. However, the region has limited excess capacity to meet high demand days and the marginal facilities have high operating costs. Therefore, the marginal price of supply rapidly increases during periods of high demand. As a result, many generators in ERCOT benefit from these sporadic periods of “scarcity pricing” in which power prices increase significantly.
In addition to energy, ancillary services, including Non-Spinning Reserve Service, ERCOT Contingency Reserve Service, Responsive Reserve Service and Regulation Service offer other potential revenue streams for market participants in order to maintain system reliability. These ancillary services help mitigate real-time system needs and have exhibited higher clearing prices in part because ERCOT has one of the highest concentrations of intermittent wind capacity in the United States, with approximately 36,900 MW of installed capacity.
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,
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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 Nuclear PTCs 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 FTRs/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 and ERCOT 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 | ||||||||||||
Our Contracted Revenue Sources
Operating revenues primarily consist of capacity revenues, energy/ancillary revenues and unrealized gain (loss) on derivative instruments.
The substantial majority of our generation capacity is located in, and revenues are derived from, either PJM or ERCOT, both wholesale markets. Please read “—Our Key Markets—PJM” for more information regarding this key market.
We sell capacity through forward PJM Base Residual Auctions. To the extent we are unable to sell unused capacity through the PJM base or incremental auctions or through bilateral contracts, we may sell the remaining capacity into monthly or spot markets. We also enter into bilateral agreements in each of PJM and ERCOT with power purchasers for the sale of energy from our generation fleet as part of our optimization strategy. We may also enter into these agreements outside of the markets operated by PJM and ERCOT. Counterparties to the contracts are either unaffiliated third parties, Cumulus Data or Talen Energy Marketing.
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. The following table indicates our electric energy generated by fuel diversity for the 12-month period ended December 31, 2022:
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Electric Energy Generated by Fuel Diversity (TWh)
Nuclear
Susquehanna Nuclear has a portfolio of supply contracts for uranium, conversion, enrichment and fabrication with varying expiration dates, and we expect execution of certain additional fuel contracts to be immediately forthcoming. Together, these contracts are expected to provide substantially all of the nuclear fuel required to operate Susquehanna through 2025 and the majority of 2026, with significant supply contracted as far out as 2028. We recently accelerated certain fuel deliveries to eliminate ongoing exposure to any Russian-affiliated counterparties.
Susquehanna 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.
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We plan to eliminate the use of coal at our wholly owned generation facilities through either fuel conversion or plant retirement. Our current coal inventories are expected to be sufficient to run our wholly owned coal-fired facilities through either their planned conversion or planned retirement, as applicable, and we do not expect to make significant additional coal purchases for those facilities unless required by regulators to run for reliability reasons.
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 our 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 the Notes to the Interim 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 and ERCOT are competitive markets and have, 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 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, allowing lower electric-market bid prices from competing natural gas generators, which can lead to lower realized electric market prices for our Mid-Atlantic facilities 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. In
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addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region and during the summer in Texas.
We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance requirements of our facilities and the terms of bilateral contracts to purchase or sell electricity. The largest recurring maintenance project is the annual spring refueling outage at Susquehanna. The outages normally occur during late March and into April each year. Susquehanna Unit 2 entered its spring refueling outage on March 20, 2023 and successfully completed the outage on April 24, 2023.
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 October 16, 2023, the limit for public liability and approved legal costs per incident is approximately $16.2 billion, which is funded by primary 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 expect to increase primary insurance coverage to $500 million, resulting in a commensurate increase in total coverage, but that increase has not yet occurred.
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 approximately $331.8 million per incident, payable at a maximum of approximately $49.4 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 September 30, 2023, 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 at June 30, 2023. Talen has additional coverage that, under certain conditions, may reduce this exposure.
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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 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.
Talen Restructuring
Upon Emergence in May 2023, the Debtors’ liability was discharged for certain claims arising prior to commencement of the Restructuring pursuant to the Plan of Reorganization. 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 in these 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 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. On August 25, 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 Montana, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. This holding may be appealed by any of the parties. 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; in May 2023, 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, who are currently seeking appellate review. 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.
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
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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.
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 Sale from Talen Montana to PPL, leaving Talen Montana without adequate funds to pay its obligations. Plaintiff seeks compensatory and punitive damages. In January 2020, PPL filed a motion to dismiss this suit for, among other things, lack of personal jurisdiction. In September 2020, the Montana state court denied PPL’s motion to dismiss, but granted a stay of the Montana claims until resolution of the Delaware case described below.
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. In October 2019, the Delaware Court granted Talen defendants’ motion to dismiss one of PPL’s claims but denied Talen defendants’ other requests for dismissal.
Talen Montana then filed an adversary complaint against PPL and its affiliates in the Bankruptcy Court, which asserts claims similar to those asserted in the Montana action. In September 2022, the PPL defendants filed counterclaims substantially similar to the claims asserted in the Delaware Court. In June 2023, the Bankruptcy Court denied the PPL defendants’ motion for partial summary judgment and set the case for trial in February 2024. 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. Talen Montana and its affiliates believe that PPL’s claims are without merit and intend to vigorously prosecute their own claims and defend against the counterclaims. Talen Montana and Talen cannot predict the outcome of this matter or its effect on Talen Montana and Talen; however, a material positive or adverse judgment could affect 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) 10 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, subject to negotiation of mutually acceptable definitive agreements and Court approval of the final settlement. If the final settlement is approved, we do not expect a material adverse effect on Talen’s results of operations and liquidity or the TERP’s assets. If the settlement is not consummated and the plaintiffs prevail on their claims, a material adverse judgment could have an adverse effect on the TERP’s assets and Talen’s results of operations and liquidity. We cannot at this time predict the outcome of this matter or its effect on Talen if litigated to conclusion.
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 the 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
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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.
SNF Litigation
Substantial uncertainty exists regarding the nuclear industry’s permanent disposal of 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 Nuclear.
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. A claim for such costs was submitted under the agreement in 2023 for costs incurred in 2022. 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.
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.
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 Capacity Market
PJM MOPR
In July 2021, PJM filed proposed tariff language that significantly reduced 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. Appeals relating to the narrowed PJM MOPR are pending before the U.S. Court of Appeals for the Third Circuit. As a result, the final impact on Talen’s financial condition, results of operations or liquidity is not known at this time.
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 2025/2026 in June 2024, 2026/2027 in December 2024, 2027/2028 in June 2025 and 2028/2029 in December 2025.
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PJM 2024/2025 Base Residual Auction
PJM delayed the release of the 2024/2025 PJM Base Residual Auction results due to certain issues regarding DPL-South, a PJM locational delivery area. In December 2022, PJM filed a request with FERC to revise its tariff to enable PJM to adjust an auction parameter for DPL-South and to make adjustments to subsequent auction outcomes if similar issues arise in future auctions. In February 2023, FERC approved PJM’s filing. Rehearing of FERC’s order was denied by operation of law in April 2023, and several parties have appealed the order to the U.S. Court of Appeals for the Third Circuit. On February 27, 2023, PJM released its 2024/2025 auction results.
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. The final impact of this order on Talen’s financial condition, results of operations or liquidity is unknown at this time.
PJM Capacity 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 October 13, 2023, PJM made a filing at FERC regarding certain CIFP changes. Talen is participating in the CIFP process, but it is too early in the process to determine impacts to Talen.
Winter Storm Elliot
During December 2022, as a result of Winter Storm Elliott, PJM experienced extreme cold weather conditions that contributed to PJM declaring a Maximum Generation Emergency Action. 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 has: (i) incurred certain Capacity Performance penalties charged by PJM for certain generation facilities; and (ii) earned bonus revenues from PJM for other generation facilities.
In April 2023, PJM notified Talen Energy Marketing of an update to the expected Capacity Performance penalties incurred by certain of Talen’s generation facilities and bonus revenues earned by other generation facilities, and Talen Energy Marketing recognized in 2023 and 2022 an aggregate penalty of $51 million, net of expected bonus revenues.
Talen Energy Marketing and its affiliates filed complaints against PJM at FERC disputing a portion of the penalties assessed by PJM, along with other complainants, and on September 29, 2023, PJM filed for FERC approval a settlement agreement that would resolve all Winter Storm Elliot complaints, including those filed by Talen. The settlement agreement would result in a 31.7% reduction in the total penalties assessed on all capacity market sellers, including Talen, as well as an additional $7.5 million credit to Talen. As filed, the settlement agreement would reduce Talen’s aggregate penalty, net of expected bonus revenues, from $51 million to approximately $28 million. No assurance, however, can be provided that the settlement will be approved. In addition, in December 2022, FERC and NERC opened a joint inquiry into the operations of the bulk-power system regarding Winter Storm Elliott. FERC and NERC completed their inquiry and issued a report in September 2023.
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 winter storm events.
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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 co-op. 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.
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 ORDC floor as a short-term bridge solution. 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 operation 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 environmental matters or become subject to 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 coal operations, Talen requested extensions for compliance under these rules for certain Talen 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 has proposed additional changes to the EPA ELG Rule and to the EPA CCR Rule. The ELG 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, EPA has proposed to impose new requirements on legacy CCR impoundments and CCR Management Units, which could affect several Talen facilities. Furthermore, 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, Connecticut, Delaware, Maryland and New York have submitted petitions to the EPA under Section 126 of the CAA requesting findings that different upwind coal-fired power generation facilities, including our Brunner Island and Montour generation facilities and the Keystone and Conemaugh generation facilities, in which we own undivided interests, are emitting air pollutants that significantly contribute to non-attainment of the 2008 and 2015 ozone EPA NAAQS in their respective states (each state pointing to different generation facilities).
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The EPA has denied the petitions. After Delaware, Maryland, New York and certain activists filed petitions for review of the decisions for their states in the U.S. Court of Appeals for the D.C. Circuit, the Court vacated and remanded the Maryland and New York denials. The EPA is in the process of reconsidering the denials. In a parallel effort to attain the EPA NAAQS, in May 2019 Maryland also requested that the Ozone Transport Commission petition EPA to lower air emissions from various generation facilities in Pennsylvania, including some generation facilities owned by Talen. After receiving public comment on the matter in June 2020, the Ozone Transport Commission recommended to EPA that it require additional nitrogen oxides control measures at the affected generation facilities. In December 2020, the EPA published a notice summarizing the Ozone Transport Commission recommendations and seeking comments on the recommendations. Since receiving comments in February 2021, the EPA has yet to take action on the recommendation.
In February 2020, the states of New Jersey, Connecticut, Delaware, New York and Massachusetts, and the City of New York, filed a lawsuit seeking to compel EPA to promulgate EPA FIPS for the EPA 2008 EPA NAAQS to address nitrogen oxide emissions from seven states, including Pennsylvania. In July 2020, the U.S. District Court for the Southern District of New York issued a decision requiring the EPA to issue those EPA FIPS in March 2021. Also, in March 2021, the EPA finalized revisions to the EPA CSAPR that, effective in June 2021, lowered the Ozone Season nitrogen oxide allowance budgets for certain upwind states, including Pennsylvania and Maryland, beginning in 2021. Talen had sufficient nitrogen oxide allowances to support generation in the 2022 Ozone Seasons and will manage its electricity generation and allowance inventory to maintain compliance going forward.
To address the 2015 ozone standard, in June 2023, EPA published the final rule covering the CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” 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 CSAPR and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. 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.
To address the 2015 ozone standard, in June 2023, EPA published the final rule covering the CSAPR Ozone Season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” EPA has made some reductions in allowance allocations, among other changes, to minimize nitrogen oxide emissions during the Ozone Season. Texas, among other states, challenged the Good Neighbor FIP. On August 2, 2023, the EPA announced an interim final rule, which took effect on August 4, 2023, for Arkansas, Kentucky, Louisiana, Mississippi and Texas. The interim final rule imposed a stay on the “Good Neighbor FIP” for facilities in those states. Talen’s Texas facilities are still subject to the previous version of CSAPR and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. Imposition of stricter deadlines for controlling downwind contribution could accelerate unit retirements or the need to implement emission control strategies. 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 (residual risk and technology review) 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 to the EPA on the rule, indicating that the rule, if finalized, would unreasonably require Colstrip to install new control equipment. A final rule is expected by March 2024. 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. Certain third parties filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania is currently stayed. The timing and potential impacts associated with these legal proceedings are uncertain and therefore, may change the state’s participation in the RGGI program, including the compliance
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timeline. 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 CAA 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 rule would allow all existing EGUs to continue to operate until 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 GHG 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.
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 September 30, 2023, we had 2,118 full-time employees, 41% of which were represented by labor unions. In December 2022, IBEW Local 1600, which represents approximately 32% of our workforce, ratified a memorandum of agreement with TEC to extend the term of the existing collective bargaining agreement to August 2025. Likewise, in April 2023, the collective bargaining agreement with IBEW Local 1638, which covers approximately 187 Talen Montana employees, was extended to April 2026.
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 October 23, 2023:
Name | Age | Position | ||||||||||||
Mark “Mac” McFarland | 55 | Chief Executive Officer and Director | ||||||||||||
Terry Nutt | 47 | Chief Financial Officer | ||||||||||||
John Wander | 56 | General Counsel and Corporate Secretary | ||||||||||||
Andrew Wright | 56 | Chief Administrative Officer | ||||||||||||
Stephen Schaefer | 59 | Chairman of the Board and Director | ||||||||||||
Gizman Abbas | 51 | Director | ||||||||||||
Anthony Horton | 62 | Director | ||||||||||||
Karen Hyde | 62 | Director | ||||||||||||
Joseph Nigro | 58 | Director | ||||||||||||
Christine Benson Schwartzstein | 42 | 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 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 a member of the Board the 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 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 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 he 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.
Directors
The following is a brief summary of the business experience of our directors.
Stephen Schaefer. Mr. Schaefer has served as the Chairman of the Board 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 from November 2018 to May 2023), TexGen Power LLC (where he has served as Chairman of the Board since May 2018), Just Energy Group, Inc., and Alpine Summit Energy Partners (where he has also served as Chairman of the Audit Committee since July 2018). Mr. Schaefer has been actively involved in the deregulated natural gas and electricity markets since 1993. He was a Partner with Riverstone Holdings LLC (“Riverstone”), a private equity firm focused on energy investing, from 2004 to 2015. While at 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 as a Founding Principal of Direct Invest Development since December 2014 and has served on the Board of Directors of the New York Independent System Operator as Chairman of the Commerce & Compensation Committee and 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
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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 and March 2020, respectively, Mr. Horton has served as Chief Executive Officer of AR Horton Advisors and served as an Independent Director for Travelport. Additionally, Mr. Horton served as an Independent Director of 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, and served as Independent Director and Chairman of the Board 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. Ms. Hyde earned her M.S. in Mineral Economics from the Colorado School of Mines 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 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. 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
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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.”
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;
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•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 will operate under a written charter, to be effective prior to the effectiveness of the registration statement of which this prospectus forms a part, 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 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 Co-Chief Executive Officers;
•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 will operate under a written charter, to be effective prior to the effectiveness of the registration statement of which this prospectus forms a part, 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.
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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 will operate under a written charter, to be effective prior to the effectiveness of the registration statement of which this prospectus forms a part, 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.
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.
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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 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—Reorganization and Emergence.” Following its Emergence, the Company has a new board of directors (the “Current Board”) and compensation committee thereof, and has 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, 2022, as required by applicable disclosure requirements. However, we first describe our compensation arrangements put in place following the Restructuring, as we believe this description provides a more relevant understanding of our current and future compensation programs and philosophy.
Our Named Executive Officers, Post- and Pre-Restructuring
Following the Restructuring, the Company’s principal executive officer, principal financial officer and three other most highly compensated executive officers (the “Current Executive Officers”) are:
•Mark “Mac” McFarland, President and Chief Executive Officer;
•Terry Nutt, Chief Financial Officer;
•John Wander, General Counsel and Corporate Secretary;
•Brad Berryman, Senior Vice President and Chief Nuclear Officer; and
•Andrew Wright, Chief Administrative Officer.
This Executive Compensation section is required to, among other things, provide information about the material elements of compensation for our “named executive officers” for 2022, which included our former principal executive officer, former principal financial officer and the three other most highly compensated executive officers employed at the end of 2022. For 2022, our named executive officers were:
•Alejandro Hernandez, Former Chief Executive Officer;
•John Chesser, Former Chief Financial Officer;
•Andrew Wright, Former General Counsel and Corporate Secretary (now Chief Administrative Officer);
•Brad Berryman, Senior Vice President and Chief Nuclear Officer; and
•Dale Lebsack, Former Senior Vice President, Fossil Operations (now Chief Fossil Officer).
We made several changes to our senior management team 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, (iii) Mr. Chesser departed the Company in July 2023, at which time Mr. Nutt was appointed as Chief Financial Officer and (iv) Mr. Lebsack was promoted to Chief Fossil Officer in July 2023 (after having been promoted to Senior Vice President, Fossil Operations in March 2022).
Although Messrs. McFarland, Nutt and Wander were not named executive officers for 2022, we have included descriptions of their compensation arrangements in this discussion, as well as the current arrangements for Messrs.
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Berryman and Wright, as these new arrangements more accurately reflect our current compensation philosophy and objectives with respect to our Current Executive Officers.
Pre-Emergence Compensation Philosophy
Compensation decisions with respect to our named executive officers before the Restructuring, including the design and adoption of the compensation program in place from January 2022 to April 2022 (the “2022 Compensation Program”) and subsequent changes to this program in April 2022 in light of the Restructuring (the “Revised 2022 Compensation Program”) were made by the pre-Restructuring board of directors (the “Prior Board”), and decisions made during the Restructuring were generally made by the Restructuring Committee (the “Restructuring Committee”) of the Talen Energy Supply board of managers and approved by the Bankruptcy Court. The compensation paid to our named executive officers for 2022 is not indicative of how we expect to compensate our named executive officers going forward, as it was significantly impacted by circumstances that the Prior Board determined justified changes to the 2022 Compensation Program in order to focus on cash retention and short-term incentives during the Restructuring. Upon Emergence, the Company implemented new compensation plans and arrangements in 2023 (the “Current Compensation Program”) with increased focus on long-term incentives and stockholder alignment, which are discussed in greater detail below under “—2023 Compensation Arrangements.”
Current Compensation Philosophy and Objectives
Our compensation committee reviews and approves the compensation of our named executive officers 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 current 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 new post-Emergence compensation plans that tie a substantial portion of our executives’ overall compensation to our operating and financial performance.
Determining Compensation
Role of Our Compensation Committee and Named Executive Officers
Our compensation committee meets outside the presence of all of our executive officers, including our named executive officers, to consider appropriate compensation for our Chief Executive Officer. For all other named
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executive officers, our compensation committee meets outside the presence of all executive officers except our Chief Executive Officer. Going forward, our Chief Executive Officer will review annually each other named executive officer’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, 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.
Role of Compensation Consultant
In order to ensure that we continue to remunerate our executives appropriately, our compensation committee retained Lyons, Benenson & Company, Inc. (“LB & Co.”) as its independent compensation consultant to assist with the design of the Current Compensation Program, and its work included the review of policies and procedures with respect to executive compensation following our Emergence. LB & Co. 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.
Our Prior Board did not engage an independent compensation consultant to assist with the design or implementation of the 2022 Compensation Program. The Prior Board and the Restructuring Committee subsequently retained Willis Towers Watson plc (“WTW”) as independent compensation consultant to design the Revised 2022 Compensation Program.
Neither LB & Co. nor WTW provided services to the Company other than the compensation advisory services described above.
Benchmarking for Revised 2022 Compensation Program
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 Revised 2022 Compensation Program, the Prior Board and the Restructuring Committee, with assistance from WTW, reviewed and considered the compensation paid by our known competitors in terms of the elements of pay, total available pay opportunities and compensation actually received.
The competitive market data provided by WTW was based, in part, on the following peer group that was developed by WTW and approved by the Prior Board and the Restructuring Committee:
| 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. | |||||||
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2023 Benchmarking
Following Emergence, our compensation committee engaged LB & Co. to review and update the company peer group listed above, and our compensation committee intends to continue using competitive market data to inform its decisions about our executive compensation program in the future.
Risk Management
The Company has determined that any risks arising from our Current Compensation Programs 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.
2023 Compensation Arrangements
In connection with Emergence, the Company entered into new employment and compensation arrangements with our Current Executive Officers. As mentioned above, although Messrs. McFarland, Nutt and Wander were not named executive officers for 2022, we have described their compensation arrangements herein, as well as the current arrangements for Messrs. Berryman and Wright, as these new arrangements more accurately reflect our compensation philosophy and objectives with respect to our Current Executive Officers. For a description of our historical arrangements with our named executive officers for 2022, see the sections titled “—2022 Compensation Program” and “—Revised 2022 Compensation Program.”
Employment Agreements
Upon or following Emergence, the Company entered into new employment agreements with each of the Current Executive Officers (collectively, the “Current Employment Agreements”), as described below.
Under the Current Employment Agreements, which have three-year terms, the Current Executive Officers are entitled to the following annual base salaries:
| Executive | 2023 Base Salary | |||||||
| Mark McFarland | $ | 1,125,000 | ||||||
| Terry Nutt | $ | 550,000 | ||||||
| John Wander | $ | 550,000 | ||||||
| Brad Berryman | $ | 550,000 | ||||||
| Andrew Wright | $ | 530,000 | ||||||
The Current Executive Officers are eligible to receive the following annual target bonuses as a percentage of their annual base salary, in each case, to be earned based upon the achievement of performance objectives to be determined by our compensation committee:
| Executive | Target STI Payout (% of Base Salary) | 2023 Target Payout | ||||||||||||
| Mark McFarland | 135% (with the opportunity to earn up to 200% in subsequent years) | $ | 1,518,750 | |||||||||||
| Terry Nutt | 100 | % | $ | 550,000 | ||||||||||
| John Wander | 100 | % | $ | 550,000 | ||||||||||
| Brad Berryman | 100 | % | $ | 550,000 | ||||||||||
| Andrew Wright | 100 | % | $ | 530,000 | ||||||||||
The Current Employment Agreements also set forth the Current Executive Officers’ eligibility to receive certain equity incentive awards (described below in “—2023 Equity Incentive Plan and Equity Awards”), as well as their eligibility to participate in the Company’s employee benefit plans, policies and arrangements that are generally
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available to executive officers. The Current Employment Agreements with Messrs. McFarland and Wander also provide for cash signing bonuses, (i) in the case of Mr. McFarland, in the amount of $2,000,000, payable in two equal installments on each of the first two anniversaries of the execution date of his Current Employment Agreement, and (ii) in the case of Mr. Wander, in the amount of $500,000, payable in two equal installments, the first of which was payable within 30 days of his execution of his Current Employment Agreement and the second of which is payable on the first anniversary thereof, in each case, subject to continued employment through the applicable payment date. Mr. Wander’s signing bonus is repayable to the Company in full in the event that he is terminated for “Cause” or he resigns without “Good Reason” prior to the first anniversary of his date of employment.
Under the Current Employment Agreements, if the Company terminates a Current Executive Officer’s employment without “Cause” or the Current Executive Officer terminates their 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, (i) such Current Executive Officer is entitled to a cash payment equal to one-times (or, for Mr. McFarland, two-times) the sum of their base salary and target annual bonus for the performance year in which the termination date occurs, payable over the 12 months (or, for Mr. McFarland, payable over 24 months) following the separation date, (ii) for Mr. McFarland only, all his long-term equity awards issued upon Emergence shall vest, and (iii) for Messrs. McFarland and Wander only, any unpaid portion of their respective signing bonuses shall automatically vest and be paid within 60 days following the termination date.
“Cause” is defined in each Current Employment Agreement as the Current Executive Officer’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 Current Executive Officer and one or more members of the Company Group, including the Current Executive Officer’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) the Current Executive Officer’s 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 Current Executive Officer), 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.
“Good Reason” is defined in each Current Employment Agreement as the occurrence of any of the following, in each case without the Current Executive Officer’s written consent and which the Company fails to cure within 30 days of receipt of notice: (i) a material adverse change in the Current Executive Officer’s title, duties or responsibilities (including reporting responsibilities); (ii) a material reduction in the Current Executive Officer’s base salary; (iii) a relocation of the Current Executive Officer’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.
The Current 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.
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
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the Current Board. 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 in June 2023 and August 2023 to a select group of Company management, including the Current Executive Officers. 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 Executive Officers were granted the following equity awards under the 2023 Equity Plan:
2023 Emergence Grants (1) | ||||||||||||||||||||||||||
| Executive | Target LTI Payout (% of Base Salary) | Number of RSUs | Number of PSUs | Target Value (in Dollars) | ||||||||||||||||||||||
| Mark McFarland | 2100 | 223,141 | 334,711 | $ | 23,625,000 | |||||||||||||||||||||
| Terry Nutt | 1200 | 62,338 | 93,507 | $ | 6,600,000 | |||||||||||||||||||||
| John Wander | 1200 | 62,338 | 93,507 | $ | 6,600,000 | |||||||||||||||||||||
| Brad Berryman | 1200 | 62,338 | 93,507 | $ | 6,600,000 | |||||||||||||||||||||
| Andrew Wright | 1200 | 60,071 | 90,107 | $ | 6,360,000 | |||||||||||||||||||||
__________________
(1)Emergence grants are intended to reflect the Current Executive Officers’ 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 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 grant date (or, if sooner, the occurrence of a change in control), subject to continued service through such date (except as set forth below). The number of PSUs that vest 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 Executive Officers), 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 Company 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.
Generally, for Current Executive Officers 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 that occurs on or following 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
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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 Current Executive Officers. 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 remain outstanding and eligible to vest based on actual performance.
Upon the occurrence of a “Change in Control” (as defined in the 2023 Equity Plan) all outstanding RSUs and PSUs held by the Current Executive Officers will fully vest (with PSUs vesting based on the implied Adjusted Equity Value in connection with such Change in Control), subject to the Current Executive Officer’s continued employment through such Change in Control.
2022 Compensation Program
The Prior Board established the 2022 Compensation Program described below for our named executive officers. This particular mix of compensation elements, comprised of base salary, short-term incentive cash bonuses and long-term incentive awards, was believed to provide a well-proportioned mix of secure compensation, retention value and at-risk compensation to produce short-term and long-term performance incentives and rewards. As mentioned above and described in more detail below, in light of the Restructuring, the Prior Board made certain changes to the 2022 Compensation Program, specifically enhancing its short-term incentive components, under the Revised 2022 Compensation Program in April 2022.
Base Salary
The primary component of compensation of our executive officers for the 2022 Compensation Program was base salary. The base salary established for each of our executive officers during the first half of 2022 was intended to reflect each individual’s specific role, level and magnitude of responsibility, potential to drive corporate results, industry experience, individual performance and discretionary factors deemed relevant by our then Chief Executive Officer and/or the Prior Board.
Each of our named executive officers received a 3.00% increase to their base salary for 2022 due to ordinary course market adjustments. Mr. Lebsack also received an increase in annual base salary rate from $350,000 to $435,500 in March 2022 in connection with his promotion to Senior Vice President, Fossil Operations. In April 2022, Mr. Lebsack’s base salary was further increased to $450,000, and Mr. Wright received an increase from $420,247 to $515,000, in each case, to bring such executive’s base salary in line with those paid by our peer companies.
The base salaries paid to our named executive officers in 2022 are set forth in the Summary Compensation Table below.
Pre-Emergence Short-Term Incentive Programs
Pre-Restructuring 2022 Retention Bonus Awards
In November 2021, the Prior Board granted Retention Bonus Awards (the “Pre-Restructuring TRAs”) to certain key employees, including our named executive officers, pursuant to which each named executive officer was eligible to receive a retention bonus in an amount equal to 100% of base salary, paid in two equal installments in November 2021 (the “First TRA Installment”) and November 2022 or such earlier date as determined by the Company’s then Chief Executive Officer after consultation with the Prior Board (the “Second TRA Installment” and together with the First TRA Installment, the “TRA Installments”), subject to continued employment through the payment date and subject to vesting in the right to retain each installment. The named executive officers were to
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become vested in their right to retain the TRA Installments subject to continued employment through November 12, 2022 for the First TRA Installment and, for the Second TRA Installment, the first anniversary of payment. In the event of a “change in control,” vesting of each TRA Installment would accelerate to the thirtieth day following the consummation of such transaction.
The table below sets forth the value of each named executive officer’s Pre-Restructuring TRA:
| Executive | First TRA Installment ($) | Second TRA Installment ($) | Total Pre-Restructuring TRA ($) | |||||||||||||||||
| Alejandro Hernandez | 612,500 | 612,500 | 1,225,000 | |||||||||||||||||
| John Chesser | 250,000 | 250,000 | 500,000 | |||||||||||||||||
| Andrew Wright | 210,124 | 210,124 | 420,248 | |||||||||||||||||
| Brad Berryman | 251,964 | 251,964 | 503,928 | |||||||||||||||||
| Dale Lebsack | 175,000 | 175,000 | 350,000 | |||||||||||||||||
In late April 2022, in light of the Restructuring, the Prior Board revised the Pre-Restructuring TRAs with respect to the Second TRA Installments as described below under “—Revised 2022 Compensation Program—Revised 2022 Retention Bonus Awards.” Each named executive officer vested in the First TRA Installment in November 2022, and such amounts are reported in the Summary Compensation Table below. As discussed below under “—Revised 2022 Compensation Program—Revised 2022 Retention Bonus Awards,” the Second TRA Installment was paid to our named executive officers in 2022 but did not vest until 2023, so it is not reported in the Summary Compensation Table below.
2022 Pre-Emergence STI Program
The Company historically maintained a short-term incentive bonus program (the “STI Program”) pursuant to which certain employees, including our pre-Emergence named executive officers, were 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 approved by the Prior Board, with individual awards subject to further adjustment based on management’s determination of individual performance. In March 2022, the Prior Board approved quarterly bonus opportunities under the STI Program for the pre-Emergence named executive officers for fiscal 2022 (the “2022 STI Program”), with target level of aggregate bonus compensation for fiscal 2022 structured as a percentage of base salary, as set forth in the table below. Payouts were to be determined based on the Company’s achievement of Business Plan Investment goals (measured against Operations and Maintenance; CapEx and General and Administrative; and Solar and Battery Equity contribution performance metrics), Safety goals (measured against Lost Time Incident Rate performance metrics), Operating Performance goals (measured against Equivalent Forced Outage Factor performance metrics) and the Company’s progress toward recapitalization and the transformation of its asset base.
| Metric | Weight | Threshold Performance | Target Performance (100%) | Maximum Performance (125 – 250%) | ||||||||||||||||||||||
| Business Plan Investment | 50 | % | $ | 1,111 | M | $ | 966 | M | $821M (200%) | |||||||||||||||||
Safety(1) | 15 | % | 0.75 | 0.3 | 0.20 (125%) | |||||||||||||||||||||
Operating Performance(2) | 15 | % | 6.60 | % | 3.30 | % | 2.30% (250%) | |||||||||||||||||||
| Progress on Recapitalization | 10 | % | — | Board Discretionary Metrics / Guidelines | Board Discretionary Metrics / Guidelines (200%) | |||||||||||||||||||||
| Progress of Transformation | 10 | % | — | Board Discretionary Metrics / Guidelines | Board Discretionary Metrics / Guidelines (200%) | |||||||||||||||||||||
__________________
(1)Safety is measured as the total number of lost time injuries times 200,000 divided by the total number of hours worked.
(2)Operating 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.
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Because the named executive officers were identified as “insiders” for purposes of the anticipated Restructuring, their 2022 STI opportunity could be paid out only at target STI payout levels. In April 2022, the named executive officers received payouts at target performance level under the 2022 STI Program based on operating and financial performance during the first quarter of 2022 as follows:
| Executive | Target STI Payout (% of Base Salary) | Target Q1 2022 STI Payout | Q1 2022 STI Program Payout | |||||||||||||||||
| Alejandro Hernandez | 200 | % | $ | 630,875 | $ | 599,331 | ||||||||||||||
| John Chesser | 50 | % | $ | 66,145 | $ | 61,156 | ||||||||||||||
| Andrew Wright | 50 | % | $ | 66,145 | $ | 61,156 | ||||||||||||||
| Brad Berryman | 60 | % | $ | 79,998 | $ | 73,964 | ||||||||||||||
| Dale Lebsack | 50 | % | $ | 57,797 | $ | 51,716 | ||||||||||||||
In late April 2022, in light of the Restructuring, the Prior Board increased the target STI Program opportunity for each named executive other than Mr. Hernandez and pre-paid to all the named executive officers the remainder of their 2022 STI Program awards at target performance level, subject to clawback under certain circumstances, as described below under “—Revised 2022 Compensation Program—Revised 2022 STI Program.”
2022 Long-Term Compensation Programs
Long-Term Equity-Based Compensation
The pre-Restructuring long-term incentive awards granted to our named executive officers historically consisted of profits interests and restricted interests in our affiliates. Each of our named executive officers previously received profits interests in Talen MidCo LLC (the “MidCo Incentive Units”), which directly held 49% of our equity pre-Emergence. The MidCo Incentive Units represented potential future profits of Talen MidCo LLC (“Talen Midco”). Mr. Hernandez also 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 and approximately 28.9% of Talen directly as of the Company’s commencement of Restructuring. The MidCo Incentive Units and Raven Power Incentive Units granted to our executive officers were subject to both time-vesting and performance-vesting conditions.
Additionally, each of our named executive officers previously entered into a bonus letter agreement with the Company that provided for a cash bonus (each, a “Sale Bonus”) calculated based on the value the executive would have been eligible to realize for his MidCo Incentive Units based on hypothetical capital contributions. The Sale Bonuses would have been payable upon the occurrence of a liquidity event of Talen MidCo or public offering of Talen MidCo or any of its subsidiaries or affiliates (including the Company), which did not occur. Talen MidCo was liquidated following Emergence, at which time the MidCo Incentive Units were cancelled for no consideration in accordance with the terms of the applicable award agreement.
None of these interests were granted to the named executive officers in 2022 and no other equity awards were granted to our executive officers in 2022.
Commercial and Risk Team Long-Term Incentive Plan
Talen Energy Supply maintains the Commercial and Risk Team Long-Term Incentive Plan (the “CRIP”), pursuant to which certain employees of TES and its subsidiaries, including Messrs. Chesser and Lebsack, were eligible to receive cash retention bonus payments. In March 2022, Messrs. Chesser and Lebsack were each granted awards under the CRIP pursuant to which each executive was eligible to earn an aggregate cash retention bonus of $500,000, payable in three equal installments during the first 90 days of each of the 2022, 2023 and 2024 calendar years, subject to the executive’s continued employment through the date of payment (except, in the sole discretion of the Company’s Chief Executive Officer, in the event of termination due to the executive’s death or disability).
Messrs. Chesser and Lebsack received payments under their CRIP awards equal to $166,666.67 in each of March 2022 (which are reflected in the Summary Compensation Table) and June 2023, and Mr. Lebsack remains
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eligible to earn the third installment payment of $166,666.67 within the first 90 days of 2024. For additional information about the CRIP, see the section entitled “—Potential Payments Upon Termination or Change of Control.” While we still maintain the CRIP, none of our Current Executive Officers participate in this plan.
Revised 2022 Compensation Program
Following a comprehensive review of the Company’s 2022 Compensation Program, in April 2022, the Prior Board and the Restructuring Committee implemented certain revisions to the STI Program under the 2022 Compensation Program to effectively incentivize and retain employees and to align executive compensation with the changed priorities of the Company during the Restructuring. As part of these revisions, the Prior Board and Restructuring Committee engaged WTW as independent outside compensation consultant.
Revised 2022 Short-Term Incentive Compensation Programs
Revised 2022 STI Program
In April 2022, each named executive officer other than Mr. Hernandez received an increased target STI Program opportunity as shown below in the table below. Additionally, each named executive officer was granted prepayment of his STI Program award with respect to the second, third and fourth quarters of 2022 and the first quarter of 2023 at target performance level (the “Advanced STI Bonus”), to be earned and retained subject to continued employment through March 31, 2023 and achievement of the performance targets previously approved for the 2022 STI Program or to be approved for the amount attributed to the 2023 STI Program. The Advanced STI Bonuses were subject to clawback until fully earned; no amounts paid to our named executive officers were ultimately subject to recoupment.
The table below shows the Advanced STI Bonuses paid to each named executive officer in respect of 2022 performance.
| Executive | Target STI Opportunity (% of Base Salary) | Advanced STI Bonus for Q2 – Q4 2022 Performance – Cumulative ($) | ||||||||||||
| Alejandro Hernandez | 200 | % | 1,893,000 | |||||||||||
| John Chesser | 100 | % | 386,250 | |||||||||||
| Andrew Wright | 100 | % | 386,250 | |||||||||||
| Brad Berryman | 100 | % | 389,283 | |||||||||||
| Dale Lebsack | 100 | % | 386,250 | |||||||||||
In January 2023, the Prior Board deemed all performance metrics were collectively satisfied at 135% in respect of the second, third and fourth quarters of 2022 for all corporate employees (including our named executive officers). Accordingly, the portions of the Advanced STI Bonuses paid in respect of the 2022 STI Program were deemed earned on March 31, 2023. Though reflected here, we have therefore not included them in the Summary Compensation Table for compensation earned during 2022.
2022 Revised Retention Bonus Awards
In April 2022, the Prior Board approved amendments to the Pre-Restructuring TRAs (the “Amended TRAs”), including those held by our named executive officers, with respect to the amounts, payment timing and vesting schedule of the Second TRA Installments. Under the Amended TRAs, the Second TRA Installments were paid to our executives in April 2022 and they became eligible to vest in their right to retain the Second TRA installment 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).
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The table below sets forth the value of each named executive officer’s Amended TRA opportunity:
| Executive | First TRA Installment ($) | Second TRA Installment ($) | Total Amended TRA ($) | |||||||||||||||||
| Alejandro Hernandez | 612,500 | 2,149,788 | 2,762,288 | |||||||||||||||||
| John Chesser | 250,000 | 362,260 | 612,260 | |||||||||||||||||
| Andrew Wright | 210,124 | 386,623 | 596,747 | |||||||||||||||||
| Brad Berryman | 251,964 | 365,106 | 617,070 | |||||||||||||||||
| Dale Lebsack | 175,000 | 343,082 | 518,082 | |||||||||||||||||
The Second TRA Installments under each named executive officer’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 are therefore not reported in the Summary Compensation Table as compensation earned in fiscal 2022.
Key Employee Incentive Plan (KEIP)
In August 2022, the Bankruptcy Court approved the Talen Energy Supply, LLC Key Employee Incentive Plan (the “KEIP”), pursuant to which certain key employees identified by the Prior Board, including each of our named executive officers, were eligible to earn (i) quarterly incentive payments based on achievement of business plan targets measured against performance metrics for each performance period as described below (collectively, the “Quarterly Performance Bonuses”), (ii) an incentive payment based on the expediency with which the Bankruptcy Court confirmed the Plan of Reorganization (the “Plan Confirmation Bonus”), (iii) an incentive payment based on the Company’s entry into a binding agreement to sell certain non-core assets and the proceeds earned therefore (the “Asset Sale Bonus”) and (iv) an incentive payment based on achievement of the Company’s Incremental Cash Balance performance metrics during the one-year period starting March 31, 2022 and ending March 31, 2023 (the “Cash Balance Bonus” and the incentive payments described in (i) through (iv) collectively, the “KEIP Payments”).
The potential amount payable to each named executive officer 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 named executive officer’s continued employment through payment. The performance levels, performance period and timing of payment for each component of the KEIP is set forth below:
| Metric | Weighting | Measurement Period | Performance Goals | Payout Timing | ||||||||||||||||||||||||||||||||||
| Threshold | Target | Maximum | ||||||||||||||||||||||||||||||||||||
Equivalent Forced Outage Factor(1) | 15 | % | 2Q ‘22 – 3Q ‘23 (6 quarters) | 6.60 | % | 3.30 | % | 2.30 | % | Quarterly | ||||||||||||||||||||||||||||
Safety(2) | 10 | % | 2Q ‘22 – 3Q ‘23 (6 quarters) | 0.75 | 0.3 | 0.2 | Quarterly | |||||||||||||||||||||||||||||||
| Business Plan Investment | 30 | % | 2Q ‘22 – 1Q ‘23 (4 Quarters) | 110% of Target | Business Plan Target | 90% of Target | Quarterly | |||||||||||||||||||||||||||||||
| Incremental Cash Balance | 30 | % | 2Q ‘22 – 1Q ‘23 (4 Quarters) | $0 - $120M | $482M | $751M | As soon as practicable following March 31, 2023 | |||||||||||||||||||||||||||||||
| Confirmation Timing | 15 | % | 2Q ‘22 – 1Q ‘23 (4 Quarters) | Feb. 15, 2023 | Jan. 15, 2023 | Dec. 15, 2022 | Single payment as soon as practicable after confirmation | |||||||||||||||||||||||||||||||
| Asset Sale Proceeds | N/A | 2Q ‘22 – 3Q ‘23 (6 quarters) | N/A | $0 | > $70M | 50% at execution of binding docs; 50% upon receipt of proceeds | ||||||||||||||||||||||||||||||||
__________________
(1)Equivalent Forced Outage Factor is 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 is measured as the total number of lost time injuries times 200,000 divided by the total number of hours worked.
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The table below details the threshold and maximum payout as a percentage of target for each performance metric. With respect to the Asset Sale Bonus, the KEIP provided for a payment equal to 1.9782% of the first $70 million of proceeds from consummation of any sales of non-core assets.
| Metric | KEIP Payout Range (% of Target) | |||||||||||||||||||
| Threshold | Target | Maximum | ||||||||||||||||||
| Equivalent Forced Outage Factor (EFOF) | 20 | % | 100 | % | 225 | % | ||||||||||||||
| Safety | 20 | % | 100 | % | 112.5 | % | ||||||||||||||
| Business Plan Investment | 20 | % | 100 | % | 180 | % | ||||||||||||||
| Incremental Cash Balance | 20 | % | 100 | % | 180 | % | ||||||||||||||
| Confirmation Timing | 20 | % | 100 | % | 180 | % | ||||||||||||||
| Asset Sale Proceeds | N/A | Unknown | 20% of Target (10% of Upside) | |||||||||||||||||
| Target KEIP Opportunity ($) | ||||||||||||||||||||||||||||||||||||||||||||
| Named Executive Officer | EFOF | Safety | Business Plan Investment | Cash Balance | Confirmation Timing | Asset Sale Proceeds | Total | |||||||||||||||||||||||||||||||||||||
| Alejandro Hernandez | 750,000 | 500,000 | 1,000,000 | 1,000,000 | 375,000 | — | 3,625,000 | |||||||||||||||||||||||||||||||||||||
| John Chesser | 225,000 | 150,000 | 300,000 | 300,000 | 112,500 | — | 1,087,500 | |||||||||||||||||||||||||||||||||||||
| Andrew Wright | 150,000 | 100,000 | 200,000 | 200,000 | 75,000 | — | 725,000 | |||||||||||||||||||||||||||||||||||||
| Brad Berryman | 187,500 | 125,000 | 250,000 | 250,000 | 93,750 | — | 906,250 | |||||||||||||||||||||||||||||||||||||
| Dale Lebsack | 60,000 | 40,000 | 80,000 | 80,000 | 30,000 | — | 290,000 | |||||||||||||||||||||||||||||||||||||
The Restructuring Committee certified performance achievement at 165% of target for the second and third quarters of 2022 and 179% of target for the fourth quarter of 2022 for the Quarterly Performance Bonuses (Business Plan Investment, Safety and EFOF components of the KEIP Payment). The Restructuring Committee certified maximum performance achievement for the Confirmation Timing component of the KEIP Payment, as confirmation of the Plan of Reorganization occurred on December 15, 2022. Additionally, the Restructuring Committee certified performance achievement at 70% of target for the first quarter of 2023. Pursuant to their separation agreements, each of Messrs. Hernandez and Chesser received prorated payments under the KEIP for the second quarter of 2023 through the date of Emergence equal to $76,449 and $22,935, respectively. Payments made to our named executive officers under the KEIP are shown in the table directly below, and the aggregate payments made under the KEIP during 2022 are reported in the Summary Compensation Table below.
| Quarterly Bonus Payouts | Plan Confirmation Bonus | |||||||||||||||||||||||||
| Named Executive Officer | Q2 and Q3 2022 | Q4 2022 | Q1 2023 | |||||||||||||||||||||||
| Alejandro Hernandez | $ | 1,510,721 | $ | 821,625 | $ | 150,178 | $ | 603,571 | ||||||||||||||||||
| John Chesser | $ | 453,216 | $ | 246,488 | $ | 45,054 | $ | 181,071 | ||||||||||||||||||
| Andrew Wright | $ | 302,144 | $ | 164,325 | $ | 30,036 | $ | 120,714 | ||||||||||||||||||
| Brad Berryman | $ | 377,680 | $ | 205,406 | $ | 37,545 | $ | 150,893 | ||||||||||||||||||
| Dale Lebsack | $ | 120,858 | $ | 65,730 | $ | 12,014 | $ | 54,000 | ||||||||||||||||||
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, and (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-
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revocation of the general release of claims and continued abidance by the restrictive covenant obligations under his employment agreement.
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 a 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.
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; 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, during 2022, following a comprehensive review of security risks, we implemented a security program for Mr. Hernandez in recognition of certain risks identified in connection with his employment. These security arrangements 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, Offer Letters and Restrictive Covenant Agreements
With respect to 2022, each of the named executive officers was party to an employment agreement or offer letter (each, a “Prior Employment Agreement”) with the Company, each providing for base salary and annual cash bonus, and participation in long-term incentive plans and the same benefit plans and programs in which our other similarly situated employees are eligible to participate, each, as described above.
Pursuant to the terms of his Prior Employment Agreement, Mr. Hernandez is subject to a perpetual covenant not to disclose confidential information and a covenant regarding the assignment of intellectual property. He is also subject to a non-competition covenant and employee and customer solicitation covenants, in each instance for a period extending through the 12-month anniversary of his termination of employment.
Mr. Chesser is party to a Non-Competition, Non-Solicitation and Confidentiality Agreement with the Company pursuant to which he is subject to a perpetual covenant not to disclose confidential information, a covenant regarding the assignment of intellectual property, and a non-competition covenant and employee and customer solicitation covenants, in each instance for a period extending through the 6-month anniversary of his termination of employment. Messrs. Wright, Berryman and Lebsack were also party to restrictive covenant agreements with the same terms, which were superseded by the restrictive covenant provisions of employment agreements each executed in connection with Emergence, as described below under “—2023 Compensation—Employment Agreements.”
The severance and change of control provisions of the Prior Employment Agreements, are described in more detail in the section entitled “—Potential Payments Upon Termination or Change of Control.”
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Stock Ownership Guidelines
Our executive officers have not been subject to mandated stock ownership guidelines. However, 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. In connection with our public listing, we expect to establish guidelines of equity ownership for our Chief Executive Officer equivalent to three times his base salary and for our other executive officers equivalent to one times their respective base salaries. 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 who received such equity awards in 2023 to meet this requirement.
Prohibition on Hedging
In connection with our public listing, we have adopted a 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 also 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.
Clawback Policy
In connection with our public listing, we expect to adopt a “clawback” policy that is compliant with Section 10D of the Securities and Exchange Act, as well as Nasdaq exchange rules related thereto.
Compensation Committee Interlocks and Insider Participation
The Company did not have a compensation committee during the 2022 fiscal year and there were no insider participations or interlocks among current or former officers or employees who participated in the deliberations of the Board concerning executive officer compensation during 2022. Additionally, there are currently no insider participations or compensation committee interlocks among our compensation committee.
Impact of Accounting and Tax Requirements on Compensation
The Current Board and our compensation committee consider tax deductibility and other tax implications when designing the 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 named executive officers as it deems appropriate and in furtherance of its 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.
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2022 Summary Compensation Table
The following table sets forth certain information with respect to compensation for the year ended December 31, 2022 earned by, awarded to or paid to our named executive officers.
| Name and Principal Position | Year | Salary ($) | Non-Equity Incentive Plan Compensation ($)(1) | All Other Compensation ($)(2) | Total ($) | |||||||||||||||||||||||||||
| Alejandro Hernandez, | ||||||||||||||||||||||||||||||||
| Former Chief Executive Officer | 2022 | 1,254,683 | 4,147,748 | 1,807,975 | 7,210,406 | |||||||||||||||||||||||||||
| John Chesser, | ||||||||||||||||||||||||||||||||
| Former Chief Financial Officer | 2022 | 516,473 | 1,358,599 | 28,355 | 1,903,427 | |||||||||||||||||||||||||||
| Andrew Wright, | ||||||||||||||||||||||||||||||||
| Former General Counsel and Corporate Secretary (now Chief Administrative Officer) | 2022 | 501,136 | 858,463 | 21,414 | 1,381,014 | |||||||||||||||||||||||||||
| Brad Berryman, | ||||||||||||||||||||||||||||||||
| Senior Vice President and Chief Nuclear Officer | 2022 | 520,530 | 1,059,907 | 20,753 | 1,601,190 | |||||||||||||||||||||||||||
| Dale Lebsack, | ||||||||||||||||||||||||||||||||
| Former Senior Vice President, Fossil Operations (now Chief Fossil Officer) | 2022 | 432,681 | 633,970 | 20,040 | 1,086,691 | |||||||||||||||||||||||||||
__________________
(1)The amounts in this column reflect the cash amounts payable and earned in 2022 under the Company’s 2022 STI Program, TRAs, KEIP and CRIP. Amounts earned and paid out in April 2022 under the 2022 STI Program are reported in this table, however, the amounts paid out in April 2022 under the Revised 2022 STI Program are not reportable in this table because they were not earned until March 31, 2023. Amounts in respect of the First TRA Installment that were paid out in November 2021 and earned in November 2022 are reported in this table, however, the amounts paid out on April 29, 2022 in respect of the Second TRA Installment are not reportable in this table because they were not earned until June 17, 2023 (or May 17, 2023 with respect to Mr. Hernandez pursuant to his separation agreement). For additional information about these short-term incentive programs, see “—2022 Compensation Program—Pre-Emergence Short-Term Incentive Programs,” “—2022 Compensation Program—2022 Long-Term Compensation Programs—Commercial and Risk Team Long-Term Incentive Plan,” and “—Revised 2022 Compensation Program—Revised 2022 Short-Term Incentive Compensation Programs.”
(2)The amount in this column reflect the following:
(a)For Mr. Hernandez, (i) a $1,710 payment for the cost of premiums for a term life insurance policy paid by us, (ii) $11,754 employer contribution to the 401(k) plan in Mr. Hernandez’s name, (iii) a $1,200 contribution to Mr. Hernandez’s health savings account and (iv) $1,793,311 to reflect the aggregate incremental cost of the personal security arrangements implemented following the security review described under “—Other Executive Benefits and Perquisites.”
(b)For Mr. Chesser, (i) an $810 payment for the cost of premiums for a term life insurance policy paid by us, (ii) $18,300 employer contribution to the 401(k) plan in Mr. Chesser’s name, (iii) a $1,200 contribution to Mr. Chesser’s health savings account and (iv) an $8,045 payment for the cost of health and welfare benefits for Mr. Chesser’s dependent.
(c)For Mr. Wright, (i) a $1,914 payment for the cost of premiums for a term life insurance policy paid by us, (ii) $18,300 employer contribution to the 401(k) plan in Mr. Wright’s name and (iii) a $1,200 contribution to Mr. Wright’s health savings account.
(d)For Mr. Berryman, (i) a $1,253 payment for the cost of premiums for a term life insurance policy paid by us, (ii) $18,300 employer contribution to the 401(k) plan in Mr. Berryman’s name, and (iii) a $1,200 contribution to Mr. Berryman’s health savings account.
(e)For Mr. Lebsack, (i) a $540 payment for the cost of premiums for a term life insurance policy paid by us, (ii) $18,300 employer contribution to the 401(k) plan in Mr. Lebsack’s name and (iii) a $1,200 contribution to Mr. Lebsack’s health savings account.
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2022 Grants of Plan-Based Awards
The following table sets forth certain information with respect to grants of plan-based awards for the year ended December 31, 2022 with respect to our named executive officers.
| Estimated Possible Payouts Under Non-Equity Incentive Plan Awards | ||||||||||||||||||||||||||||||||
| Name | Grant Type | Grant Date | Threshold ($) | Target ($) | Maximum ($) | |||||||||||||||||||||||||||
| Alejandro Hernandez | 2022 STI (1) | April 22, 2022 | — | 2,523,500 | — | |||||||||||||||||||||||||||
Advanced STI Bonus (2) | April 29, 2022 | — | 2,523,500 | — | ||||||||||||||||||||||||||||
Amended TRA (3) | April 29, 2022 | — | 2,149,788 | — | ||||||||||||||||||||||||||||
KEIP (4) | August 15, 2022 | 925,524 | 3,625,000 | 7,250,000 | ||||||||||||||||||||||||||||
| John Chesser | 2022 STI (1) | April 22, 2022 | — | 257,500 | — | |||||||||||||||||||||||||||
Advanced STI Bonus (2) | April 29, 2022 | — | 529,163 | — | ||||||||||||||||||||||||||||
Amended TRA (3) | April 29, 2022 | — | 362,260 | — | ||||||||||||||||||||||||||||
KEIP (4) | August 15, 2022 | 277,657 | 1,087,500 | 2,175,001 | ||||||||||||||||||||||||||||
| Andrew Wright | 2022 STI (1) | April 22, 2022 | — | 257,500 | 515,000 | |||||||||||||||||||||||||||
Advanced STI Bonus (2) | April 29, 2022 | — | 529,163 | 1,058,325 | ||||||||||||||||||||||||||||
Amended TRA (3) | April 29, 2022 | — | 386,623 | — | ||||||||||||||||||||||||||||
KEIP (4) | August 15, 2022 | 185,105 | 725,000 | 1,450,002 | ||||||||||||||||||||||||||||
| Brad Berryman | 2022 STI (1) | April 22, 2022 | — | 311,427 | — | |||||||||||||||||||||||||||
Advanced STI Bonus (2) | April 29, 2022 | — | 533,319 | — | ||||||||||||||||||||||||||||
Amended TRA (3) | April 29, 2022 | — | 365,106 | — | ||||||||||||||||||||||||||||
KEIP (4) | August 15, 2022 | 231,381 | 906,250 | 1,812,499 | ||||||||||||||||||||||||||||
| Dale Lebsack | 2022 STI (1) | April 22, 2022 | — | 217,750 | — | |||||||||||||||||||||||||||
Advanced STI Bonus (2) | April 29, 2022 | — | 462,375 | — | ||||||||||||||||||||||||||||
Amended TRA (3) | April 29, 2022 | — | 343,082 | — | ||||||||||||||||||||||||||||
KEIP (4) | August 15, 2022 | 74,042 | 290,000 | 580,002 | ||||||||||||||||||||||||||||
__________________
(1)Amounts shown represent the aggregate payout opportunity under the 2022 STI for fiscal 2022. The 2022 STI was to be paid out on a quarterly basis throughout fiscal 2022. Because the named executive officers were identified as “insiders” for purposes of the anticipated Restructuring, their 2022 STI opportunity could be paid out only at target, so no threshold or maximum opportunities are reported in the table. The first quarterly payout under the 2022 STI was made on April 22, 2022 at target as follows: $599,331; $61,156; $61,156; $73,964; and $51,716 for Messrs. Hernandez, Chesser, Wright, Berryman and Lebsack, respectively. On April 22, 2022, the 2022 STI was accelerated with respect to the second, third and fourth quarters of fiscal 2022, subject to clawback in certain circumstances, and STI Program target opportunities were increased for each named executive officer except for Mr. Hernandez. The accelerated components of the 2022 STI are reported in the table for each named executive officer as the “Advanced STI Bonus.” For additional information, see section entitled “—2022 Compensation Program—Short-Term Incentive Cash Bonuses—2022 STI Program.”
(2)Reflects Advanced 2022 STI awards granted in the form of pre-paid cash bonuses pursuant to the 2022 STI Program on April 29, 2022 to replace the previously granted 2022 STI awards with respect to the second, third and fourth quarters of fiscal 2022 and in respect of the first quarter of fiscal 2023. The Advanced STI Bonuses were paid out based on target performance achievement and were subject to repayment by the executive to the extent performance targets were not satisfied (based on performance metrics set for the 2022 STI or that will be set for the 2023 STI (as applicable)) and upon certain terminations of employment prior to March 31, 2023. For additional information, see section entitled “—Revised 2022 Compensation Program—Revised 2022 Short-Term Incentive Compensation—Revised 2022 STI Program.”
(3)Reflects payments made under the Amended TRAs on April 29, 2022, which replaced the Pre-Restructuring TRAs granted to our named executive officers on November 4, 2021, and were subject to repayment upon certain terminations of employment until the earliest of (i) December 31, 2023, (ii) the date that is 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). These payments fully vested on June 17, 2023 (60 days following Emergence) (or May 17, 2023 for
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Mr. Hernandez pursuant to his separation agreement). For additional information, see section entitled “—Revised 2022 Compensation Program—Revised 2022 Short-Term Incentive Compensation—2022 Revised Talen Retention Bonus Awards.”
(4)Reflects awards made under the KEIP to each of our named executive officers. For additional information, see section entitled “—Revised 2022 Compensation Programs—Revised 2022 Short-Term Incentive Compensation—Key Employee Incentive Plan (KEIP).”
Outstanding Equity Awards At 2022 Fiscal Year End
While the equity awards granted by our affiliates and described under “—2022 Compensation Program—2022 Long-Term Compensation Program—2022 Long-Term Equity-Based Compensation” remained outstanding as of December 31, 2022, each of these awards had a value of $0 as of such date, and the MidCo Incentive Units have since been cancelled for no consideration.
Options Exercised and Stock Vested
No equity awards fully vested during the fiscal year ended December 31, 2022 with respect to our named executive officers.
Pension Benefits
Our named executive officers did not participate in or have account balances in qualified or nonqualified defined benefit plans sponsored by us. The Current Board or compensation committee may elect to adopt qualified or nonqualified benefit plans in the future if it determines that doing so is in our best interest.
Nonqualified Deferred Compensation
Our named executive officers 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 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
As of December 31, 2022, each of our named executive officers was eligible to receive certain payments or benefits upon a termination of employment or in connection with a change in control pursuant to their individual arrangements as described below.
Pursuant to Mr. Hernandez’s Pre-Emergence Employment Agreement and Messrs. Berryman’s and Lebsack’s pre-Emergence severance letter agreements each dated November 15, 2021, upon a termination by the Company without “Cause” or by the named executive officer with “Good Reason” as of December 31, 2022, each named executive officer would have been entitled to a cash payment equal to 12 months of annual base salary and annual target cash bonus, as well as reimbursement for the cost of COBRA coverage premiums for 12 months following termination, in each case, subject to the execution and non-revocation of a release of claims by the named executive officer and continued compliance with restrictive covenant obligations. Pursuant to their pre-Emergence offer letters, Messrs. Wright and Chesser would have been entitled to a lump sum payment equal to the sum of the named executive officers’ s annual base salary, target bonus and 12 months of COBRA premiums. Additionally, each named executive officer would have become fully vested in the Second TRA Installment under the Amended TRA as of the date of termination.
Pursuant to the CRIP, in the event of a change in control occurring on December 31, 2022, Messrs. Chesser and Lebsack would have fully vested in and received their second and third CRIP installment payments.
Additionally, the MidCo Incentive Units held by each of our named executive officers and the Raven Power Incentive Units held by Mr. Hernandez as of December 31, 2022 were subject to certain vesting acceleration treatment upon qualifying terminations of employment or change in control transactions. However, these equity interests had a value of $0 as of December 31, 2022, so no named executive officer would have received payment or otherwise benefited from any such termination or change in control event if it were to have occurred on December 31, 2022.
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Director Compensation
The table below provides information on the compensation of our non-employee directors for board of director service either at the Company or TES during the year ended December 31, 2022. As required by applicable SEC rules, the disclosure in this section covers all persons who at any time served as a director during 2022, other than Mr. Hernandez, who served as our President and Chief Executive Officer and received no additional compensation for serving as director. Other than as set forth in the table and described more fully below, we did not pay any compensation, reimburse any expense of, or make any equity awards or non-equity awards to, or pay any other compensation to, any of the other non-employee members of the Board in 2022.
| Name | Fees Earned or Paid in Cash ($) (1) | |||||||
| Carol Flaton | 450,000 | |||||||
Gary Wojtaszek (2) | 354,435 | |||||||
__________________
(1)Our non-employee directors received a monthly cash fee of $37,500 for each full month of service during 2022, as well as a pro-rated monthly fee for the initial month of service.
(2)Mr. Wojtaszek was appointed to the Prior Board in March 2022 and received a pro-rated monthly fee in respect of his services for such month.
Post-Emergence 2023 Director Compensation
Upon Emergence, the Current Board approved a new director compensation program for directors of the Company. Annual director fees for fiscal 2023 were set at $100,000 payable in cash quarterly in arrears. In addition to annual fees, directors serving on standing committees of the Current Board were paid as follows: an additional $10,000 for the audit committee members (or $20,000 for the Chair of the audit committee); an additional $7,500 for the nominating and corporate governance committee members (or $15,000 for the Chair of the nominating and corporate governance committee); and an additional $10,000 for the compensation committee members (or $15,000 for the Chair of the compensation committee). The independent Chair of the Current Board also receives an annual retainer in the amount of $100,000 (in addition to the standard annual director fees received by the independent Chair of the Current Board), payable in cash quarterly in arrears (or in restricted stock units with a one-year cliff).
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 2025, 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 directors service on the Current Board for any reason, all unvested RSUs will be forfeited. Upon the occurrence of a Change in Control, all unvested RSUs held by non-employee directors will immediately vest.
In addition to the fees and grant above, the Non-Executive Director 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 Executive Officers (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 (as defined in the 2023 Equity Plan). Mr. Schaefer also may not sell or transfer any of the shares of Company common stock received upon vesting of his PSUs until the earlier of a Change in Control or the third anniversary of Emergence. 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 employed with 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 Company 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.
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 years ended December 31, 2022 and 2021, and the six months ended June 30, 2023, amounts invested by TES to these joint ventures were $5 million, $2.6 million and $0.5 million, respectively.
Cumulus Investments
Cumulus Digital Holdings; Riverstone Buyout
TES owns certain direct and 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, 2022 and June 30, 2023 was $114 million and $140 million, respectively. TES, Talen Growth and Riverstone initially became owners of common equity units of Cumulus Digital Holdings (the “Cumulus 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 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 Units from Riverstone in exchange for $1 million in cash. From September 2022 through June 30, 2023, TES and Talen Growth’s combined interest in Cumulus Digital Holdings increased to 81% as a result of incremental investments by TES, and Riverstone interest decreased to 14%.
In September 2023, Riverstone sold all of their Cumulus Units to TES and affiliates of Orion in exchange for $20 million in cash (the “Riverstone Buyout”). As a result of the Riverstone Buyout, TES and Talen Growth’s
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combined 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 September 30, 2023, TES owns 95% of Cumulus Digital Holdings.
See the historical financial statements of TEC and TES and the 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. 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 leased by Nautilus from Cumulus Data. Under the terms of the lease, among other things, Cumulus Data submeters 150 MW of electric power to Nautilus in exchange for supplemental rent payments. The lease has an initial term that expires on July 1, 2027, renewable at Nautilus’ option. The power is 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 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. See Note 2 in Notes to the Interim Financial Statements for more information. 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.
Nautilus generally liquidates Bitcoin within one business day to meet its operating requirements. 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.
Nautilus’ miners are insured, and it does not host miners operated or owned by third parties. The average hash rate of the miners was approximately five exahashes per second and the average time in service was approximately four months, as of June 30, 2023. Since the facility became operational in the first quarter of 2023 through September 30, 2023, the amount of Bitcoin mined each month ranged from approximately 328 to 450, with an average of approximately 350 Bitcoin per month.
Energy Supply Agreements
Cumulus Data, a subsidiary of Cumulus Digital Holdings, is party to the following two separate agreements with Talen Generation for energy supply from Susquehanna Nuclear: (i) an agreement for up to 300 MW which supports Cumulus Data’s obligation to provide submetered power to Nautilus under a ground lease agreement (the “Coin PPA”); and (ii) a separate option agreement for up to 650 MW which will support Cumulus Data’s anticipated obligations to provide submetered power under lease agreements with data center tenants (the “Campus PPA”). As of the date of hereof, Cumulus Data has elected to receive 150 MW under the Coin PPA and has not elected to
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receive any power under the Campus PPA. Talen Generation’s obligation to supply power to Cumulus Data under each of the agreements is backstopped by wholesale energy supply agreements with Susquehanna Nuclear on substantially the same terms as the Coin PPA and the Campus PPA, respectively.
Delivery of power under the Coin PPA, together with the five-year initial term of the agreement, commenced in February 2023. The agreement includes two three-year renewal options at Cumulus Data’s election. Cumulus Data may also elect to increase its capacity under the Coin PPA to up to 300 MW as necessary to support Nautilus’ operations under the ground lease. At this time, however, Cumulus Coin has no intention to expand Nautilus’ operations above 150 MW.
During the initial term of the Coin PPA, Talen Generation sells the first 100 MW to Cumulus Data at a price of $28.00 per MWh, and the next 50 MW at a price of $44.05 per MWh. The price for power on any additional capacity and/or during any renewal term will be fixed at the time of election based on a combination of the then-forward locational marginal price of power and auction-clearing capacity pricing at Susquehanna during the remainder of the initial term or renewal term, as applicable. The price for power is also subject to adjustment when the outstanding indebtedness under the Cumulus Digital TLF is reduced to $100 million or less or is refinanced (the “Reset Date”). At such time, the price will be adjusted to a then-current market price as determined by an independent third party plus, to the extent Susquehanna cannot then claim nuclear energy production tax credits for energy delivered under the agreement due to Cumulus Data being an affiliate, the statutory rate otherwise available for such credits (the “Lost PTC Amount”).
Under the terms of the Campus PPA, Cumulus Data has the option to purchase up to 650 MW of power from Talen Generation at a market-based fixed rate to be determined at the time of election. Cumulus Data has until September 2026 to exercise the option. The initial term of the Campus PPA will be seven years from the exercise date, with two three-year renewal options at Cumulus Data’s election. If the initial amount of capacity elected by Cumulus Data under the Campus PPA is less than 650 MW, Cumulus Data may elect to increase its capacity from time to time up to a maximum of 650 MW.
The price for power under the Campus PPA will be fixed at the time of exercise (in the case of the initial election or any optional increase in capacity) and/or renewal election (in the case of any renewal term) based upon a combination of the then-forward locational marginal price of power and auction-clearing capacity pricing at Susquehanna plus the Lost PTC Amount, if any, subject to a floor of $27 per MWh at all times and, prior to the Reset Date, a cap of $40 per MWh.
No revenue was recognized under either the Coin PPA or the Campus PPA during the years ended December 31, 2022 and December 31, 2021. Revenue under the Coin PPA was $13.1 million for the six months ended June 30, 2023.
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 by which projected amounts payable by Cumulus Data under the Coin PPA following the projected Reset Date would exceed the price in effect thereunder prior to the Reset Date for the remainder of the initial term.
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 by which the projected amounts payable by Cumulus Data under the Campus PPA (as amended in connection with the TEC Global Settlement) during the initial term would exceed the amounts payable under the terms of the Campus PPA as in effect prior to such amendment. 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.
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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. Cash payment of fees and expenses under the agreement is 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 has 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 years ended December 31, 2021 and December 31, 2022, and for the six months ended June 30, 2023, were $3.0 million, $14.6 million and $10.6 million, respectively, of which $26.3 million was converted to additional common units in Cumulus Digital Holdings in June 2023.
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’ 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 $45,000 and $3.2 million for the year ended December 31, 2022 and the six months ended June 30, 2023, respectively.
Letters of Credit Supporting Cumulus Digital TLF and Reimbursement Agreement
As of December 31, 2022, TES provided $50 million in LCs to support certain of Cumulus Digital’s obligations under the Cumulus Digital TLF. The LCs can be drawn upon, among other events: the acceleration of the loan due to an event of default or the bankruptcy of Cumulus Digital. The amount of the LCs will be decreased from time to time based on the outstanding principal balance of the Cumulus Digital TLF. In the event that the LCs are drawn, Cumulus Digital Holdings has agreed to issue additional common equity to TES to reimburse it for the amount drawn. Cumulus Digital has agreed to reimburse TES for fees associated with the LCs, with payment of such amounts 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 will have the option to receive payment for the deferred fees 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 years ended December 31, 2021 and December 31, 2022, and for the six months ended June 30, 2023, were $324,000, $2.6 million and $1.4 million, respectively, of which $3.7 million was converted to additional common units in Cumulus Digital Holdings in June 2023.
Guaranty of Cumulus Digital TLF
TEC has 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 will terminate if the principal amount of loans outstanding is reduced to $50 million or less. Amounts are not payable under the guarantee until all available amounts under the TES LCs described above have been drawn.
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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 party thereto 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”) so long as the aggregate Company ownership represented on the Offering Committee is at least 20% and have rights to require the Company to pursue and consummate 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.
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 Campus 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”).
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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 October 19, 2023 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 59,028,843 shares of common stock outstanding as of October 19, 2023. 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 October 19, 2023 or issuable pursuant to RSUs that vest within 60 days of October 19, 2023. 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) | 13,782,407 | 23 | % | 23 | % | 13,782,407 | — | — | ||||||||||||||||||||||||||||||
Monarch Alternative Capital LP(4) | 3,845,105 | 6.5 | % | 6.5 | % | 3,845,105 | — | — | ||||||||||||||||||||||||||||||
Capital Research and Management Company(5) | 3,099,169 | 5.3 | % | 5.3 | % | 3,099,169 | — | — | ||||||||||||||||||||||||||||||
| Named Executive Officers and Directors | ||||||||||||||||||||||||||||||||||||||
Mark “Mac” McFarland(6)(7)(8) | ||||||||||||||||||||||||||||||||||||||
Stephen Schaefer(6)(9) | ||||||||||||||||||||||||||||||||||||||
Gizman Abbas(6)(10) | ||||||||||||||||||||||||||||||||||||||
Anthony Horton(6)(11) | ||||||||||||||||||||||||||||||||||||||
Karen Hyde(6)(12) | ||||||||||||||||||||||||||||||||||||||
Joseph Nigro(6)(13) | ||||||||||||||||||||||||||||||||||||||
Christine Benson Schwartzstein(6)(14) | ||||||||||||||||||||||||||||||||||||||
Terry Nutt(7)(15) | ||||||||||||||||||||||||||||||||||||||
Andrew Wright(7)(16) | ||||||||||||||||||||||||||||||||||||||
John Wander(7)(17) | ||||||||||||||||||||||||||||||||||||||
All directors and executive officers as a group (10 persons)(18) | ||||||||||||||||||||||||||||||||||||||
| Other Selling Stockholders | ||||||||||||||||||||||||||||||||||||||
FIG LLC(19) | 2 | 2,813,652 | 4.8 | % | 4.8 | % | 2,813,652 | — | — | — | ||||||||||||||||||||||||||||
Sachem Head Capital Management LP(20) | 2,440,000 | 4.1 | % | 4.1 | % | 2,440,000 | — | — | — | |||||||||||||||||||||||||||||
Citadel Advisors LLC(21) | 2,376,772 | 4.0 | % | 4.0 | % | 2,376,772 | — | — | — | |||||||||||||||||||||||||||||
Entities Affiliated with CQS (UK) LLP(22) | 2,260,643 | 3.8 | % | 3.8 | % | 2,260,643 | — | — | — | |||||||||||||||||||||||||||||
Carronade Capital Management, LP(23) | 2,100,980 | 3.6 | % | 3.6 | % | 2,100,980 | — | — | — | |||||||||||||||||||||||||||||
Nuveen Asset Management LLC(24) | 1,844,267 | 3.1 | % | 3.1 | % | 1,844,267 | — | — | — | |||||||||||||||||||||||||||||
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Parsifal Capital Management, LP(25) | 1,716,738 | 2.9 | % | 2.9 | % | 1,716,738 | — | — | — | |||||||||||||||||||||||||||||
Two Seas Capital LP(26) | 1,455,108 | 2.5 | % | 2.5 | % | 1,455,108 | — | — | — | |||||||||||||||||||||||||||||
P. Schoenfeld Asset Management LP(27) | 1,363,468 | 2.3 | % | 2.3 | % | 1,363,468 | — | — | — | |||||||||||||||||||||||||||||
Glendon Capital Management, L.P.(28) | 1,280,711 | 2.2 | % | 2.2 | % | 1,280,711 | — | — | — | |||||||||||||||||||||||||||||
Lord Abbett & Co. LLC(29) | 960,210 | 1.6 | % | 1.6 | % | 960,210 | — | — | — | |||||||||||||||||||||||||||||
Franklin Advisers, Inc.(30) | 888,808 | 1.5 | % | 1.5 | % | 888,808 | — | — | — | |||||||||||||||||||||||||||||
J. Rothschild Capital Management Limited(31) | 841,980 | 1.4 | % | 1.4 | % | 841,980 | — | — | ||||||||||||||||||||||||||||||
Entities Affiliated with Riverstone Holdings LLC(32) | 833,701 | 1.4 | % | 1.4 | % | 833,701 | — | — | ||||||||||||||||||||||||||||||
Atalan Capital Partners, LP(33) | 820,120 | 1.4 | % | 1.4 | % | 820,120 | — | — | — | |||||||||||||||||||||||||||||
PointState Capital LP(34) | 814,929 | 1.4 | % | 1.4 | % | 814,929 | — | — | — | |||||||||||||||||||||||||||||
Sculptor Capital Management, Inc.(35) | 770,908 | 1.3 | % | 1.3 | % | 770,908 | — | — | — | |||||||||||||||||||||||||||||
Yost Capital Management, LP(36) | 705,969 | 1.2 | % | 1.2 | % | 705,969 | — | — | — | |||||||||||||||||||||||||||||
Oaktree Capital Management, L.P.(37) | 643,828 | 1.1 | % | 1.1 | % | 643,828 | — | — | ||||||||||||||||||||||||||||||
Philosophy Capital Management, LLC(38) | 606,420 | 1.0 | % | 1.0 | % | 606,420 | — | — | — | |||||||||||||||||||||||||||||
CastleKnight Management LP(39) | 408,924 | * | * | 408,924 | — | — | — | |||||||||||||||||||||||||||||||
Glenview Capital Management, LLC(40) | 257,529 | * | * | 257,529 | — | — | — | |||||||||||||||||||||||||||||||
Jefferies Financial Group, Inc.(41) | 246,133 | * | * | 246,133 | — | — | — | |||||||||||||||||||||||||||||||
FourWorld Capital Management LLC(42) | 239,367 | * | * | 239,367 | — | — | — | |||||||||||||||||||||||||||||||
Hartree Partners GP, LLC(43) | 150,000 | * | * | 150,000 | — | — | — | |||||||||||||||||||||||||||||||
Corbin Capital Partners, L.P.(44) | 139,292 | * | * | 139,292 | — | — | — | |||||||||||||||||||||||||||||||
ACR Alpine Capital Research, LLC(45) | 102,157 | * | * | 102,157 | — | — | ||||||||||||||||||||||||||||||||
The Goldman Sachs Group, Inc.(46) | 40,282 | * | * | 40,282 | — | — | — | |||||||||||||||||||||||||||||||
BofA Securities, Inc.(47) | 27,695 | * | * | 27,695 | — | — | — | |||||||||||||||||||||||||||||||
__________________
*Represents beneficial ownership of less than 1%.
(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) 8,981,221 shares held by Rubric Capital Master Fund LP, (ii) 3,173,129 shares held by Rubric BSR Fund LLC, (iii) 849,918 shares of common stock held by Blackstone CSP-MST FMAP Fund and (iv) 778,139 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) 1,939,025 shares held by Monarch Capital Master Partners V LP, (ii) 745,309 shares held by Monarch Capital Master Partners VI LP, (iii) 57,306 shares held by Monarch Customized Opportunistic Fund – Series 1 LP, (iv) 524,056 shares held by Monarch Debt Recovery Master Fund Ltd and (v) 579,409 shares held by Monarch V Select Opportunities Master Fund LP (collectively, the “Monarch Funds”). Monarch Alternative Capital LP Capital is the beneficial owner of the Company’s common stock and has been
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delegated the power to vote and dispose of the shares on behalf of the Monarch Funds. MDRA GP LP and Monarch GP LLC share 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.
(5)Consists of (i) 356 shares held by American Funds Insurance Series - Capital World Bond Fund, (ii) 2,242,027 shares held by American High-Income Trust, (iii) 109,720 shares held by American Funds Insurance Series – American High-Income Trust, (iv) 372,237 shares held by American Funds Multi-Sector Income Fund, (v) 368,879 shares held by The Income Fund of America and (vi) 5,950 shares held by Capital Group U.S. High-Yield Trust (US). Capital Research and Management Company (“CRMC”) is the investment adviser for American Funds Insurance Series – Capital World Bond Fund, American High-Income Trust, American Funds Insurance Series – American High-Income Trust, American Funds Multi-Sector Income Fund, The Income Fund of America and Capital Group U.S High-Yield Trust (US) (collectively, the “CRMC Funds”). CRMC may be deemed to be the beneficial owner of the shares held by each CRMC Fund; however, CRMC expressly disclaims that it is, in fact, the beneficial owner of such securities. Philip Chitty, Andrew A. Cormack and Thomas Reithinger, as portfolio managers, have voting or investment control over the shares held by American Funds Insurance Series – Capital World Bond Fund. 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). 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. The address of American Funds Insurance Series – Capital World Bond Fund, American High-Income Trust and American Funds Insurance Series – American High-Income Trust is 333 South Hope, 55th Floor, Los Angeles, CA 90071-1406. The address of American Funds Multi-Sector Income Fund, The Income Fund of America and Capital Group U.S. High-Yield Trust (US) is 6455 Irvine Center Drive, Irvine, CA 92618.
(6)Director of the Company.
(7)Named executive officer of the Company.
(8)
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(19)Consists of (i) 994,249 shares held by CF TLNE LP and (ii) 1,819,403 shares held by CF TLNE 2023 LP. 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 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
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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 Selling Stockholder holds and beneficially owns all of the Shares, 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 Selling Stockholder. As the Co-Chief Investment Officers of the Selling Stockholder (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 Selling Stockholder, but each of them disclaims beneficial ownership thereof. The address of each of CF TLNE LP and CF TLNE 2023 LP is Corporation Trust Center, 1209 Orange Street, Wilmington, DE 19801.
(20)Consists of (i) 1,299,802 shares held by Sachem Head LP, (ii) 745,198 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 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.
(21)Consists of 2,376,531 shares held by Citadel Credit Master Fund LLC. Citadel Advisors LLC is the manager of Citadel Credit Master Fund LLC. Citadel Advisors Holdings LP is the sole member of Citadel Advisors LLC. Citadel GP LLC is the General Partner of Citadel Advisors Holdings LP. Kenneth Griffin owns a controlling interest in Citadel GP LLC. Mr. Griffin, as the owner of a controlling interest in Citadel GP LLC, may be deemed to have shared power to vote and/or shared power to dispose of the securities held by Citadel Credit Master Fund LLC. This disclosure shall not be construed as an admission that Mr. Griffin or any of the Citadel related entities listed above is the beneficial owner of any securities of the Company other than the securities actually owned by such person (if any). The business address of Citadel Credit Master Fund LLC is c/o Citadel Enterprise Americas LLC, Southeast Financial Center, 200 S. Biscayne Blvd., Suite 3300, Miami, Florida 33131.
(22)Consists of (i) 175,382 shares held by Barclays Bank plc, acting as prime broker for CQS ACS Fund, a sub-fund of CQS Global Funds ICAV (“CQS ACS”), the beneficial owner of such shares, (ii) 40,000 shares held by BNP Paribas, acting as prime broker for CQS ACS, the beneficial owner of such shares, (iii) 1,523,608 shares held by Barclays Bank plc, acting as prime broker for CQS Directional Opportunities Master Fund Limited (“CQS Directional”), the beneficial owner of such shares and (iv) 521,653 shares held by Barclays Bank plc, acting as prime broker for BIWA Fund Limited (“BIWA” and, together with CQS ACS and CQS Directional, the “CQS Funds”), the beneficial owner of such shares. Barclays Bank plc and BNP Paribas, as applicable, hold voting and dispositive power over the shares beneficially owned by the CQS Funds. The address of each of the CQS Funds is 1 Churchill Place, London, E14 5HP, United Kingdom.
(23)Consists of 2,100,980 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.
(24)Consists of (i) 32,449 shares held by Nuveen All-American Municipal Bond Fund, (ii) 22,007 shares held by Nuveen Enhanced High Yield Municipal Bond Fund, (iii) 83,051 shares held by Nuveen High Yield Municipal Opportunities Fund LP, (iv) 19,613 shares held by Nuveen Dynamic Municipal Opportunities Fund, (v) 1,330,343 shares held by Nuveen High Yield Municipal Bond Fund, (vi) 94,500 shares held by
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Nuveen Municipal Credit Opportunities Fund, (vii) 100,100 shares held by Nuveen Short Duration High Yield Municipal Bond Fund, (viii) 12,994 shares held by Nuveen Strategic Municipal Opportunities Fund, (ix) 1,116 shares held by Nuveen AMT-Free Municipal Value Fund, (x) 140,133 shares held by Nuveen AMT-Free Municipal Credit Income Fund, (xi) 654 shares held by SPDR Nuveen Bloomberg High Yield Municipal Bond ETF, (xii) 2,350 shares held by Nuveen Municipal High Income Opportunity Fund, (xiii) 716 shares held by Nuveen Pennsylvania Quality Municipal Income Fund, (xiv) 4,154 shares held by Nuveen Municipal Credit Income Fund and (xv) 87 shares held by Aspiriant Risk-Managed Municipal Bond Fund Muni Sleeve (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 owners 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.
(25)Consists of (i) 1,379,555 shares held by Parsifal Master Fund Ltd. and (ii) 10,468 shares of common stock held by Parsifal Co-Invest I, LP. Parsifal Capital Management, LP is the manager of each of Parsifal Master Fund Ltd. and Parsifal Co-Invest I, LP. Parsifal Capital Management, LP is controlled Parsifal Capital Management GP, LLC, its general partner. Parsifal Capital Management GP, LLC is controlled by David Zorub, its managing member. Each of Parsifal Master Fund Ltd., Parsifal Co-Invest I, LP, Parsifal Capital Management, LP and Parsifal Capital Management GP, LLC (collectively, the “Parsifal Entities”) and Mr. Zorub 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 pecuniary interest therein. Also includes 326,715 shares of common stock held by an account managed by Parsifal Capital Management, LP with respect to which the Parsifal Entities and Mr. Zorub may be deemed to have shared voting or dispositive power with the owner of such account. The address of each Parsifal Entity and Mr. Zorub is c/o Parsifal Capital Management, LP, One Fawcett Place, Suite 130, Greenwich, CT 06830.
(26)Consists of 1,455,108 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.
(27)Consists of (i) 554,604 shares held by PSAM WorldArb Master Fund Ltd, (ii) 52,054 shares held by Rebound Portfolio Ltd, (iii) 24,467 shares held by FASF-K2 Alternative Strategies Fund-Master, (iv) 130,881 shares held by Lumyna Specialist Funds - PSAM Credit Opportunities Fund, (v) 25,752 shares held by FTIF Franklin K2 Alternative Strategies Fund, (vi) 370,701 shares held by Lumyna Funds - Lumyna - PSAM Global Event UCITS Fund, (vii) 133,637 shares held by K2 PSAM Event Master Fund Ltd and (viii) 14,094 shares held by Lumyna Specialist Funds - Event Alternative 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, K2 PSAM Event Master Fund Ltd and Lumyna Specialist Funds - Event Alternative Fund is c/o P. Schoenfeld Asset Management LP, 1350 Avenue of the Americas, 21st Floor, New York, NY 10019. The address of FASF-K2 Alternative Strategies Fund-Master and FTIF Franklin K2 Alternative Strategies Fund is 300 Atlantic Street, 12th Floor, Stamford, CT 06901.
(28)Consists of (i) 759,636 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.
(29)Consists of (i) 521,185 shares held by Lord Abbett Bond Debenture Fund, (ii) 278,100 shares held by Lord Abbett Investment Trust - Lord Abbett High Yield Fund, (iii) 20,091 shares held by Lord Abbett Series Fund - Bond Debenture Portfolio, (iv) 3,895 shares held by Lord Abbett Trust I - Lord Abbett Short Duration High Yield Fund, (v) 2,673 shares held by Lord Abbett Global Funds I plc - Lord Abbett Global High Yield Fund and (vi) 134,266 shares held by Lord Abbett Global Funds I plc - Lord Abbett High Yield Fund (collectively, the “Lord Abbett Funds”). The Lord Abbett Funds are managed by Lord Abbett & Co. LLC as investment advisor. Lord Abbett & Co. LLC 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 each of Lord Abbett Bond Debenture Fund, Lord Abbett Investment Trust - Lord Abbett High Yield Fund, Lord Abbett Series Fund - Bond Debenture Portfolio and Lord Abbett Trust I - Lord Abbett Short Duration High Yield Fund is 90 Hudson Street, Jersey City, NJ 07302. The address of Lord Abbett Global Funds I plc - Lord Abbett Global High Yield Fund and Lord Abbett Global Funds I plc - Lord Abbett High Yield Fund is 30 Herbert Street, Dublin D02 W329, Ireland.
(30)Consists of (i) 50,516 shares held by Franklin Universal Trust, (ii) 556,650 shares held by Franklin High Income Trust-Franklin High Income Fund, (iii) 192,342 shares held by Franklin Templeton Investment Funds-Franklin High Yield Fund, (iv) 54,555 shares held by Franklin Limited Duration Income Trust, (v) 3,710 shares held by The Shared Risk Plan for CUPE Employees of New Brunswick Hospitals and (vi) 31,035 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 (“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 the securities reported in such SEC filings. The address of each of the Franklin Funds is c/o Franklin Advisers, Inc., One Franklin Parkway, San Mateo, CA 94403.
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(31)Consists of 841,980 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.
(32)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 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 general partner of TC Group Sub L.P., which is the sole member of TC Group-Energy LLC, 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.
(33)Consists of 820,120 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.
(34)Consists of 814,929 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”), which 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 Buckingham Square, 2nd Floor, 720A West Bay Road, Grand Cayman KY1-1001, Cayman Islands.
(35)Consists of (i) 154,744 shares held by Sculptor Credit Opportunities Master Fund, Ltd., (ii) 138,381 shares held by Sculptor SC II, LP and (iii) 477783 shares held by Sculptor Master Fund, Ltd. Sculptor SC II, LP is a Delaware limited partnership (“SCSC”). Sculptor Capital II LP (“Sculptor II”), a Delaware limited partnership, is the investment manager to SCSC. Sculptor Capital Holding II LLC (“SCHCII”), a Delaware limited liability company, serves as the general partner of Sculptor II. Sculptor Capital LP (“Sculptor”), a Delaware limited partnership, is the sole member of SCHCII. Sculptor Capital Holding Corporation (“SCHC”), a Delaware corporation, serves as the general partner of Sculptor. Sculptor Capital Management, Inc. (“SCU”), a Delaware limited liability company that is publicly traded on the New York Stock Exchange (NYSE: SCU), is a holding company that is the sole shareholder of SCHC and the ultimate parent company of Sculptor. Accordingly, Sculptor II, SCHCII, Sculptor, SCHC and SCU, may be deemed to be beneficial owners of SCSC. The address of each of SCSC, SCHCII, SCHC and SCU is 9 West. 57th Street, 40th Floor, New York, NY 10019.
(36)Consists of (i) 463,232 shares held by Yost Partners, L.P., (ii) 174,737 shares held by Yost SPV I, L.P. and (iii) 68,000 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”). Tomcat Advisors, L.L.C., a Texas limited partnership (“Yost Management”), serves as the investment manager of Yost Partners. Tomcat Advisors serves as the general partner of Yost Management. 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 2800 W. Lancaster Avenue, Forth Worth, TX 76107.
(37)Consists of (i) 570,326 shares held by Oaktree Value Opportunities Fund Holdings, L.P. (“Oaktree Value Opportunities Fund Holdings”) and (ii) 73,502 shares held by Oaktree Phoenix Investment Fund, L.P. (“Oaktree Phoenix”). These shares of common stock being registered
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herein are beneficially owned by (i) Oaktree Value Opportunities Fund Holdings, as a result of its direct ownership of 570,326 shares of common stock, (ii) Oaktree Phoenix, as a result of its direct ownership of 73,502 shares of common stock, (iii) 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, (iv) 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, (v) Oaktree Phoenix Investment Fund GP, L.P. (“Oaktree Phoenix GP LP”), solely in its capacity as the general partner of Oaktree Phoenix, (vi) Oaktree Phoenix Investment Fund GP Ltd. (“Oaktree Phoenix GP”), solely in its capacity as the general partner of Oaktree Phoenix GP LP, and (vii) Oaktree Capital Management, L.P., solely in its capacity as the director of Oaktree Value Opportunities Fund GP and as the director of Oaktree Phoenix GP. The address of each of the foregoing is 333 South Grand Avenue, 28th Floor, Los Angeles, CA 90071.
(38)Consists of (i) 150,277 shares held by Blackwell Partners LLC - Series A, (ii) 146,281 shares held by Cassini Partners, L.P., (iii) 231,242 Philosophy Capital Partners, LP and (iv) 78,620 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.
(39)Consists of 408,924 shares held by CastleKnight SPV I LLC (the “CastleKnight Fund”). These shares of the Company’s common stock may be deemed to be beneficially owned by (i) CastleNight Management LP by virtue of its role as the investment manager of the CastleKnight Fund, (ii) CastleKnight Management GP LLC by virtue of its role as a general partners of CastleKnight Management LP, (iii) Weitman Capital LLC by virtue of its role as a managing member of CastleKnight Management GP LLC and (iv) Aaron Weitman by virtue of his role as managing member of Weitman Capital LLC. Each of the foregoing disclaims beneficial ownership of the shares of common stock of the Company except to the extent of his or its pecuniary interest therein, and this statement shall not be deemed an admission that such reporting person is the beneficial owner of the securities for purposes of Section 16 of the Securities Exchange Act of 1934, as amended, or for any other purpose. The address of the CastleKnight Fund is 888 Seventh Avenue, 24th Floor, New York, NY 10019.
(40)Consists of (i) 29,162 shares held by Glenview Offshore Opportunity Master Fund, Ltd., (ii) 129,504 shares held by Glenview Capital Master Fund, Ltd., (iii) 11,647 shares held by Glenview Capital Partner, L.P. and (iv) 86,766 shares held by Glenview Capital Opportunity Fund, L.P. (collectively, the “Glenview Funds”). Larry Robbins is Founder, Portfolio Manager and Chief Executive Officer of Glenview Capital Management, LLC, which serves as investment manager to the Glenview Funds. Mr. Robbins shares voting and dispositive power over the shares held by the Glenview Funds, and may be deemed to beneficially own such shares. The business address of each of the Glenview Funds is 767 Fifth Avenue 44th Floor, New York, New York 10153.
(41)Consists of 246,133 shares held by Jeffries LLC. Jefferies LLC is wholly owend by Jefferies Financial Group Inc. Jefferies Financial Group Inc. may be deemed to be the beneficial owner of the shares of common stock held of record by Jefferies LLC. The address of Jeffries LLC is 520 Madison Avenue, New York, NY 10022.
(42)Consists of (i) 26,748 shares held by Boothbay Absolute Return Strategies, LP, (ii) 20,176 shares held by Boothbay Diversified Alpha Master Fund LP, (iii) 4,017 shares held by Cadence Hill Opportunity Fund, (iv) 48,016 shares held by FW Deep Value Opportunities Fund I, (v) 12,196 shares held by FourWorld Event Opportunities, LP, (vi) 119,490 shares held by FourWorld Global Opportunities Fund, Ltd. and (vii) 8,724 shares held by FourWorld Special Opportunities Fund, LLC (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 FWCM Funds, but disclaims beneifical 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.
(43)Consists of 150,000 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.
(44)Consists of (i) 23,373 shares held by Corbin Opportunity Fund, L.P. and (ii) 115,919 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, as the Chief Investment Officer of CCP, makes voting and investment decisions for the Corbin Funds, but disclaims beneficial ownership of the shares held by them. The address of each of the Corbin Funds is 590 Madison Avenue, 31st Floor, New York, NY 10022.
(45)Consists of 102,157 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.
(46)Consists of 40,282 shares held by Goldman Sachs & Co. LLC (“GS&Co.”). GS&Co. is registered as a U.S. broker-dealer, futures commission merchant, swap dealer and security-based swap dealer, and is a wholly-owned subsidiary of the Goldman Sachs Group, Inc. (“GS Group.”), a Delaware corporation, except for de minimus nonvoting, non-participating interests by unaffiliated broker-dealers. GS Group is a public company whose common stock is traded on the NYSE. GS Group may be deemed to beneficially own the securities held by GS&Co. GS Group disclaims beneficial ownership of such securities except to the extent of its pecuniary interest therein. The mailing address for GS&Co. is 200 West Street, New York, New York 10282.
(47)Consists of 27,695 held by U.S. Distressed & Special Situations Group, a business unit within BofA Securities, Inc. (“BofA”), and do not reflect holdings of any other line of business within BofA, or any of its affiliates or subsidiaries. BofA is the beneficial owner of the securities listed herein. The address of BofA is 401 N. Tyron Street, Charlotte, NC 28255.
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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 October 19, 2023, there were 59,028,843 shares of our common stock outstanding held by one stockholder 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 three 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 and the number of directors constituting the full Board of Directors will be permitted to be set only 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 may 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 American Stock Transfer & Trust Company. The transfer agent and registrar’s address is 6201 15th Avenue, Brooklyn, New York, 11219.
Exchange Listing
Our common stock is currently not listed on any securities exchange. We intend to apply 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 , we have a total of 59,028,843 shares of common stock issued and outstanding. Of the 59,028,843 shares of common stock issued and outstanding, 15,135,955 shares were issued in reliance on the exemption from registration provided by Section 1145 of the Bankruptcy Code (the “1145 Shares”). The 1145 Shares are freely tradable without restriction or further registration under the Securities Act, except that any shares held by our affiliates, as that term is defined under Rule 144 of the Securities Act, are considered control securities and may be sold only in compliance with the limitations described below. Of the 59,028,843 shares of common stock issued and outstanding, 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”). The 4(a)(2) Shares are deemed restricted securities under the meaning of Rule 144 and may be sold in the public market only if registered or if they qualify for an exemption from registration, including the exemptions pursuant to Rule 144, which are summarized 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.
Issuance and Resales of 1145 Shares
We relied on Section 1145(a)(1) and (2) of the Bankruptcy Code to exempt from the registration requirements of the Securities Act any future offer and resale of our common stock issued pursuant to the Plan of Reorganization. Section 1145(a)(1) exempts the offer and sale of securities under the Plan of Reorganization from registration under Section 5 of the Securities Act and state laws if certain requirements are satisfied. The 1145 Shares issued pursuant to the Plan of Reorganization may be resold without registration unless the seller is an “underwriter” with respect to those shares. Section 1145(b)(1) defines an “underwriter” as any person who: purchases a claim against, an interest in, or a claim for an administrative expense against the debtor, if that purchase is with a view to distributing any security received in exchange for such a claim or interest; offers to sell securities offered under the Plan of Reorganization for the holders of those securities; offers to buy those securities from the holders of the securities, if the offer to buy is (i) with a view to distributing those securities; and (ii) under an agreement made in connection with the Plan of Reorganization, the completion of the Plan of Reorganization, or with the offer or sale of securities under the Plan of Reorganization; or is an “affiliate” of the issuer. To the extent a person is deemed to be an “underwriter,” resales by such person would not be exempted by Section 1145 from registration under the Securities Act or other applicable law. Those persons would, however, be permitted to resell shares of our common stock without registration if they are able to comply with the provisions of Rule 144, as described further below.
Rule 144
Affiliate Resales of Restricted Securities
In general, once we have been subject to the public company reporting requirements of Section 13 or Section 15(d) of the Exchange Act for at least 90 days, a person who is an affiliate of ours, or who was an affiliate at any time during the 90 days before a sale, who has beneficially owned shares of our capital stock for at least six months,
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but less than a year, 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 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 of Restricted Securities
In general, once we have been subject to the public company reporting requirements of Section 13 or Section 15(d) of the Exchange Act for at least 90 days, a person who is not an affiliate of ours at the time of sale, has not been an affiliate at any time during the three months preceding a sale, and has beneficially owned shares of our capital stock for at least six months but less than a year, 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 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 that may be resold pursuant to this prospectus as a capital asset (generally, property held for investment) within the meaning of Section 1221 of the Code. 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,” 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 and 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. 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 any possible 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 supplement to this prospectus, if required, pursuant to Rule 424(b) under 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
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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 4(a)(2) Shares 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 4(a)(2) Shares and the 1145 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.
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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 Supply, LLC as of December 31, 2022 and 2021 and for each of the three years in the period ended December 31, 2022 included in this prospectus, have been so included in reliance on the report (which contains explanatory paragraphs relating to the removal of substantial doubt about the Company’s ability to continue as a going concern as described in Note 2, and relating to its emergence from bankruptcy on May 17, 2023 as described in Note 2 and Note 3 to the 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.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Annual Financial Statements for the Three Fiscal Years Ended December 31, 2022, 2021 and 2020 (Predecessor) | |||||
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Confidential Treatment Requested by Talen Energy Corporation
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| (Millions of Dollars, except share data) | 2023 | 2023 | 2022 | |||||||||||||||||
| Capacity revenues | $ | 26 | $ | 108 | $ | 247 | ||||||||||||||
| Energy and other revenues | 188 | 1,042 | 657 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 87 | 60 | 184 | |||||||||||||||||
Operating Revenues | 301 | 1,210 | 1,088 | |||||||||||||||||
| Energy Expenses | ||||||||||||||||||||
| Fuel and energy purchases | (57) | (176) | (417) | |||||||||||||||||
| Nuclear fuel amortization | (25) | (33) | (47) | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (46) | (123) | 22 | |||||||||||||||||
Total Energy Expenses | (128) | (332) | (442) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (69) | (285) | (317) | |||||||||||||||||
| General and administrative | (18) | (51) | (59) | |||||||||||||||||
| Depreciation, amortization and accretion | (28) | (200) | (270) | |||||||||||||||||
| Impairments | — | (381) | — | |||||||||||||||||
| Operational restructuring | — | — | (447) | |||||||||||||||||
| Other operating income (expense), net | (3) | (37) | (17) | |||||||||||||||||
Operating Income (Loss) | 55 | (76) | (464) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 39 | 57 | (191) | |||||||||||||||||
| Interest expense and other finance charges | (33) | (163) | (172) | |||||||||||||||||
| Reorganization income (expense), net | — | 799 | (331) | |||||||||||||||||
| Other non-operating income (expense), net | (11) | 60 | (44) | |||||||||||||||||
Income (Loss) Before Income Taxes | 50 | 677 | (1,202) | |||||||||||||||||
| Income tax benefit (expense) | (19) | (212) | 48 | |||||||||||||||||
Net Income (Loss) | 31 | 465 | (1,154) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 2 | (14) | — | |||||||||||||||||
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 29 | $ | 479 | $ | (1,154) | ||||||||||||||
| Per Common Share (Successor) | ||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | 0.49 | N/A | N/A | ||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | 0.49 | N/A | N/A | |||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 59,029 | N/A | N/A | |||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 59,088 | N/A | N/A | |||||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| (Millions of Dollars) | 2023 | 2023 | 2022 | |||||||||||||||||
Net Income (Loss) | $ | 31 | $ | 465 | $ | (1,154) | ||||||||||||||
| Other Comprehensive Income (Loss) | ||||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | (6) | 6 | (54) | |||||||||||||||||
| Income tax benefit (expense) | 2 | (2) | 22 | |||||||||||||||||
| Gains (losses) arising during the period, net of tax | (4) | 4 | (32) | |||||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net | 1 | 4 | 23 | |||||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | — | (1) | (1) | |||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net | — | 2 | 13 | |||||||||||||||||
| Income tax (benefit) expense | — | (3) | (13) | |||||||||||||||||
| Reclassifications from AOCI, net of tax | 1 | 2 | 22 | |||||||||||||||||
| Total Other Comprehensive Income (Loss) | (3) | 6 | (10) | |||||||||||||||||
| Comprehensive Income (Loss) | 28 | 471 | (1,164) | |||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | 2 | (14) | — | |||||||||||||||||
Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 26 | $ | 485 | $ | (1,164) | ||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-3
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| Successor | Predecessor | |||||||||||||
| June 30, | December 31, | |||||||||||||
| (Millions of Dollars. except share data) | 2023 | 2022 | ||||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | 127 | $ | 724 | ||||||||||
| Restricted cash and cash equivalents | 588 | 264 | ||||||||||||
| Accounts receivable, net | 150 | 408 | ||||||||||||
| Inventory, net | 318 | 457 | ||||||||||||
| Derivative instruments | 169 | 2,165 | ||||||||||||
| Other current assets | 116 | 247 | ||||||||||||
Total current assets | 1,468 | 4,265 | ||||||||||||
| Property, plant and equipment, net | 3,863 | 4,705 | ||||||||||||
| Nuclear decommissioning trust funds | 1,499 | 1,400 | ||||||||||||
| Derivative instruments | 2 | 228 | ||||||||||||
| Other noncurrent assets | 191 | 124 | ||||||||||||
Total Assets | $ | 7,023 | $ | 10,722 | ||||||||||
| Liabilities and Equity | ||||||||||||||
| Revolving credit facilities | $ | — | $ | 848 | ||||||||||
| Long-term debt, due within one year | 14 | 1,010 | ||||||||||||
| Accrued interest | 29 | 278 | ||||||||||||
| Accounts payable and other accrued liabilities | 298 | 454 | ||||||||||||
| Derivative instruments | 50 | 1,927 | ||||||||||||
| Other current liabilities | 57 | 346 | ||||||||||||
Total current liabilities | 448 | 4,863 | ||||||||||||
| Long-term debt | 2,832 | 2,494 | ||||||||||||
| Liabilities subject to compromise | — | 2,825 | ||||||||||||
| Derivative instruments | 28 | 363 | ||||||||||||
| Postretirement benefit obligations | 335 | — | ||||||||||||
| Asset retirement obligations and accrued environmental costs | 444 | 567 | ||||||||||||
| Deferred income taxes | 372 | 75 | ||||||||||||
| Other noncurrent liabilities | 104 | 17 | ||||||||||||
Total Liabilities | 4,563 | 11,204 | ||||||||||||
| Commitments and Contingencies - Note 12 | ||||||||||||||
| Stockholders’ (Successor) / Member’s (Predecessor) Equity | ||||||||||||||
| Member’s equity | — | (573) | ||||||||||||
Common stock - $0.001 par value (a) | — | — | ||||||||||||
| Additional paid-in capital | 2,325 | — | ||||||||||||
| Accumulated retained earnings (deficit) | 29 | — | ||||||||||||
| Accumulated other comprehensive income (loss) | (3) | — | ||||||||||||
Total Stockholders’ (Successor) / Member’s (Predecessor) Equity | 2,351 | (573) | ||||||||||||
Noncontrolling interests | 109 | 91 | ||||||||||||
Total Equity | 2,460 | (482) | ||||||||||||
Total Liabilities and Equity | $ | 7,023 | $ | 10,722 | ||||||||||
__________________
(a)At June 30, 2023: 350,000,000 shares authorized; 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
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| (Millions of Dollars) | 2023 | 2023 | 2022 | |||||||||||||||||
| Operating Activities | ||||||||||||||||||||
| Net income (loss) | $ | 31 | $ | 465 | $ | (1,154) | ||||||||||||||
| Non-cash Reconciliation adjustments: | ||||||||||||||||||||
| Unrealized (gains) losses on derivative instruments | (39) | 65 | (226) | |||||||||||||||||
| Nuclear fuel amortization | 25 | 33 | 47 | |||||||||||||||||
| Depreciation, amortization and accretion | 27 | 208 | 288 | |||||||||||||||||
| Impairments | — | 381 | — | |||||||||||||||||
| Operational restructuring | — | — | 447 | |||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) | (33) | (43) | 211 | |||||||||||||||||
| Deferred income taxes | 16 | 195 | (56) | |||||||||||||||||
| Reorganization (income) expense, net | — | (933) | 99 | |||||||||||||||||
| Other | 17 | (43) | 74 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Accounts receivable, net | (5) | 261 | (130) | |||||||||||||||||
| Inventory, net | (11) | 10 | 2 | |||||||||||||||||
| Other assets | 22 | 98 | (89) | |||||||||||||||||
| Accounts payable and accrued liabilities | (89) | (69) | 267 | |||||||||||||||||
| Accrued interest | 25 | (124) | 258 | |||||||||||||||||
| Other liabilities | 13 | (42) | (14) | |||||||||||||||||
Net cash provided by (used in) operating activities | (1) | 462 | 24 | |||||||||||||||||
Investing Activities | ||||||||||||||||||||
| Property, plant and equipment expenditures | (20) | (138) | (61) | |||||||||||||||||
| Nuclear fuel expenditures | (14) | (49) | (45) | |||||||||||||||||
| Nuclear decommissioning trust funds investment purchases | (279) | (959) | (1,254) | |||||||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds | 273 | 949 | 1,246 | |||||||||||||||||
| Proceeds from the sale of non-core assets | — | 46 | 1 | |||||||||||||||||
| Equity investments in affiliates | — | (8) | (77) | |||||||||||||||||
| Other investing activities | 2 | 2 | 17 | |||||||||||||||||
Net cash provided by (used in) investing activities | (38) | (157) | (173) | |||||||||||||||||
Financing Activities | ||||||||||||||||||||
| Contributions from member | — | 1,393 | — | |||||||||||||||||
| Exit Financing 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 | |||||||||||||||||
| Deferred Capacity Obligation and Inventory Repurchase Obligations, net repayments | — | — | (341) | |||||||||||||||||
| LMBE-MC TLB payments | (1) | (7) | (23) | |||||||||||||||||
| Deferred finance costs | — | (74) | (57) | |||||||||||||||||
| Derivatives with financing elements | — | (20) | (21) | |||||||||||||||||
| Other | 1 | — | (10) | |||||||||||||||||
Net cash provided by (used in) financing activities | — | (539) | 535 | |||||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents | (39) | (234) | 386 | |||||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | 754 | 988 | 743 | |||||||||||||||||
| End of period cash and cash equivalents and restricted cash and cash equivalents | $ | 715 | $ | 754 | $ | 1,129 | ||||||||||||||
See Note 19 in Notes to the Interim Financial Statements for supplemental cash flow information.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-5
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 | Member’s Equity | Noncontrolling Interest | Total Equity | |||||||||||||||||||||||||||||||||||||
December 31, 2021 (Predecessor) | — | $ | — | $ | — | $ | — | $ | 733 | $ | — | $ | 733 | |||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | (1,154) | — | (1,154) | |||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | — | (10) | — | (10) | |||||||||||||||||||||||||||||||||||||
June 30, 2022 (Predecessor) | — | $ | — | $ | — | $ | — | $ | (431) | $ | — | $ | (431) | |||||||||||||||||||||||||||||||
December 31, 2022 (Predecessor) | — | $ | — | $ | — | $ | — | $ | (573) | $ | 91 | $ | (482) | |||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 479 | (14) | 465 | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income | — | — | — | — | 6 | — | 6 | |||||||||||||||||||||||||||||||||||||
Cancellation of member’s equity (c) | — | — | — | — | 88 | — | 88 | |||||||||||||||||||||||||||||||||||||
Issuance of member’s equity (c) | — | — | — | — | 2,313 | — | 2,313 | |||||||||||||||||||||||||||||||||||||
Issuance of warrants (c) | — | — | — | — | 8 | — | 8 | |||||||||||||||||||||||||||||||||||||
| Common equity from member’s equity exchange | 59,029 | 2,321 | — | — | (2,321) | — | — | |||||||||||||||||||||||||||||||||||||
Non-cash contributions (b) | — | — | — | — | — | 38 | 38 | |||||||||||||||||||||||||||||||||||||
Non-cash distribution, 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) | — | — | 29 | — | 2 | 31 | ||||||||||||||||||||||||||||||||||||||
| Other comprehensive loss | — | — | — | (3) | — | — | (3) | |||||||||||||||||||||||||||||||||||||
Non-cash distribution (d) | — | — | — | — | — | (3) | (3) | |||||||||||||||||||||||||||||||||||||
| Other | — | 4 | — | — | — | — | 4 | |||||||||||||||||||||||||||||||||||||
June 30, 2023 (Successor) | 59,029 | $ | 2,325 | $ | 29 | $ | (3) | $ | — | $ | 109 | $ | 2,460 | |||||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Relates to contributions of cryptocurrency mining machines by TeraWulf to Nautilus.
(c)Pursuant to the Plan of Reorganization: (i) existing equity interests were canceled and (ii) new equity interests and equity-classified warrants were issued.
(d)Relates primarily to a distribution of cryptocurrency mining machines or Bitcoin to TeraWulf.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
F-6
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 Supply 2022 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 Talen Energy Corporation 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 Talen Energy Supply 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 on the Emergence Date.
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 high-quality 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 nature of our wholly-owned coal fleet through the conversion to lower-carbon fuels. In addition, we have developed a hyperscale data center campus adjacent to Susquehanna 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 June 30, 2023, our generation capacity was 12,402 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 Interim Financial Statements are prepared in accordance with GAAP and include the accounts of all controlled subsidiaries. Intercompany transactions are eliminated in consolidation. Certain information and note disclosures, normally included in financial statements prepared in accordance with GAAP, have been condensed or omitted from these statements in accordance with GAAP. In the opinion of management, the Interim Financial Statements include 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. The Condensed Consolidated Balance Sheet at December 31, 2022 is derived from the Talen Energy Supply 2022 Consolidated Balance Sheet in the Annual Financial Statements. See “Reverse Acquisition” below for more information regarding the relationship between TEC and TES after Emergence. The Interim Financial Statements and Notes thereto should be read in conjunction with the Annual Financial Statements and Notes thereto.
The results of operations for the Predecessor period, from January 1 through May 17, 2023, and the Successor period, from May 18 through June 30, 2023, are not necessarily indicative of the results to be expected for the full year ending December 31, 2023 or for other future periods, because the results for interim periods can be disproportionately influenced by various factors, developments and seasonal variations. After the Emergence Date, TES applied fresh start accounting, which resulted in a new basis of accounting, as the Company became a new entity for financial reporting purposes. As a result of the application of fresh start accounting and the implementation
F-7
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
of the Plan of Reorganization, our consolidated financial statements after the Emergence Date are not comparable to our financial statements prior to that date. 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.
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. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for VIEs. Talen consolidates a VIE when it is determined that it has a controlling interest in the VIE and Talen is the primary beneficiary of the entity. See Note 11 of the Annual Financial Statements for additional information.
Reverse Acquisition. During the Restructuring, TEC deconsolidated TES for financial reporting purposes because TEC no longer controlled the activities of TES. 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 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 — 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 Condensed Consolidated Statements of Equity.
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. 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 was 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.
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.
Accounting Policy Updates at Emergence
Upon Emergence, we elected to change our accounting policies related to derivative instruments, postretirement benefit obligations and stock-based compensation.
Derivative Instruments. The netting and collateral provisions under master trade agreements govern setoff rights and collateral requirements on commercial agreements between counterparties. Prior to the Emergence Date, the fair value of derivative instruments on the Condensed Consolidated Balance Sheets was presented gross of setoff rights and cash collateral deposits exchanged between parties under such arrangements. After the Emergence Date, 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. See Note 5 for additional information on our derivative instruments and hedging activities.
F-8
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Postretirement Benefit Obligations. Prior to the Emergence Date, we used a bond matching methodology, based on a specific portfolio of bonds that closely match the overall cash flow timing and duration of the benefit plans, to develop the discount rate utilized to measure the projected benefit obligations and service costs for benefit plans. After the Emergence Date, we use a spot rate curve that represents a portfolio of high-quality corporate bonds to develop the discount rate.
Stock-Based Compensation. In connection with Emergence, TEC granted 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 date of grant 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. For the period from May 18 through June 30, 2023 (Successor), a non-material amount of stock-based compensation was recognized and presented as “General and administrative” on the Condensed Consolidated Statements of Operations. There was no stock-based compensation in prior periods.
Nautilus Revenue Recognition
The primary output of Nautilus’ ordinary business activities is providing computing power, or hashing power, 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 computing power to an unaffiliated mining pool operator. Nautilus is entitled to an enforceable right to compensation from the mining pool operator only for the duration when Nautilus provides its computing power over a period of time.
In exchange for providing computing power to the mining pool operator, Nautilus is entitled to daily consideration whether or not the mining pool operator successfully solves a block based on a ‘full-pay-per-share’ payout methodology. Nautilus’ only performance obligation is to provide computing power to the mining pool operator. If Nautilus does not provide computing power to the mining pool operator, no consideration is awarded to 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 daily that is measured at fair value using the quoted price for Bitcoin in Nautilus’ principal market at the beginning of each day (Coordinated Universal Time).
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.
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
F-9
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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, Talen Energy Corporation 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.
•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;
F-10
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
◦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; 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. To the extent any proceeds are recovered by the Debtors pursuant to the PPL/Talen Montana litigation, 10% of the net proceeds recovered will be contributed to the pool of cash, subject to a cap of $11 million. See Note 12 for information on the PPL/Talen Montana litigation.
4. Fresh Start Accounting
At the Emergence Date, the Company was required to adopt fresh start accounting as: (i) the holders of existing voting shares of the Predecessor received less than 50% of the voting shares of the Successor and (ii) the reorganization value of the Company’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.
Under fresh start accounting, reorganization value represents the value of the entity before considering liabilities and is intended to represent the approximate amount a willing buyer would pay for the assets immediately after the restructuring. Upon the adoption of fresh start accounting, the Company allocated the reorganization value to its individual assets and liabilities based on their 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.
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 the Emergence Date 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 the Emergence Date. 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 the Emergence Date included the income approach, market approach and cost approach with consideration of the exit market and nature of the applicable asset or liability subject to valuation.
The Company’s principal assets are generation facilities whose values were determined by a discounted cash flow analysis based on management’s latest outlook of the business through the end of their expected useful lives. The forward-looking projections considered: (i) company-specific factors, such as unit characteristics, plant dispatch, operating expenses, capital expenditures and estimated economic useful lives, and (ii) macroeconomic factors, such as capacity prices, energy prices, fuel prices, market supply and demand factors, inflation factors, and environmental regulations. Commodity prices used to estimate future cash flows in observable periods were primarily based on adjusted exchange prices, prices provided by brokers, or 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
F-11
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 the Emergence Date, 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 the Emergence Date:
| 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)Enterprise value excludes any value associated with noncontrolling interest.
(b)Balance includes “Cash and cash equivalents” and “Restricted cash and cash equivalents.” Amount excludes $52 million for payment of professional fees.
The following table reconciles the Company’s enterprise value to the estimated fair value at the Emergence Date:
| 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)Enterprise value excludes any value associated with noncontrolling interest.
(b)Balance includes “Cash and cash equivalents” and “Restricted cash and cash equivalents.” Amount excludes $52 million for payment of professional fees.
(c)Successor equity issued in accordance with the Plan of Reorganization, which includes 59,028,843 shares of TEC common stock and $8 million of equity-classified warrants.
Condensed Consolidated Balance Sheet
The column “Reorganization Adjustments” set forth in the below fresh start Condensed Consolidated Balance Sheet as of the Emergence Date presents the aggregate effect of the transactions contemplated by the Plan of Reorganization, and the column “Fresh Start Adjustments” presents the preliminary fair value and other required
F-12
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
adjustments as a result of applying fresh start accounting. The explanatory notes provide additional information related to the adjustments recorded, 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 | ||||||||||||||||||||||||
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 Date 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
F-13
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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” on the Emergence Date 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-14
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(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 debt issuance costs of $21 million. See Note 13 for more information.
(b)Net of an aggregate original issue discount and debt issuance costs of $32 million.
(c)Net of an aggregate original issue discount and debt issuance costs of $24 million.
(d)Includes recognition of $4 million of interest expense.
F-15
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(l)“Liabilities subject to compromise” settled or reinstated on the Emergence Date 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 14 for more information.
F-16
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The estimated fair value of liability-classified warrants was determined using a Black-Scholes option pricing model with the following assumptions at the Emergence Date:
| Expected volatility | 30.00 | % | |||
| Expected term (years) | 5.00 | ||||
| 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 on Emergence | (27) | ||||
| Restructuring-related compensation expense | (8) | ||||
| Total reorganization items from reorganization adjustments | 1,378 | ||||
| Interest expense incurred on 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 (b) | (35) | ||||
Other (c) | (6) | ||||
Net change in Member’s equity | $ | 3,416 | |||
__________________
(a)See Note 16 for more information.
(b)See Note 14 for more information.
(c)Includes $1 million of proceeds from Riverstone for payment to general unsecured creditors trust.
Fresh Start Adjustments
(q)Net presentation of derivatives on the unaudited Condensed Consolidated Balance Sheets. See Note 2 for more 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-17
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 more 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 account for postretirement obligations, from 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 the Emergence Date, 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-18
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(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
At December 31, 2022, “Liabilities subject to compromise” on the Condensed 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 June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Backstop Premium | $ | — | $ | (70) | $ | — | ||||||||||||||
| Gain (loss) on debt discharge | — | 1,459 | — | |||||||||||||||||
| Gain (loss) on revaluation adjustments | — | (460) | — | |||||||||||||||||
| Professional fees | — | (56) | (45) | |||||||||||||||||
| Make-whole premiums and accrued interest on certain indebtedness | — | (21) | (184) | |||||||||||||||||
| Professional fees incurred to obtain the DIP Facilities | — | — | (68) | |||||||||||||||||
| Write-off of deferred financing cost and original issue discount | — | (46) | (30) | |||||||||||||||||
| Other | — | (7) | (4) | |||||||||||||||||
Reorganization Income (Expense), net | $ | — | $ | 799 | $ | (331) | ||||||||||||||
F-19
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 Condensed Consolidated Statement of Operations and included in “Accrued interest” on the Condensed Consolidated Balance Sheet.
Cash paid for reorganization expense, net, was $308 million for the period from January 1 through May 17, 2023 (Predecessor). Cash paid in the six months ended June 30, 2022 (Predecessor) for DIP Facilities financing fees is presented as “Financing Activities” on the Condensed Consolidated Statement 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 Company’s board of directors.
The Company’s board (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.
F-20
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Open commodity purchase (sales) derivatives at June 30, 2023 (Successor) range in maturity through 2026. The net notional volumes of open commodity derivatives were:
| Successor | Predecessor | |||||||||||||
June 30, 2023 (a) | December 31, 2022 (a) | |||||||||||||
| Power (MWh) | (35,932,185) | (34,810,559) | ||||||||||||
| Natural gas (MMBtu) | 48,784,300 | 57,621,580 | ||||||||||||
| Emission allowances (tons) | 2,850,000 | 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.
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 at June 30, 2023 (Successor) range in maturity dates through 2023. The net notional volumes of open interest rate derivatives were:
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
Interest rate (in millions) (a) | $ | 260 | $ | 289 | ||||||||||
__________________
(a)Value at June 30, 2023 and December 31, 2022 relates to LMBE-MC indebtedness. This indebtedness was repaid in August 2023 and these derivatives were terminated.
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. Allowances for doubtful accounts were $6 million at both June 30, 2023 (Successor) and December 31, 2022 (Predecessor).
F-21
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Concentrations of Credit Risk. At June 30, 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 $975 million and its credit exposure net of such effects was $245 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 93% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Credit Risk Contingent Features. 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 a non-material amount at June 30, 2023 (Successor) and December 31, 2022 (Predecessor).
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 Condensed Consolidated Balance Sheets with the effect of such permitted netting at June 30, 2023 (Successor), while derivative assets and derivative liabilities are presented on the Condensed Consolidated Balance Sheets without the effect of such permitted netting at December 31, 2022 (Predecessor). See Note 2 for information on this policy election change.
The net amounts of “Derivative instruments” presented as assets and liabilities on the Condensed 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 | ||||||||||||||||||||||||||||||
| June 30, 2023 (Successor) | |||||||||||||||||||||||||||||||||||
| Assets | $ | 820 | $ | (649) | $ | — | $ | 171 | $ | — | $ | 171 | |||||||||||||||||||||||
| Liabilities | 783 | (649) | — | 134 | (56) | 78 | |||||||||||||||||||||||||||||
| 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 Condensed Consolidated Balance Sheets. See Note 4 for additional information.
F-22
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Derivative Instrument Presentation
The fair value of derivative instruments presented within assets and liabilities on the Condensed Consolidated Balance Sheets were:
| Successor | Predecessor (a) | |||||||||||||||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||||||
| Commodity contracts | $ | 164 | $ | 50 | $ | 2,156 | $ | 1,928 | ||||||||||||||||||
| Interest rate contracts | 5 | — | 9 | — | ||||||||||||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | — | — | 1 | ||||||||||||||||||||||
Total current derivative instruments | $ | 169 | $ | 50 | $ | 2,165 | $ | 1,927 | ||||||||||||||||||
| Commodity contracts | $ | 2 | $ | 28 | $ | 228 | $ | 363 | ||||||||||||||||||
Total non-current derivative instruments | $ | 2 | $ | 28 | $ | 228 | $ | 363 | ||||||||||||||||||
__________________
(a)A portion of liability values has been presented as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheets. See Note 4 for additional information.
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 Condensed Consolidated Statements of Operations. Changes in fair value and realized settlements of interest rate derivatives are presented as “Interest expense and other finance charges” on the Condensed Consolidated Statements of Operations. See Note 14 for additional information on fair value.
The location and pre-tax effect of derivative instruments presented on the Condensed Consolidated Statements of Operations were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Realized gain (loss) on commodity contracts | ||||||||||||||||||||
Energy revenues (a) | $ | 70 | $ | 644 | $ | (433) | ||||||||||||||
Fuel and energy purchases (a) | (20) | (34) | 73 | |||||||||||||||||
| Unrealized gain (loss) on commodity contracts | ||||||||||||||||||||
Operating revenues (b) | $ | 87 | $ | 60 | $ | 184 | ||||||||||||||
Energy expenses (b) | (46) | (123) | 22 | |||||||||||||||||
Realized and unrealized gain (loss) on interest rate contracts | ||||||||||||||||||||
| Interest expense and other finance charges | $ | 1 | $ | — | $ | 25 | ||||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Condensed Consolidated Statements of Operations.
Contract Terminations
Commodity Hedge Terminations. In March and April 2022, Talen and a commercial counterparty terminated certain outstanding economic hedges that were scheduled to be priced and delivered from April 2022 through December 2022. As a result, Talen realized a $124 million termination loss in the six months ended June 30, 2022 (Predecessor) and settled the obligation on a monthly basis through January 2023. The realized termination losses
F-23
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
are presented as “Energy revenues” on the Condensed Consolidated Statement of Operations and repayments are presented as “Derivatives with financing elements” on the Consolidated Statement of Cash Flows.
In May 2022, certain commodity counterparties terminated power and natural gas agreements with a carrying value and fair value of $(33) million prior to the agreements’ scheduled maturity dates. Accordingly, for the six months ended June 30, 2022 (Predecessor), Talen recognized a $33 million net loss presented as either “Energy revenues” or “Fuel and energy purchases” on the Condensed Consolidated Statement of Operations.
Interest Rate Swap Terminations. In May 2022, certain financing counterparties terminated interest rate swap agreements with a carrying value and fair value of $11 million prior to the agreements’ scheduled termination dates. The total notional amount terminated was approximately $500 million. As a result, Talen recognized a realized gain of $11 million to “Interest expense and other finance charges” on the Condensed Consolidated Statement of Operations during the six months ended June 30, 2022 (Predecessor).
6. Revenue
The disaggregation of our operating revenues for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Capacity revenues | $ | 26 | $ | 108 | $ | 247 | ||||||||||||||
| Electricity sales and ancillary services, ISO/RTO | 130 | 281 | 934 | |||||||||||||||||
| Physical electricity sales, bilateral contracts, other | 6 | 62 | 189 | |||||||||||||||||
| Other revenue | 15 | 27 | — | |||||||||||||||||
Total revenue from contracts with customers | 177 | 478 | 1,370 | |||||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | 124 | 732 | (282) | |||||||||||||||||
Operating revenues | $ | 301 | $ | 1,210 | $ | 1,088 | ||||||||||||||
Accounts Receivable
Accounts receivable, net presented on the Condensed Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Customer accounts receivable | $ | 57 | $ | 350 | ||||||||||
| Other accounts receivable | 93 | 58 | ||||||||||||
Accounts receivable, net | $ | 150 | $ | 408 | ||||||||||
There have been no significant changes in accounts receivable other than normal billing and collection transactions. See Note 5 for additional information on Talen’s credit risk on the carrying value of its receivables.
Deferred Revenue
Deferred revenues that were: (i) presented as a liability on the Condensed Consolidated Balance Sheets at June 30, 2023 (Successor) and December 31, 2022 (Predecessor) or (ii) recognized as revenue on the Condensed Consolidated Statements of Operations were not material.
F-24
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
At June 30, 2023 (Successor), the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
2023 (a) | 2024 | 2025 | 2026 | 2027 | |||||||||||||||||||||||||
| Expected capacity revenues | $ | 88 | $ | 170 | $ | 70 | $ | 3 | $ | 1 | |||||||||||||||||||
__________________
(a)For the period from June 30, 2023 through December 31, 2023.
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.
7. Income Taxes
The components of “Income tax benefit (expense)” for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Federal | $ | (3) | $ | (15) | $ | (8) | ||||||||||||||
| State | — | (2) | — | |||||||||||||||||
Current income taxes | (3) | (17) | (8) | |||||||||||||||||
| Federal | (15) | (184) | 87 | |||||||||||||||||
| State | (1) | (11) | (32) | |||||||||||||||||
Deferred income taxes | (16) | (195) | 55 | |||||||||||||||||
| Investment tax credit | — | — | 1 | |||||||||||||||||
Income tax benefit (expense) | $ | (19) | $ | (212) | $ | 48 | ||||||||||||||
| Income (loss) before income taxes | $ | 50 | $ | 677 | $ | (1,202) | ||||||||||||||
Effective income tax rate | 38.0 | % | 31.3 | % | 4.0 | % | ||||||||||||||
F-25
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Income (loss) before income taxes | $ | 50 | $ | 677 | $ | (1,202) | ||||||||||||||
| Income tax benefit (expense) | (19) | (212) | 48 | |||||||||||||||||
Effective tax rate (a) | 38.0 | % | 31.3 | % | 4.0 | % | ||||||||||||||
| Federal income tax statutory tax rate | 21 | % | 21 | % | 21 | % | ||||||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | $ | (10) | $ | (143) | $ | 252 | ||||||||||||||
| Income tax increase (decrease) due to: | ||||||||||||||||||||
| State income taxes, net of federal benefit | (2) | (34) | 61 | |||||||||||||||||
| Change in valuation allowance | 2 | 129 | (282) | |||||||||||||||||
| Permanent differences | (3) | (16) | (12) | |||||||||||||||||
| Nuclear decommissioning trust taxes | (6) | (9) | 28 | |||||||||||||||||
| Reorganization Adjustments | — | (138) | — | |||||||||||||||||
| Investment tax credit | — | — | 1 | |||||||||||||||||
| Other | — | (1) | — | |||||||||||||||||
Income tax benefit (expense) | $ | (19) | $ | (212) | $ | 48 | ||||||||||||||
__________________
(a)The effective tax rate for the Successor period differed from the statutory rate primarily due to the additional 20% trust tax on the NDT income.
Reorganization Adjustments
The Company evaluated the tax impact of the Restructuring including the change in control resulting from Emergence. In Chapter 11 bankruptcy cases, the cancellation of debt income realized upon emergence is excludable from taxable income but results in reduction of tax attributes. As a result of Emergence, the Successor experienced an ownership change under Section 382 of the Code, which is anticipated to subject certain remaining tax attributes an annual limitation. States generally have similar tax attribute limitation rules following an ownership change. See Note 3 for more information on the Restructuring. Upon Emergence, the Company also applied fresh start accounting. As a result, deferred tax assets and liabilities were adjusted based on the Successor US GAAP financial statements. See Note 4 for more information on fresh start accounting.
Valuation Allowance
Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit use of existing deferred tax assets. The assessment of future taxable income includes the scheduled reversal of taxable temporary differences, projected future taxable income, tax planning strategies and results of recent operations. For the January 1 through May 17, 2023 (Predecessor) period, Talen recognized a $129 million benefit for the reduction of federal and state valuation allowance. This release of valuation allowance was caused by tax attribute reduction from the cancellation of debt income realized upon Emergence. For the six months ended June 30, 2022 (Predecessor) period, Talen recognized a $282 million expense for the increase in federal and state valuation allowances, primarily related to pre-tax losses incurred in the period. At each period, management will continue to assess the available positive and negative evidence to determine the need for a valuation allowance.
F-26
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 annual pro-rata decrease will be based upon a portion of the qualifying generation facility’s prior year gross receipts (as defined and calculated per implementation guidelines to be issued). 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 in 2020 through 2022.
These changes are expected to increase Susquehanna Nuclear’s income and impact the expected returns for Talen’s potential future clean energy development projects. However, the Act’s provisions are subject to implementation regulations, whose terms are not yet known, and are subject to amendment by future legislation and, as such, Talen cannot fully predict the impacts to its liquidity or results of operations.
8. Inventory
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Coal | $ | 171 | $ | 189 | ||||||||||
| Oil products | 69 | 61 | ||||||||||||
Fuel inventory for electric generation | 240 | 250 | ||||||||||||
| Materials and supplies, net | 57 | 195 | ||||||||||||
| Environmental products | 21 | 12 | ||||||||||||
Inventory, net | $ | 318 | $ | 457 | ||||||||||
Inventory was adjusted to fair value after the Emergence Date. See Note 4 for additional information.
Net realizable value and obsolescence charges on coal and fuel oil inventories are presented as “Other operating income (expense), net” on the Condensed Consolidated Statements of Operations. Such non-cash charges were a non-material amount for the period from May 18 through June 30, 2023 (Successor), $37 million for the period from January 1 through May 17, 2023 (Predecessor), and a non-material amount for the six months ended June 30, 2022 (Predecessor).
Net realizable value and obsolescence charges on materials and supplies inventories are presented as “Operation, maintenance and development” on the Condensed Consolidated Statements of Operations. Such non-cash charges were a non-material amount for the period from May 18 through June 30, 2023 (Successor), January 1 through May 17, 2023 (Predecessor) and a non-material amount for the six months ended June 30, 2022 (Predecessor).
Net realizable value and obsolescence charges for the period from January 1 through May 17, 2023 (Predecessor) includes an aggregate $24 million charge for Brandon Shores inventories. See Note 10 for additional information on the Brandon Shores recoverability assessment.
F-27
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
9. Nuclear Decommissioning Trust Funds
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | |||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 11 | $ | — | $ | — | $ | 11 | $ | 6 | $ | — | $ | — | $ | 6 | ||||||||||||||||||||||||||||||||||
| Equity securities | 481 | 531 | 58 | 954 | 521 | 485 | 69 | 937 | ||||||||||||||||||||||||||||||||||||||||||
| Debt securities | 538 | 1 | 5 | 534 | 507 | 1 | 31 | 477 | ||||||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | — | — | — | — | (20) | — | — | (20) | ||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | $ | 1,030 | $ | 532 | $ | 63 | $ | 1,499 | $ | 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 at June 30, 2023 or December 31, 2022.
As of June 30, 2023, 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 for the Successor at June 30, 2023 were:
| Fair Value | Unrealized Losses | ||||||||||
| Corporate debt securities | $ | 89 | $ | (1) | |||||||
| Municipal debt securities | 83 | (1) | |||||||||
| U.S. Government debt securities | 279 | (3) | |||||||||
Total debt securities in unrealized loss position (a) | $ | 451 | $ | (5) | |||||||
__________________
(a)Unrealized losses primarily attributed to widening credit spreads.
There were securities for the Successor with a fair value of $75 million that at June 30, 2023 were in a non-material unrealized loss position for a duration of one year or longer.
The contractual maturities for available-for-sale debt securities presented on the Condensed Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Maturities within one year | $ | 16 | $ | 32 | ||||||||||
| Maturities within two to five years | 226 | 173 | ||||||||||||
| Maturities thereafter | 292 | 272 | ||||||||||||
Debt securities, fair value | $ | 534 | $ | 477 | ||||||||||
F-28
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
Sales proceeds of nuclear decommissioning trust funds investments (a) | $ | 271 | $ | 839 | $ | 1,128 | ||||||||||||||
| Gross realized gains | — | 7 | 4 | |||||||||||||||||
| Gross realized (losses) | (2) | (12) | (27) | |||||||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the trust.
10. Property, Plant and Equipment
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||
| Cost | Accumulated Provision | Carrying Value | Cost | Accumulated Provision | Carrying Value | |||||||||||||||||||||||||||||||||
| Electric generation | $ | 3,137 | $ | (20) | $ | 3,117 | $ | 10,596 | $ | (6,797) | $ | 3,799 | ||||||||||||||||||||||||||
| Nuclear fuel | 227 | (11) | 216 | 491 | (316) | 175 | ||||||||||||||||||||||||||||||||
| Other property and equipment | 284 | (4) | 280 | 157 | (82) | 75 | ||||||||||||||||||||||||||||||||
| Intangible assets | — | — | — | 137 | (64) | 73 | ||||||||||||||||||||||||||||||||
| Capitalized software | 4 | — | 4 | 102 | (95) | 7 | ||||||||||||||||||||||||||||||||
| Construction work in progress | 246 | — | 246 | 576 | — | 576 | ||||||||||||||||||||||||||||||||
Property, plant and equipment, net | $ | 3,898 | $ | (35) | $ | 3,863 | $ | 12,059 | $ | (7,354) | $ | 4,705 | ||||||||||||||||||||||||||
Property, plant, and equipment was adjusted to fair value after the Emergence Date. See Note 4 for additional information.
The components of “Depreciation, amortization and accretion” presented on the Condensed Consolidated Statements of Operations were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
Depreciation expense (a) | $ | 23 | $ | 173 | $ | 226 | ||||||||||||||
Amortization expense (b) | 1 | 4 | 6 | |||||||||||||||||
Accretion expense (c) | 4 | 24 | 39 | |||||||||||||||||
Qualifying derivative (gain) loss, net (d) | — | (1) | (1) | |||||||||||||||||
Depreciation, amortization, and accretion | $ | 28 | $ | 200 | $ | 270 | ||||||||||||||
__________________
(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.
(d)Reclassified from AOCI.
F-29
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The cost of nuclear fuel is charged to “Nuclear fuel amortization” on the Condensed Consolidated Statements of Operations.
Favorable Supply Contracts. At the Emergence Date, the Company recognized certain favorable supply contracts for nuclear fuel at their fair value of $109 million in “Other noncurrent assets” on the Condensed Consolidated Balance Sheets. See Note 4 for additional information. During the period from May 18 through June 30, 2023 (Successor), the Company recorded $14 million in amortization expense and the carrying value of these assets at June 30, 2023 was $95 million. For the remainder of 2023, we expect amortization expense to be $39 million. Estimated amortization expense for the next five years is $33 million in 2024, $14 million in 2025, $5 million in 2026, $3 million in 2027, and $1 million in 2028 and after.
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 increased 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 Condensed Consolidated Statements of Operations.
11. Asset Retirement Obligations and Accrued Environmental Costs
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Asset retirement obligations | $ | 447 | $ | 751 | ||||||||||
| Accrued environmental costs | 20 | 35 | ||||||||||||
| Total asset retirement obligations and accrued environmental costs | 467 | 786 | ||||||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | 23 | — | ||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | 219 | ||||||||||||
Asset retirement obligations and accrued environmental costs due after one year | $ | 444 | $ | 567 | ||||||||||
__________________
(a)Presented as “Other current liabilities” at June 30, 2023 (Successor) and as “Liabilities subject to compromise” at December 31, 2022 (Predecessor) on the Condensed Consolidated Balance Sheets.
As a result of the Restructuring: (i) certain portion of ARO and accrued environmental costs were presented as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheets at 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 ARO obligations, 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.
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Asset Retirement Obligations
The changes of the ARO carrying value during the periods were:
| ARO Rollforward | |||||
Carrying value, January 1, 2022 (Predecessor) | $ | 760 | |||
| Obligations settled | (4) | ||||
| Changes in estimates and (or) settlement dates | (1) | ||||
| Obligations incurred | 7 | ||||
| Accretion expense | 38 | ||||
Carrying value, June 30, 2022 (Predecessor) | $ | 800 | |||
| Carrying value, January 1, 2023 (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 | (2) | ||||
| Accretion expense | 4 | ||||
Carrying value, June 30, 2023 (Successor) | $ | 447 | |||
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Supplemental Information | ||||||||||||||
Nuclear (a) | $ | 202 | $ | 564 | ||||||||||
Non-Nuclear (b) | 245 | 187 | ||||||||||||
Carrying value | $ | 447 | $ | 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.
See Note 14 for additional information on Susquehanna Nuclear’s NDT.
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.
12. Commitments and Contingencies
Litigation
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 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.
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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.
Montana Hydroelectric Litigation. Talen Montana is a defendant in litigation in the U.S. District Court for the District of Montana relating to Talen Montana’s past ownership and operation of hydroelectric generation facilities in Montana, which were sold to NorthWestern in November 2014. 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 2012, the U.S. Supreme Court unanimously overturned judgments of the Montana state courts that had held in favor of the State of Montana and remanded the case to the Montana state courts for further proceedings. In April 2016, following an extended period of inactivity, the State filed an updated complaint against both Talen Montana and NorthWestern, making allegations substantially similar to those in the original suit. The case was subsequently removed to the U.S. District Court for the District of Montana (the Montana District Court). In August 2018, the Montana District Court granted Talen Montana’s motion to dismiss claims related to several facilities near Great Falls, Montana. These facilities represented approximately 50% of the damages awarded in the prior judgments that were overturned by the U.S. Supreme Court. In February 2019, the Montana District Court joined the United States and certain federal government entities as co-defendants based on the federal ownership interests in certain of the applicable streambeds. In October 2019, the State filed an amended complaint, adding claims against the United States under the Federal Quiet Title Act. A bench trial on the issue of defendants’ liability was held in January 2022, and 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 Montana, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. This holding may be appealed by any of the parties. Damages and defenses related to this proceeding are to be addressed in a future adjudication. Upon Emergence in May 2023, however, Talen Montana’s liability on all claims asserted by the State was discharged under the Plan of Reorganization; consequently, 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 due to defendants’ other operational failures during Winter Storm Uri. Numerous insurance company plaintiffs also seek to recover payments to policyholders for damage to residential and commercial properties caused by Winter Storm Uri. 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, who are currently seeking appellate review. 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. Any such plaintiffs that did not receive effective notice of the Restructuring under applicable bankruptcy law 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.
In June 2021, Talen Energy Corporation intervened in five cases in which certain market participants are challenging the validity of two PUCT’s 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. Of the remaining cases, one case is pending in the Texas Third Court of Appeals, and two of these cases are pending in State District Court in Travis County, Texas. All of these cases have been abated pending a decision in the primary case, Luminant v. PUCT. In March 2023, the Third Court of Appeals issued an opinion in Luminant v. PUCT that, in part, reversed and remanded the PUCT’s order directing ERCOT to ensure prices were at their maximum of $9,000 per MWh during
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Winter Storm Uri because such orders exceeded the PUCT’s authority. The PUCT (along with Talen Energy Corporation and others) has requested leave to appeal to the Texas Supreme Court. 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.
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.
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 relating to a distribution by Talen Montana to PPL of $733 million of net proceeds from the sale of Talen Montana’s hydroelectric facilities in November 2014 (the Distribution). The action claims that PPL and its directors improperly made the Distribution, leaving Talen Montana without adequate funds to pay its obligations. Plaintiff seeks compensatory and punitive damages. In January 2020, PPL filed a motion to dismiss this suit for, among other things, lack of personal jurisdiction. In September 2020, the Montana state court denied PPL’s motion to dismiss, but granted a stay of the Montana claims until resolution of the Delaware case described below.
In November 2018, PPL filed a lawsuit in Delaware Court of Chancery (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. In October 2019, the Delaware Court granted Talen defendants’ motion to dismiss one of PPL’s claims but denied Talen defendants’ other requests for dismissal.
Finally, after the commencement of the Restructuring, Talen Montana filed an adversary complaint against PPL and its affiliates in the Bankruptcy Court. The adversary complaint asserts claims similar to those asserted in the Montana action. The Montana and Delaware cases were removed to the Bankruptcy Court in August 2022, which consolidated them with the adversary proceeding, Talen Montana and Talen Energy Supply filed an amended and consolidated complaint which asserts substantially the same fraudulent transfer claims, an indemnity claim to recover damages, including defense costs, arising from PPL’s claims, and claims under the Bankruptcy Code to disallow claims asserted by PPL and its affiliates in the Bankruptcy Court and to subordinate any such claims that are allowed. In September 2022, the PPL defendants filed counterclaims substantially similar to the claims asserted in the Delaware Court. In June 2023, the Bankruptcy Court denied the PPL defendants’ motion for partial summary judgment on statute of repose and other limitations alleged to be applicable to Talen Montana’s fraudulent transfer claims and set the case for trial in February 2024. 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. Talen Montana and its affiliates believe that PPL’s claims are without merit and intend to vigorously prosecute and defend these actions. Talen Montana and Talen cannot predict the outcome of this matter or its effect on Talen Montana and Talen; however, a material positive or adverse judgment could effect Talen’s results of operations and liquidity.
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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, and the TERP committee, alleging that they are owed enhanced benefits under the TERP because (i) either: (a) the 2015 Talen Formation Transactions or (b) the 2016 take-private transaction constituted a change in control as defined in the TERP; and (ii) their employment was terminated within three years following such change in control. The lawsuit seeks class action status on behalf of all Talen non-union employees (or their surviving beneficiaries) whose employment was terminated between June 1, 2015 and December 5, 2019 and who were age 55 or older at the time of termination. In January 2022, plaintiffs filed a motion for class certification. The case was abated during the Restructuring, through January 31, 2023. In March 2023, the Court granted plaintiffs leave to amend their complaint to add ten former retirement plan committee members as defendants. At this time, we cannot predict the outcome of this matter or its effect on Talen; however, a material adverse judgment could have an adverse effect on Talen’s results of operations and liquidity.
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, BNSF Railway Company, CSX Transportation, Inc., Norfolk Southern Railway Company and Union Pacific Railroad Company (collectively, the Railroads), violated the 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. There remains substantial uncertainty regarding the nuclear industry’s permanent disposal of spent nuclear fuel. Federal law requires the U.S. Government to provide for the permanent disposal of commercial spent nuclear fuel. Prior to May 2014, nuclear generation facility operators were required to contribute to a fund to pay for the transportation and disposal of spent nuclear fuel. 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.
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 spent nuclear fuel by the statutory deadline. The settlement agreement required the U.S. Government to reimburse certain costs to temporarily store spent nuclear fuel at the Susquehanna nuclear generation facility. In exchange, Susquehanna Nuclear waived any claims against the U.S. Government for costs paid or injuries sustained related to temporarily storing spent nuclear fuel. A claim for such costs was submitted under the agreement in 2023 for costs incurred in 2022. This agreement has been extended four times, most recently in May 2023, through the end of 2025. We cannot be certain that subsequent amendments will extend these arrangements beyond 2025.
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.
Regulatory
Talen is subject to regulation by federal and state agencies 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 Capacity Market
PJM MOPR. In July 2021, PJM filed its proposed tariff language that significantly reduces 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. As FERC did not act on PJM’s July 2021 filing, the PJM MOPR tariff language went into effect in September 2021. FERC did not act on requests for rehearing within 30 days and the requests were deemed to be denied by operation of law. Appeals relating to the narrowed PJM MOPR are pending before the U.S. Court of Appeals for the Third Circuit. As a result, the final impact on Talen’s financial condition, results of operations, or liquidity is not known at this time.
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 2025/2026 in June 2024, 2026/2027 in December 2024, 2027/2028 in June 2025, and 2028/2029 in December 2025.
PJM 2024/2025 Base Residual Auction. PJM delayed the release of the 2024/2025 PJM Base Residual Auction results due to certain issues. In December 2022, PJM filed a request with FERC to revise its tariff to enable PJM to adjust an auction parameter and to make adjustments to subsequent auction outcomes if similar issues arise in future auctions. In February 2023, FERC approved PJM’s filing. Rehearing of FERC’s order was denied by operation of law in April 2023, and several parties have appealed the order to the U.S. Court of Appeals for the Third Circuit. On February 27, 2023, PJM released its 2024/2025 auction results.
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 February 2022, FERC denied rehearing requests on its September 2021 order from multiple parties, including Talen. 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. The final impact of this order on Talen’s financial condition, results of operations or liquidity is unknown at this time.
PJM Capacity 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 Board directive included reliability risks, risk drivers and resource availability. The stakeholder process is referred to as Critical Issue Fast Path (“CIFP”). PJM plans to make a filing at FERC regarding the CIFP changes in October 2023. Talen is participating in the CIFP process, but it is too early in the process to determine impacts to Talen.
Winter Storm Elliot. See “Regulatory – Winter Storm Elliot” below for information relating to Capacity Performance penalties and revenues arising from Winter Storm Elliott, which occurred from December 23 to 27, 2022.
ERCOT Market Systemic Risks. Due to the effects of Winter Storm Uri, certain market participants in ERCOT have defaulted on settlements and caused a deficit of payments to ERCOT. For example, a number of market participants, including co-ops and retail electric providers filed for bankruptcy protection following the winter events primarily in response to unpaid ERCOT settlement invoices. In May 2022, ERCOT reported a cumulative aggregate payment deficit of approximately $2.3 billion as result of winter storm events.
As a result of the ERCOT payment deficits, ERCOT has instituted “short payments.” The short payments 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 June 2021, Texas enacted a law that provides co-ops, retail electric providers and ERCOT the ability to finance, at low-interest rates, costs owed to ERCOT or outstanding default balances that are associated with Winter Storm Uri. Co-op and retail electric providers’ related costs financed through the legislatively designed mechanisms are capped at $2.1 billion and will be repaid by each covered entity. ERCOT’s costs financed through the legislatively designed mechanisms are capped at $800 million and will be repaid through a default charge that is applicable to all market participants. In November 2021, ERCOT notified market participants that payments authorized by the debt obligation order will be disbursed to affected ERCOT QSEs. In September 2022, ERCOT
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reached a settlement agreement with the largest defaulting co-op. 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. The ERCOT Board voted to approve the settlement agreement, and the co-ops’ first payment to ERCOT occurred in December 2022, based on the agreed upon payment schedule over a period of years. The co-ops’ second payment to ERCOT occurred in June 2023.
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 and will consider guidelines established in Texas House Bill 1500 passed during the 2023 legislative session. 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. 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 operation and liquidity.
Winter Storm Elliott. During December 2022, as a result of Winter Storm Elliott, PJM experienced extreme cold weather conditions that contributed to PJM declaring a Maximum Generation Emergency Action. 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 expects to: (i) incur certain Capacity Performance penalties charged by PJM for certain generation facilities; and (ii) earn bonus revenues from PJM for other generation facilities.
In April 2023, FERC approved tariff revisions proposed by PJM that impact the time by which non-performance charges are assessed, including those stemming from Winter Storm Elliot. Specifically, the revisions allow PJM to permit non-performance charges associated with Winter Storm Elliot to be paid over a nine-month period with interest assessed on amounts paid after May 2023. Talen Energy Marketing has elected the extended payment terms.
In April 2023, PJM notified Talen of an update to the expected Capacity Performance penalties incurred by certain of Talen’s generation facilities and bonus revenues earned by other generation facilities. Accordingly, Talen has recognized in 2023 and 2022 an aggregate penalty of $51 million, net of expected bonus revenues. PJM’s estimate could be revised as PJM finalizes its market settlements. In 2023, $13 million of penalties were charged for the period January 1 through May 17, 2023 (Predecessor) and a non-material amount was charged for the period May 18 through June 30, 2023 (Successor) as a reduction to “Capacity revenues” on the Condensed Consolidated Statement of Operations.
Talen and its affiliates have filed complaints against PJM at FERC disputing a significant portion of the penalties assessed by PJM. As a result, the net penalty recognized by Talen could be reduced if the complaints are successfully resolved or settled. Other suppliers are also disputing penalties assessed by PJM. If such disputes were successful, it also would reduce the bonuses payable to Talen and others for overperformance, which could have an effect on Talen’s net penalty exposure. FERC has not yet ruled on the merits of these complaints. At PJM’s request, FERC established settlement proceedings, which were terminated in early September 2023 as a result of the parties reaching a settlement in principle. No assurance can be provided that Talen will be successful in reducing the penalties assessed by PJM.
In December 2022, FERC and NERC announced that they will open a joint inquiry into the operations of the bulk-power system leading up to and during the extreme winter weather conditions that occurred during Winter Storm Elliott. Reliability First and Texas Reliability Coordinator issued document holds for investigative purposes. In March 2023, Talen and other PJM generators, received data requests from FERC and NERC regarding operations of its units during Winter Storm Elliott. Talen responded to such requests in April 2023.
Environmental
Extensive federal, state and local environmental laws and regulations are applicable to our business, including air emissions, water discharges, and hazardous and solid waste management. From time to time, in the ordinary
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course of our business, Talen may become involved in other environmental matters or become subject to other 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
In August and October 2020, the EPA finalized certain changes to the EPA CCR Rule and the EPA ELG Rule. Among other things, changes in both rules allows 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. With Talen’s plans to cease coal operations, Talen requested extensions for compliance for both the EPA ELG Rule and EPA CCR Rule that are applicable to certain of Talen’s 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.
The EPA has recently proposed additional changes to the EPA ELG Rule in March 2023 and to the EPA CCR Rule in May 2023. The ELG 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. For the EPA CCR Rule changes, EPA has proposed to impose new requirements on legacy CCR impoundments and CCR Management Units, which could affect several Talen facilities. Furthermore, 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, Connecticut, Delaware, Maryland and New York have submitted petitions to the EPA under Section 126 of the CAA requesting findings that different upwind coal-fired power generation facilities, including our Brunner Island and Montour generation facilities and the Keystone and Conemaugh generation facilities, in which we own undivided interests, are emitting air pollutants that significantly contribute to non-attainment of the 2008 and 2015 ozone EPA NAAQS in their respective states (each state pointing to different generation facilities). The EPA has denied the petitions. After Delaware, Maryland, New York and certain activists filed petitions for review of the decisions for their states in the U.S. Court of Appeals for the D.C. Circuit, the Court vacated and remanded the Maryland and New York denials. The EPA is in the process of reconsidering the denials. In a parallel effort to attain the EPA NAAQS, in May 2019 Maryland also requested that the Ozone Transport Commission petition EPA to lower air emissions from various generation facilities in Pennsylvania, including some generation facilities owned by Talen. After receiving public comment on the matter in June 2020, the Ozone Transport Commission recommended to EPA that it require additional nitrogen oxides control measures at the affected generation facilities. In December 2020, the EPA published a notice summarizing the Ozone Transport Commission recommendations and seeking comments on the recommendations. Since receiving comments in February 2021, the EPA has yet to take action on the recommendation.
In February 2020, the states of New Jersey, Connecticut, Delaware, New York and Massachusetts, and the City of New York, filed a lawsuit seeking to compel EPA to promulgate EPA FIPS for the EPA 2008 EPA NAAQS to address nitrogen oxide emissions from seven states, including Pennsylvania. In July 2020, the U.S. District Court for the Southern District of New York issued a decision requiring the EPA to issue those EPA FIPS in March 2021. Also, in March 2021, the EPA finalized revisions to the EPA CSAPR that, effective in June 2021, lowered the Ozone Season nitrogen oxide allowance budgets for certain upwind states, including Pennsylvania and Maryland,
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beginning in 2021. Talen had sufficient nitrogen oxide allowances to support generation in the 2022 Ozone Seasons and will manage its electricity generation and allowance inventory to maintain compliance going forward.
To address the 2015 ozone standard, in June 2023, EPA published the final rule covering the CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” EPA has 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 CSAPR and Talen’s facilities in Maryland, Pennsylvania and New Jersey are subject to the new rule. 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.
In May 2022, Pennsylvania updated the PA RACT nitrogen oxide standards for Montour, Keystone and Conemaugh and proposed those standards to EPA as part of its implementation for the EPA 2008 Ozone Standard. However, in August 2022 the EPA finalized an EPA FIP to tighten the standards. The PA DEP agreed to stay the new state standard while all the parties consider the different standards. The EPA FIP has been appealed by other parties and Talen has intervened in the appellate proceeding. In November 2022, Pennsylvania finalized some changes to its nitrogen oxide PA RACT standards (RACT 3) 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.
In April 2023, the EPA issued its EPA RTR (residual risk and technology review) for coal-fired generation facilities under the EPA NESHAP. The EPA MATS Rule, which is the original EPA NESHAP for coal plants has been in effect since 2012. With the publication of their final review, the EPA has proposed changes to the EPA MATS Rule, most notably to reduce particulate matter emissions from coal plants. Talen submitted formal comments to the EPA on the rule, indicating that the 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 October 2019, the Pennsylvania Governor signed an Executive Action Order instructing the PA DEP to move forward with a rulemaking process that would facilitate the entry of the state into the RGGI program. In September 2021, the Independent Regulatory Review Commission provided the final required regulatory approval of the PA DEP’s proposed final rulemaking. However, in October and December 2021, the Pennsylvania House and Senate passed resolutions disapproving the PA DEP’s proposed final rulemaking. In January 2022, the Governor of Pennsylvania vetoed the disapproval resolution. In April 2022, the final rule was published in the “Pennsylvania Code and Bulletin” and became effective, triggering Pennsylvania’s entry into the RGGI program with compliance set to begin on July 1, 2022. However, certain third parties have filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania is currently stayed. In April 2023, the Pennsylvania Governor convened a RGGI work group, of which Talen is a member, to evaluate the state’s entry into RGGI. The timing and potential impacts associated with these legal proceedings and the RGGI work group are uncertain and therefore, may change the state’s participation in the RGGI program, including the compliance timeline. 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
Federal regulators have identified climate change policy as a priority that includes, but is not limited to, goals for greenhouse gas emission reductions. Specifically, for the power sector, after the D.C. Circuit Court vacated and remanded the EPA ACE Rule, in May 2023, the EPA proposed a new Clean Air Act 111(b)/111(d) rule that would establish new source performance standards for new electric generating units and emission guidelines for existing EGUs for State implementation. After considering comments on this proposal, 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
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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 111(b)/111(d) 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.
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 associated with the Talen Formation 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. At June 30, 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 at June 30, 2023 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 at June 30, 2023 (Successor) and $113 million at 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.
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Cumulus Digital Assurances. At June 30, 2023, TES has issued LCs in the aggregate amount of $50 million to the lenders of the Cumulus Digital TLF. The LCs can be drawn upon, among other events, the acceleration of the loan due to a bankruptcy or other event of default by Cumulus Digital. The amount of the LCs will be decreased from time to time based on the outstanding principal balance of the Cumulus Digital TLF.
Additionally, Talen Energy Corporation has 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 will terminate if the principal amount outstanding is reduced to $50 million or less. Amounts are not payable under the guarantee until all available amounts under the TES LCs described above have been drawn.
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. At June 30, 2023, the liability limit per incident is $13.7 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers and an industry retrospective assessment program.
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 $275 million per incident, payable at a maximum of $41 million per year.
Additionally, Susquehanna Nuclear purchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna Nuclear is a member. At June 30, 2023, 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 at June 30, 2023. 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 coal-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 coal-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 vacating the permit amendment pending resolution of the appeal. Merits briefing is complete and oral argument was held in April 2023.
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. Both proceedings are in the early stages.
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 coal-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
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Pursuant to 17 C.F.R. Section 200.83
Ninth Circuit Court of Appeals. MEIC and the plaintiffs moved to dismiss the appeal for lack of jurisdiction, and the federal defendants do not oppose the motion to dismiss. The motion to dismiss and merits briefs are not yet complete.
At this time, Talen cannot predict the outcome of these matters or their effect on Talen Montana’s operations, results of operations or liquidity.
Labor Union Agreement. At June 30, 2023, collective bargaining agreements to which Talen is subject, govern 40% of our workforce. The collective bargaining agreement with IBEW Local 1638, which covers approximately 186 Talen Montana employees, expires in April 2026.
13. Long-Term Debt and Other Credit Facilities
Long-Term Debt
| Successor | Predecessor | |||||||||||||||||||
Interest Rate (a) | June 30, 2023 | December 31, 2022 | ||||||||||||||||||
TLB (b) | 9.59 | % | $ | 580 | $ | — | ||||||||||||||
TLC (c) | 9.59 | % | 470 | — | ||||||||||||||||
| Secured Notes | 8.63 | % | 1,200 | — | ||||||||||||||||
PEDFA 2009B Bonds (f) | 5.05 | % | 50 | 49 | ||||||||||||||||
PEDFA 2009C Bonds (f) | 5.05 | % | 81 | 79 | ||||||||||||||||
Cumulus Digital TLF, including PIK (d) | 12.50 | % | 197 | 185 | ||||||||||||||||
LMBE-MC TLB (e) | 9.05 | % | 293 | 301 | ||||||||||||||||
| Settled Indebtedness | ||||||||||||||||||||
| DIP TLB | N/A | — | 1,000 | |||||||||||||||||
| Prepetition TLB | N/A | — | 427 | |||||||||||||||||
| Prepetition Secured Notes | N/A | — | 1,620 | |||||||||||||||||
Prepetition Unsecured Notes (f) | N/A | — | 1,330 | |||||||||||||||||
PEDFA 2009A Bonds (f) | N/A | — | 100 | |||||||||||||||||
Total Principal | 2,871 | 5,091 | ||||||||||||||||||
| Unamortized deferred finance costs and original issuance discounts | (25) | (29) | ||||||||||||||||||
Total carrying value | 2,846 | 5,062 | ||||||||||||||||||
| Less: long-term debt, due within one year | 14 | 1,010 | ||||||||||||||||||
Less: amounts presented as “Liabilities subject to compromise” (f) | — | 1,558 | ||||||||||||||||||
Long-term debt | $ | 2,832 | $ | 2,494 | ||||||||||||||||
__________________
(a)Computed interest rate at June 30, 2023 (Successor).
(b)$290 million of additional principal amount was incurred under the TLB in August 2023. See “2023 Transactions - LMBE-MC Refinancing” below for additional information.
(c)See “Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities - TLC LCF” for additional information on collateralization securing the TLC LCF.
(d)Limited recourse to TES and TEC. See Note 12 for additional information.
(e)The non-recourse LMBE-MC Credit Agreement indebtedness was repaid and extinguished in August 2023. See “2023 Transactions - LMBE-MC Refinancing” below for additional information.
(f)At December 31, 2022, amounts are presented as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheets. See Note 4 for additional information.
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Revolving Credit and Other Facilities
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||||||||||||||||||||
| Expiration | Committed Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | ||||||||||||||||||||||||||||||||||||||
RCF (a) | May-28 | $ | 700 | $ | — | $ | — | $ | 700 | $ | — | $ | — | |||||||||||||||||||||||||||||||
TLC LCF (b) (c) | May-30 | 470 | — | 462 | 8 | — | — | |||||||||||||||||||||||||||||||||||||
Bilateral LCF (c) | May-28 | 75 | — | 43 | 32 | — | — | |||||||||||||||||||||||||||||||||||||
LMBE-MC RCF (d) | Dec-23 | 25 | — | 12 | 13 | — | 12 | |||||||||||||||||||||||||||||||||||||
| Settled Indebtedness | ||||||||||||||||||||||||||||||||||||||||||||
| DIP RCF | Nov-23 | — | — | — | — | — | 33 | |||||||||||||||||||||||||||||||||||||
| DIP LCF | Nov-23 | — | — | — | — | — | 434 | |||||||||||||||||||||||||||||||||||||
| Prepetition CAF | Sep-24 | — | — | — | — | 848 | — | |||||||||||||||||||||||||||||||||||||
Total | $ | 1,270 | $ | — | $ | 517 | $ | 753 | $ | 848 | $ | 479 | ||||||||||||||||||||||||||||||||
__________________
(a)Committed capacity includes $475 million of LC commitments.
(b)See “Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities - TLC LCF” for additional information on collateralization securing the TLC LCF.
(c)Direct cash borrowings are not permitted under the facility.
(d)Non-recourse to TES and TEC. The LMBE-MC Credit Agreement (including the LMBE-MC RCF) was extinguished on August 9, 2023. See “2023 Transactions - LMBE-MC Refinancing” below for additional information.
Outstanding direct cash borrowings under the RCF and the LMBE-MC RCF, when applicable, are each presented as “Revolving credit facilities” on the Condensed Consolidated Balance Sheets.
At June 30, 2023: (i) TES was not in default under the Credit Facilities (including the RCF, TLB, TLC LCF, and Bilateral LCF), the Secured Notes, or the PEDFA 2009B or 2009C Bonds; (ii) LMBE-MC was not in default under the LMBE-MC Credit Agreement (including the LMBE-MC RCF and LMBE-MC TLB); and (iii) Cumulus Digital was not in default under the Cumulus Digital TLF.
2023 Transactions
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;
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•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 under the Plan of Reorganization.
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.
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 repay in full the $293 million in aggregate principal amount outstanding under the LMBE-MC TLB, following which the LMBE-MC Credit Agreement (including the LMBE-MC TLB and LMBE-MC RCF) was terminated. The outstanding LC issued under the LMBE-MC RCF, which supported debt service reserve requirements under the LMBE-MC TLB, was likewise terminated.
Talen Energy Supply Recourse Debt and Other Credit Facilities
Predecessor Pre-Restructuring Long-Term Debt, Revolving Credit and Other Facilities
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. See Note 3 for additional information on the Restructuring, including the Exit Financings, and Notes 17 and 18 in the Annual Financial Statements for additional information on the DIP Facilities and Talen Energy Supply’s Prepetition Indebtedness.
Prepetition Long-Term Debt and Revolving Credit Facilities. Under the Plan of Reorganization, the $1.4 billion of Prepetition Unsecured Notes and PEDFA 2009A Bonds, presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet at December 31, 2022, were converted to TEC common stock upon Emergence. The PEDFA 2009B and 2009C Bonds, presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet at December 31, 2022, remained outstanding in accordance with the agreed upon terms. See Note 3 for additional information on the Restructuring.
As a result of the Restructuring, interest no longer accrued on the Consolidated Statements of Operation on certain outstanding Prepetition Indebtedness, including the Prepetition Unsecured Notes and the PEDFA Bonds. For the period from January 1 through May 17, 2023 (Predecessor), $49 million of contractual interest expense has not been presented on the Condensed Consolidated Statement of Operations. Talen continued to reimburse the direct-pay LC provider for interest paid on the PEDFA 2009B and 2009C Bonds, as permitted by a final order of the Bankruptcy Court. The interest payments were treated as a reduction to principal.
Talen Energy Supply’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 - Emergence Financings” above for more information about the repayment of the Prepetition TLB, Prepetition Secured Notes, and Prepetition CAF, and See “2023 Transactions -
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Emergence Equitization” above for more information about the equitization of the Prepetition Unsecured Notes and PEDFA 2009A Bonds.
Prepetition LCF-1 and LCF-2. LC issuances were not permitted under the Prepetition LCF-1 and LCF-2 due to the Restructuring. We terminated the Prepetition LCF-2 in May 2023. The Prepetition LCF-1 expired in June 2023.
Prepetition Secured ISDAs. Prior to commencement of the Restructuring, Talen Energy Marketing was party to the certain ISDAs, under which Talen Energy Supply 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 1L Debt) in certain assets in lieu of posting collateral in the form of cash equivalents or LCs (the “Prepetition Secured ISDAs”). Following commencement of the Restructuring, a portion of the Prepetition Secured ISDAs were rolled over into DIP Secured ISDAs. The Prepetition Secured ISDAs that were not rolled into DIP Secured ISDAs remained in place and continued to be secured by first priority liens that were subordinated to the superpriority liens securing the DIP Facilities and the DIP Secured ISDAs. As of May 18, 2023, post-emergence from Restructuring, the remaining Prepetition Secured ISDAs were rolled into the Secured ISDAs. The secured obligations under the remaining Prepetition Secured ISDAs were a non-material amount at December 31, 2022 (Predecessor).
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 LCs outstanding under the Prepetition RCF as of commencement of the Restructuring to remain outstanding with superpriority status. Amounts owing 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 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 the certain 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 (the “DIP Secured ISDAs”). 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. The secured obligations under the DIP Secured ISDAs were $77 million at December 31, 2022 (Predecessor).
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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 2/9/24 in connection with a repricing transaction | ||||||||||||||||||||||
| TLC (TLC LCF) | May 2030 | Term SOFR | 4.50% per annum applicable margin No amortization | 1.00% to the extent prepaid prior to 11/17/23 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 (letters of credit) | May 2028 | Federal Funds Rate | None | None | ||||||||||||||||||||||
| Bilateral LCF | May 2028 | Prime Rate | None | 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 $50 million of undrawn revolving 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.
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.
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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 $462 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 $473 million at June 30, 2023 (Successor) which is presented as “Restricted Cash and cash equivalents” on the Condensed Consolidated Balance Sheet. 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. 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 asset sales. 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 letters of credit totaling $135 million as of June 30, 2023. See Note 18 to the Annual Financial Statements for additional information on the terms of the PEDFA Bonds.
Secured ISDAs. Talen Energy Marketing is party to certain ISDAs, a portion of which are continuations of either the Prepetition Secured ISDAs or the DIP Secured ISDAs (the “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 $65 million at June 30, 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 are cash collateralized by $473 million at June 30, 2023 (Successor) (which is presented as “Restricted Cash and cash equivalents” on the Condensed Consolidated Balance Sheet) with such amounts being held in restricted collateral accounts, first, for the benefit of the issuers of LCs pursuant to the TLC and, thereafter, as security for the obligations under the Credit Facilities (other than the TLC), 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.
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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.
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.
Non-Recourse Debt and Other Credit Facilities
Cumulus Digital TLF. In March 2023, the Cumulus Digital Credit Agreement 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.
See Note 12 for information on LCs issued by TES and a guarantee issued by Talen Energy Corporation related to the Cumulus Digital TLF.
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 Susquehanna Nuclear NDT.
The classifications of recurring fair value measurements within the fair value hierarchy were:
| Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| June 30, 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 | $ | — | $ | — | $ | — | $ | 11 | $ | — | $ | 11 | $ | — | $ | — | $ | — | $ | 6 | $ | 6 | ||||||||||||||||||||||||||||||||||||||||||||||
Equity securities (b) | 584 | — | — | 370 | — | 954 | 508 | — | — | 429 | 937 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 298 | — | — | — | — | 298 | 272 | — | — | — | 272 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | 87 | — | — | — | 87 | — | 91 | — | — | 91 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 148 | — | — | — | 148 | — | 114 | — | — | 114 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Other debt securities | — | 1 | — | — | — | 1 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | — | (20) | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Nuclear decommissioning trust funds | 882 | 236 | — | 381 | — | 1,499 | 780 | 205 | — | 435 | 1,400 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | 434 | 369 | 12 | — | (649) | 166 | 1,807 | 565 | 12 | — | 2,384 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 5 | — | — | — | 5 | — | 9 | — | — | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total assets | $ | 1,316 | $ | 610 | $ | 12 | $ | 381 | $ | (649) | $ | 1,670 | $ | 2,587 | $ | 779 | $ | 12 | $ | 435 | $ | 3,793 | ||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives (d) | $ | 486 | $ | 295 | $ | 2 | $ | — | $ | 705 | $ | 78 | $ | 1,879 | $ | 411 | $ | — | $ | — | $ | 2,290 | ||||||||||||||||||||||||||||||||||||||||||||||
| Less: other | — | — | — | — | — | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Total liabilities | $ | 486 | $ | 295 | $ | 2 | $ | — | $ | 705 | $ | 78 | $ | 1,879 | $ | 410 | $ | — | $ | — | $ | 2,289 | ||||||||||||||||||||||||||||||||||||||||||||||
__________________
(a)Amounts represent the impact of legally enforceable master netting arrangements that allow Talen to settle positions and also for 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.
F-47
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(d)A portion of these amounts have been presented as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheet. See Note 4 for additional information.
The changes in the net Level 3 commodity derivative assets and liabilities for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Asset (liability), net, beginning of the period | $ | 8 | $ | 12 | $ | (6) | ||||||||||||||
| Gains (losses), net, included in earnings | 4 | 1 | (75) | |||||||||||||||||
| Settlements | (2) | (5) | (6) | |||||||||||||||||
Asset (liability), net, end of the period | $ | 10 | $ | 8 | $ | (87) | ||||||||||||||
The significant unobservable inputs used in the Successor fair value measurement of Level 3 commodity derivatives at June 30, 2023 were:
| Transaction Type | Valuation Technique | Unobservable Input | Low End Range | High End Range | Weighted Average (a) | Fair Value | ||||||||||||||||||||||||||||||||
| Congestion Products | Congestion Auction Results | Forward congestion price | $0.39/MWh | $120.05/MWh | $46.84/MWh | 10 | ||||||||||||||||||||||||||||||||
__________________
(a)Weighted average is based on notional volumes at June 30, 2023.
The significant unobservable inputs used in the Predecessor fair value measurement of Level 3 commodity derivatives at June 30, 2022 (Predecessor) were:
| Transaction Type | Valuation Technique | Unobservable Input | Low End Range | High End Range | Weighted Average (a) | Fair Value | ||||||||||||||||||||||||||||||||
| Congestion Products | Historical congestion | Forward congestion price | $(8.05)/MWh | $171.83/MWh | $4.46/MWh | $ | 12 | |||||||||||||||||||||||||||||||
| Heat rate options | Option models | Power volatilities | 27% | 98% | 54% | (101) | ||||||||||||||||||||||||||||||||
| Gas volatilities | 6% | 17% | 13% | |||||||||||||||||||||||||||||||||||
| Power and gas correlation | (1)% | 35% | 16% | |||||||||||||||||||||||||||||||||||
__________________
(a)Weighted average is based on notional volumes at December 31, 2022.
The sensitivity of fair value measurements to changes in significant unobservable inputs at June 30, 2023 (Successor) and June 30, 2022 (Predecessor) were:
| Significant Unobservable Input | Position | Change in Input | Fair Value Effect | |||||||||||||||||
| Forward congestion price | Purchased pathway | Price increase / decrease | Higher / (Lower) | |||||||||||||||||
| Forward congestion price | Sold pathway | Price increase / decrease | Lower / (Higher) | |||||||||||||||||
| Power and gas spread volatilities | Sold call option | Spread increase / decrease | Lower / (Higher) | |||||||||||||||||
| Power and gas correlation | Sold call option | Correlation increase / decrease | Higher / (Lower) | |||||||||||||||||
F-48
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The net gains and losses of Level 3 commodity derivatives for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Energy Revenues | ||||||||||||||||||||
| Gains (losses) included in earnings | $ | 4 | $ | 1 | $ | (75) | ||||||||||||||
Change in unrealized gains (losses) (a) | 2 | (4) | (81) | |||||||||||||||||
__________________
(a)Amounts included in earnings for positions still held at the end of each reporting date.
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 2023. There were no nonrecurring fair value measurements related to impairments of long-lived assets during the six months ended June 30, 2022 (Predecessor).
Reported Fair Value
The carrying value of certain assets and liabilities on the Condensed 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.
The carrying value and fair value of indebtedness presented on the Condensed Consolidated Balance Sheets were:
| Successor | Predecessor | |||||||||||||||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||||||
| Revolving credit facilities | $ | — | $ | — | $ | 848 | $ | 848 | ||||||||||||||||||
Long-term debt (a) | 2,846 | 2,908 | 5,062 | 4,386 | ||||||||||||||||||||||
__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Condensed Consolidated Balance Sheets.
15. Postretirement Benefit Obligations
In the second quarter 2023, upon Emergence, Talen: (i) performed a valuation of its defined benefit pension plans and other postretirement benefit plans; and (ii) made changes to related accounting policies. See Notes 2 and 4 for additional information on these matters.
Obligations under defined benefit pension plans and other postretirement benefit plans are generally based on individual participant factors such as age, years of service, and compensation. The defined benefit pension plans and other postretirement benefit plans are closed to new participants. Due to the Restructuring, as of December 31, 2022, all of Talen’s unfunded or underfunded postretirement obligations were presented as “Liabilities subject to compromise” on the Condensed Consolidated Balance Sheets. Following Emergence, Talen and Talen Montana’s respective qualified defined benefit pension and other postretirement plans continue to be in effect in accordance with their terms pursuant to the Plan of Reorganization.
F-49
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The components of net periodic benefit costs were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
Postretirement benefits service cost (a) | $ | — | $ | 1 | $ | 3 | ||||||||||||||
| Interest cost | 8 | 27 | 26 | |||||||||||||||||
| Expected return on plan assets | (8) | (33) | (36) | |||||||||||||||||
| Amortization of: | ||||||||||||||||||||
| Net loss | — | 2 | 14 | |||||||||||||||||
Postretirement benefits (gain) loss, net (b) | — | (4) | 4 | |||||||||||||||||
Net periodic defined benefit cost (credit) | $ | — | $ | (3) | $ | 7 | ||||||||||||||
__________________
(a)Activity presented as “Operation, maintenance and development” on the Condensed Consolidated Statement of Operations.
(b)Activity presented as “Other non-operating income (expense), net” on the Condensed Consolidated Statement of Operations.
16. Capital Structure
Predecessor
At December 31, 2022, outstanding shares of Talen Energy Corporation 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.
Successor
Our Third Amended and Restated Certificate of Incorporation, which became effective at Emergence, authorizes Talen Energy Corporation 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, Talen Energy Corporation issued 59,028,843 shares of common stock. The same number of shares remained outstanding at June 30, 2023. 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 the Company) when, as and if declared thereon by the board of directors of the Company.
Registration Rights Agreement and Stockholders Agreement. In connection with Emergence, Talen Energy Corporation entered into a Registration Rights Agreement and the Stockholders Agreement with certain of its stockholders party thereto. 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 Talen Energy Corporation to pursue and consummate an initial public offering and to consent to certain key elements of the initial public offering structure.
F-50
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Liability-Classified Warrants. At Emergence, Riverstone received liability-classified warrants to purchase up to 5%, 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. These warrants meet the criteria for liability classification due to a contingent put option which allows the holder to require that the Company redeem the warrants in cash upon certain change of control events. The fair value of the liability-classified warrants at June 30, 2023 was $49 million and was presented as “Other noncurrent liabilities” in the Condensed Consolidated Balance Sheets. In August 2023, Riverstone agreed to surrender these warrants in exchange for a cash payment. See Note 22 for more information.
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 initially valued at $8 million using the above strike price, 30.0% volatility, and a risk-free rate of 3.6%.
Retail PPA Incentive Equity. Pursuant to the Plan of Reorganization and the TEC Global Settlement, at Emergence, the Company issued approximately 243 thousand 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 exercises an option with Talen Generation to purchase additional electricity generated by Susquehanna, as further described in the Plan of Reorganization. In August 2023, TEC agreed to waive its right to this additional portion of the Retail PPA Incentive Equity in exchange for a cash payment. See Note 22 for more information.
17. 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 June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Numerator: (Millions) | ||||||||||||||||||||
Net Income (loss) | $ | 31 | $ | 465 | (1,154) | |||||||||||||||
| Exclude: | ||||||||||||||||||||
| Net income (loss) attributable to noncontrolling interest | 2 | (14) | — | |||||||||||||||||
Net Income (loss) attributable to the Company | $ | 29 | $ | 479 | $ | (1,154) | ||||||||||||||
| Denominator: (Thousands) | ||||||||||||||||||||
| Weighted-average shares outstanding - Basic | 59,029 | — | — | |||||||||||||||||
| Warrants | 32 | — | — | |||||||||||||||||
| Restricted stock units | 27 | — | — | |||||||||||||||||
Weighted-average shares outstanding - Diluted | 59,088 | — | — | |||||||||||||||||
Basic earnings (loss) per share | $ | 0.49 | $ | — | $ | — | ||||||||||||||
Diluted earnings (loss) per share | 0.49 | — | — | |||||||||||||||||
F-51
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
For the period from May 18 through June 30, 2023 (Successor), basic EPS of $0.49 per share includes 59,028,843 shares of common stock outstanding. For the period from January 1 through May 17, 2023 (Predecessor), there were no outstanding shares of common stock attributed to the Predecessor.
For the period from May 18 through June 30, 2023 (Successor), diluted EPS of $0.49 per share includes 31,631 warrants and 27,503 restricted stock units (“RSUs”) outstanding. For the period from January 1 through May 17, 2023 (Predecessor), there were no outstanding warrants or RSUs attributed to the Predecessor.
Diluted EPS during the period ended June 30, 2023 excludes the impact of 3,106,781 warrants outstanding due to their anti-dilutive nature. The Company had share-based compensation awards outstanding during the periods presented with vesting provisions subject to certain time and performance based conditions. Because neither the time nor the performance conditions have been met during the reporting period, these awards are excluded from the calculation of diluted EPS.
18. Accumulated Other Comprehensive Income
The total changes in AOCI for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Beginning balance | $ | — | $ | (167) | $ | (152) | ||||||||||||||
| Gains (losses) arising during the period | (6) | 6 | (54) | |||||||||||||||||
| Reclassifications to Condensed Consolidated Statements of Operations | 1 | 5 | 35 | |||||||||||||||||
| Income tax benefit (expense) | 2 | (5) | 9 | |||||||||||||||||
| Other comprehensive income (loss) | (3) | $ | 6 | (10) | ||||||||||||||||
| Cancellation of equity at Emergence | 161 | |||||||||||||||||||
Accumulated other comprehensive income | $ | (3) | $ | — | $ | (162) | ||||||||||||||
The components of AOCI, net of tax, at June 30 were:
| Successor | Predecessor | |||||||||||||
| 2023 | 2022 | |||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | (3) | $ | (14) | ||||||||||
| Qualifying derivatives unrealized gain (loss), net | — | 9 | ||||||||||||
| Postretirement benefit prior service credits (costs), net | — | 6 | ||||||||||||
| Postretirement benefit actuarial gain (loss), net | — | (163) | ||||||||||||
Accumulated other comprehensive income | $ | (3) | $ | (162) | ||||||||||
The locations of pre-tax gains (losses) reclassified from AOCI and included on the Condensed Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | ||||||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | |||||||||||||||||||||
| Location of gain (loss) | 2023 | 2023 | 2022 | ||||||||||||||||||||
Nuclear decommissioning trust funds gain (loss), net (a) | $ | (1) | (4) | $ | (23) | ||||||||||||||||||
Depreciation, amortization and accretion (b) | — | 1 | 1 | ||||||||||||||||||||
Postretirement benefit gain (loss), net (c) | — | (2) | (13) | ||||||||||||||||||||
Total | $ | (1) | $ | (5) | $ | (35) | |||||||||||||||||
__________________
(a)Available-for-sale securities unrealized gain (loss), net
F-52
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(b)Qualifying derivatives unrealized gain (loss)
(c)Postretirement benefit prior service credits (costs), net and Postretirement benefit actuarial gain (loss), net
The postretirement obligations components of AOCI are not presented in their entirety on the statement 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-53
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
19. Supplemental Cash Flow Information
Supplemental information for the Condensed Consolidated Statements of Cash Flows for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| May 18 through June 30, | January 1 through May 17, | Six Months Ended June 30, | ||||||||||||||||||
| 2023 | 2023 | 2022 | ||||||||||||||||||
| Cash paid (received) during the period | ||||||||||||||||||||
| Interest and other finance charges, net of capitalized interest ($3 million for May 18 to June 30 and $12 million for January 1 to May 17 in 2023 and $3 million in 2022) | $ | 2 | $ | 283 | $ | 99 | ||||||||||||||
| Income taxes, net | 3 | 7 | 11 | |||||||||||||||||
| Non-cash investing and operating activities | ||||||||||||||||||||
| Capital expenditure accrual increase (decrease) | $ | 1 | $ | (28) | $ | 8 | ||||||||||||||
| Accounts receivable contributed to equity method investment | — | — | 2 | |||||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Operations: | ||||||||||||||||||||
| Depreciation, amortization and accretion | $ | 28 | $ | 200 | $ | 270 | ||||||||||||||
Amortization of deferred finance costs and original issuance discounts (interest expense) (a) | 1 | 8 | 18 | |||||||||||||||||
| Other | (2) | — | — | |||||||||||||||||
Total | $ | 27 | $ | 208 | $ | 288 | ||||||||||||||
| Non-cash financing/investing activities | ||||||||||||||||||||
Non-cash increase to PP&E and decrease to other current assets for transfer of miners by Cumulus Coin (b) | $ | — | $ | 14 | $ | — | ||||||||||||||
| 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 | — | |||||||||||||||||
| Unrealized (gain) loss on derivatives: | ||||||||||||||||||||
| Commodity contracts | $ | (41) | $ | 63 | $ | (206) | ||||||||||||||
| Interest rate swap contracts | 2 | 2 | (20) | |||||||||||||||||
Total | $ | (39) | $ | 65 | $ | (226) | ||||||||||||||
| Operating activities reconciliation adjustments, other: | ||||||||||||||||||||
| Net periodic defined benefit cost | $ | 1 | $ | (3) | $ | 6 | ||||||||||||||
| Derivative option premium amortization | 9 | 29 | 35 | |||||||||||||||||
| Bitcoin revenue | (15) | (27) | — | |||||||||||||||||
| Non-cash environmental liability revisions | — | — | 13 | |||||||||||||||||
| Gain on sale of mineral rights and western gas portfolio | — | (44) | — | |||||||||||||||||
| Gain on cancellation of lease | — | (7) | — | |||||||||||||||||
| Nonrecourse PIK interest | 3 | 9 | (7) | |||||||||||||||||
| Mark-to-market on warrant | 14 | — | — | |||||||||||||||||
| Derivatives with financing elements | — | — | 21 | |||||||||||||||||
| Debt restructuring (gain) loss, net | — | — | 6 | |||||||||||||||||
| Other | 5 | — | — | |||||||||||||||||
Total | $ | 17 | $ | (43) | $ | 74 | ||||||||||||||
F-54
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
__________________
(a)Includes previously recognized fair value adjustments on certain exchanges of indebtedness.
(b)In 2023, each of the joint venture partners of Nautilus made non-cash contributions to Nautilus of cryptocurrency miners that increased PPE.
Cash and Restricted Cash
The following provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Condensed Consolidated Statements of Cash Flows to line items within the Condensed Consolidated Balance Sheets:
| Successor | Predecessor | |||||||||||||
| June 30, 2023 | December 31, 2022 | |||||||||||||
| Cash and cash equivalents | $ | 127 | $ | 724 | ||||||||||
| Restricted cash and cash equivalents: | ||||||||||||||
| Commodity exchange margin | 3 | 85 | ||||||||||||
Collateral deposits (a) | — | 89 | ||||||||||||
| TES TLC debt restricted deposits | 473 | — | ||||||||||||
| Cumulus Digital Holdings debt restricted deposits | 35 | 49 | ||||||||||||
| Nautilus project restricted deposits | 18 | 19 | ||||||||||||
| LMBE-MC major maintenance reserve deposits | — | 7 | ||||||||||||
LMBE-MC debt service reserve deposits (b) | 15 | 7 | ||||||||||||
TEC Global Settlement deposits (c) | — | 7 | ||||||||||||
| Escrow deposits for professional fees | 44 | — | ||||||||||||
| Other | — | 1 | ||||||||||||
| Restricted cash and cash equivalents | 588 | 264 | ||||||||||||
Total | $ | 715 | $ | 988 | ||||||||||
__________________
(a)Collateral deposits that support the DIP LCF. Funds were returned to Talen on the Emergence Date.
(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 on the Emergence Date.
20. 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
Talen historically has 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 the Emergence Date.
In the six months ended June 30, 2022 (Predecessor), the aggregate fees incurred for services and reimbursements was $3 million. These fees are presented as “General and administrative” on the Condensed Consolidated Statement of Operations.
F-55
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 Talen Energy Corporation’s professional advisors; (ii) deposited $7 million in a custodial account presented as “Restricted cash” on the December 31, 2022 Consolidated Balance Sheet that was to be used to pay fees and expenses of Talen Energy Corporation’s advisors when due. The $7 million was released from Talen restricted cash at Emergence.
In recent years, TES has paid certain expenses and liabilities incurred by Talen Energy Corporation. Accordingly, at December 31, 2022 (Predecessor), TES presented $2 million due from Talen Energy Corporation as “Accounts receivable, net” presented on the Condensed Consolidated Balance Sheets. Such amounts were settled in connection with the Plan of Reorganization on the Emergence Date.
During 2022, Talen engaged parties related to two employees in management positions, both under two separate independent contractor agreements for office maintenance and IT services. In six months ended June 30, 2022 (Predecessor), Talen paid approximately $66 thousand under these agreements. The contracts with these independent contractors were terminated in July 2022.
See Notes 12 and 24 to the Annual Financial Statements for additional information on the above and other related party transactions.
Cumulus Digital Agreements with TES
TES and (or) its subsidiaries have executed certain agreements with Cumulus Digital Holdings and (or) its respective subsidiaries. Such agreements include, but are not limited to: (i) the Nautilus FOA and the Cumulus Digital COSA, pursuant to which TES provides administrative and operational services to Cumulus Digital and its subsidiaries; (ii) the Nautilus Ground Lease Agreement for the Nautilus site; and (iii) certain energy supply agreements, which are supporting, or will support, Cumulus Data’s power requirements (including its obligations to provide sub-metered power to Nautilus under the Nautilus Ground Lease Agreement).
See Note 12 for information on LCs provided by TES and a guarantee provided by TEC supporting Cumulus Digital’s obligations under the Cumulus Digital TLF.
21. 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 Energy, Inc. will retain certain liabilities attributable to pre-closing operations, including environmental remediation and decommissioning costs, and Talen Montana will assume those liabilities for post-closing operations. Until the closing of the transaction, Talen Montana is entitled to increased voting rights (via Puget Sound’s voting rights) regarding certain decisions relating to Colstrip Units 3 and 4. The agreement is subject to customary closing conditions, including Bankruptcy Court approval. In addition, the co-owners of Colstrip Units 3 and 4 have certain rights of first refusal that may entitle them to acquire a portion of the interest being transferred by Puget Sound. 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 enjoys 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 Energy, Inc.’s interest in Colstrip Units 3 and 4.
Talen Montana owns 30% of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in agreements regarding the ownership and operation of Colstrip Units 3 and 4, whereby Talen Montana is responsible for 15% of the total operating costs and expenditures of Colstrip Unit 3 and 15% of Colstrip Unit 4. Accordingly, it is entitled to 15% of the available generation from each of these units. If the transaction is consummated on the terms of the agreement, assuming no co-owner exercises right of first refusal, Talen Montana
F-56
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
will own a 55% share of Colstrip Unit 3 and a 25% share of Colstrip Unit 4 and continue to be the sole operator of both Colstrip Units 3 and 4.
Completed Divestitures
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 Condensed 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 Condensed Consolidated Statements of Operations.
22. 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 maker function reviews results and allocates resources. Segment Adjusted EBITDA is the key profit metric used to measure financial performance. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker function.
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;
•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 our reportable segments; (ii) the development activities of Cumulus Growth Holdings; (iii) the development and operating activities of Cumulus Digital; (iv) other immaterial components that are not regularly reviewed by our chief operating decision maker; 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 June 30, 2023 (Successor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 354 | $ | (56) | $ | 3 | $ | 301 | |||||||||||||||
| Interest expense | — | — | 33 | 33 | |||||||||||||||||||
| Capital expenditures | 23 | 5 | 6 | 34 | |||||||||||||||||||
| Segment Adjusted EBITDA | 74 | 17 | 91 | ||||||||||||||||||||
F-57
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
| 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 | |||||||||||||||||||
| Segment Adjusted EBITDA | 687 | 31 | 718 | ||||||||||||||||||||
| Six Months Ended June 30, 2022 (Predecessor) | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 1,238 | $ | (33) | $ | (117) | $ | 1,088 | |||||||||||||||
| Interest expense | — | — | 172 | 172 | |||||||||||||||||||
| Capital expenditures | 98 | 6 | 2 | 106 | |||||||||||||||||||
| Segment Adjusted EBITDA | 306 | 42 | 348 | ||||||||||||||||||||
| Successor | Predecessor | Predecessor | ||||||||||||||||||
| May 18, 2023 through June 30, 2023 | January 1, 2023 through May 17, 2023 | Six Months Ended June 30, 2022 | ||||||||||||||||||
| Segment Adjusted EBITDA: | ||||||||||||||||||||
| PJM | $ | 74 | $ | 687 | $ | 306 | ||||||||||||||
| ERCOT and WECC | 17 | 31 | 42 | |||||||||||||||||
Total Segment Adjusted EBITDA | $ | 91 | $ | 718 | $ | 348 | ||||||||||||||
| Reconciling Items: | ||||||||||||||||||||
| Bankruptcy, Liability Management and Restructuring Activities | $ | (12) | $ | 782 | $ | (1,003) | ||||||||||||||
| Interest expense and other finance charges | (33) | (163) | (172) | |||||||||||||||||
| Income tax benefit (expense) | (19) | (212) | 48 | |||||||||||||||||
| Depreciation, amortization and accretion | (28) | (200) | (270) | |||||||||||||||||
| Nuclear fuel amortization | (25) | (33) | (47) | |||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 41 | (63) | 206 | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 39 | 57 | (191) | |||||||||||||||||
| Gain (loss) on non-core asset sales, net | — | 50 | 1 | |||||||||||||||||
| Unusual market events | (1) | (14) | 1 | |||||||||||||||||
| Impairments, canceled projects, inventory net realizable value and obsolescence, and receivables allowance | (3) | (437) | 1 | |||||||||||||||||
| Corporate, development and other | (19) | (20) | (76) | |||||||||||||||||
Net Income (Loss) | $ | 31 | $ | 465 | $ | (1,154) | ||||||||||||||
23. Subsequent Events
Talen originally evaluated subsequent events through August 14, 2023, the date the financial statements were initially issued. We further evaluated subsequent events for disclosure from the initial issuance date until the date these financial statements were issued on September 8, 2023. All significant subsequent events are included in their respective notes to the financial statements, with the exception of the agreements described below.
F-58
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Riverstone Warrant Cancellation
On August 10, 2023, TEC, TES and Riverstone entered into an agreement pursuant to which (i) Riverstone agreed to surrender all of its warrants to purchase TEC common stock to TEC for cancellation and to waive all future rights to the Retail PPA Incentive Equity; and (ii) TEC, TES and Riverstone agreed to terminate and cancel a tax indemnity agreement executed by them in connection with the TEC Global Settlement. TEC agreed to pay Riverstone $40 million in exchange for these cancellations and waivers. The cancellations and waivers were consummated concurrently with the consummation of the Riverstone Buyout described below.
Riverstone Buyout
On August 10, 2023, Riverstone and TES entered into a purchase and sale agreement pursuant to which TES agreed to purchase 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”). Under the terms of the Cumulus Digital Holdings limited liability company agreement, the other members of Cumulus Digital Holdings had a right to participate in the Riverstone Buyout on a pro rata basis based on their and TES’s respective ownership of Cumulus Digital Holdings common units. The transaction closed in the third quarter of 2023. Upon closing, TES’s ownership interest in Cumulus Digital Holdings increased to approximately 95%. Affiliates of Orion also elected to participate in the Riverstone Buyout and acquired an additional 1% interest. TES has sole control of the Cumulus Digital Holdings board of managers following the closing of the Riverstone Buyout.
F-59
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Report of Independent Registered Public Accounting Firm
To the Board of Directors and Shareholders of Talen Energy Corporation
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Talen Energy Supply, LLC and its subsidiaries (debtors-in-possession) (the “Company”) as of December 31, 2022 and 2021, and the related consolidated statements of operations, comprehensive income, equity and cash flows for each of the three 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 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 in conformity with accounting principles generally accepted in the United States of America.
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.
Substantial Doubt about the Company’s Ability to Continue as a Going Concern Has Been Removed
Management and we previously concluded there was substantial doubt about the Company’s ability to continue as a going concern. As discussed in Note 2, management has subsequently taken certain actions, which management and we have concluded remove that substantial doubt.
Emphasis of Matter
As discussed in Notes 2 and 3 to the consolidated financial statements, in May 2022 the Company filed voluntary petitions under Chapter 11 of the Bankruptcy Code and in December 2022, Talen Energy Corporation became a debtor in the restructuring contemplated by the plan of reorganization. The Bankruptcy Court approved the plan of reorganization in December 2022, which became effective on May 17, 2023 when the Company emerged from bankruptcy.
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
F-60
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
Accounting for bankruptcy
As described in Notes, 2 and 3 to the consolidated financial statements, in May 2022, Talen Energy Supply and the majority of its direct and indirect wholly owned subsidiaries filed voluntary petitions under Chapter 11 of the Bankruptcy Code in the Southern District of Texas. As a result, management has applied generally accepted accounting principles applicable to reorganizations in preparing the consolidated financial statements. Pre-petition liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the restructuring are presented as liabilities subject to compromise on the consolidated balance sheet and are presented at the best estimate of the claim amount permitted by the Bankruptcy Court. 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 statement of operations. As of and for the year ended December 31, 2022, the Company recorded reclassifications of $2.825 billion to liabilities subject to compromise, and $812 million to reorganization income (expense), net. Further, the Bankruptcy Court issued an order that allowed the Debtors to reject contracts for power supply related to the Talen Energy Marketing retail business and an order that allowed the Company to reject contracts for certain service agreements, contracts for the supply of gypsum, and a land lease. In the second quarter 2022, the Company recognized a charge of $447 million and in the fourth quarter 2022, the Company recognized an associated charge of $41 million on the consolidated statement of operations in operational restructuring, related to rejected contracts.
The principal considerations for our determination that performing procedures relating to accounting for bankruptcy impacts is a critical audit matter are (i) the high degree of audit effort in performing procedures related to the accounting for bankruptcy; and (ii) 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, testing contracts, on a sample basis, to assess the completeness, accuracy, and presentation and disclosure of rejected contract charges recorded within operational restructuring. Professionals with specialized skill and knowledge were used to assist in reading the Plan of Reorganization agreement and related court dockets, and performing procedures related to: (1) liabilities subject to compromise, which included testing, on a sample basis, (a) the completeness and classification by management of pre-petition liabilities as either secured or unsecured, (b) the accuracy of the amounts recorded based on management’s best estimate of the claim amount permitted, and (c) the classification of the aforementioned liabilities, and (2) reorganization income (expense), net, which included testing, on a sample basis, the accuracy and classification of expenses categorized as reorganization income (expense), net.
/s/ PricewaterhouseCoopers LLP
Houston, Texas
September 8, 2023
We have served as the Company’s auditor since 2017.
F-61
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
CONSOLIDATED STATEMENTS OF OPERATIONS FOR THE YEARS ENDED DECEMBER 31
(Millions of Dollars)
| 2022 | 2021 | 2020 | |||||||||||||||
| Capacity revenues | $ | 377 | $ | 444 | $ | 315 | |||||||||||
| Energy and other revenues | 2,035 | 1,331 | 1,480 | ||||||||||||||
| Unrealized gain (loss) on derivative instruments | 677 | (847) | (69) | ||||||||||||||
Operating Revenues | 3,089 | 928 | 1,726 | ||||||||||||||
| Energy Expenses | |||||||||||||||||
| Fuel and energy purchases | (938) | (856) | (649) | ||||||||||||||
| Nuclear fuel amortization | (94) | (96) | (106) | ||||||||||||||
| Unrealized gain (loss) on derivative instruments | (52) | 135 | 36 | ||||||||||||||
Total Energy Expenses | (1,084) | (817) | (719) | ||||||||||||||
| Operating Expenses | |||||||||||||||||
| Operation, maintenance and development | (610) | (584) | (595) | ||||||||||||||
| General and administrative | (106) | (88) | (82) | ||||||||||||||
| Depreciation, amortization and accretion | (520) | (524) | (452) | ||||||||||||||
| Operational restructuring | (488) | — | — | ||||||||||||||
| Impairments | — | — | (681) | ||||||||||||||
| Other operating income (expense), net | (40) | (15) | 87 | ||||||||||||||
Operating Income (Loss) | 241 | (1,100) | (716) | ||||||||||||||
| Interest expense and other finance charges | (359) | (325) | (363) | ||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | (184) | 196 | 172 | ||||||||||||||
| Reorganization income (expense), net | (812) | — | — | ||||||||||||||
| Consolidation of subsidiary gain (loss) | (170) | — | — | ||||||||||||||
| Deconsolidation of subsidiary gain (loss), net | — | — | 71 | ||||||||||||||
| Other non-operating income (expense), net | (44) | (48) | (9) | ||||||||||||||
Income (Loss) Before Income Taxes | (1,328) | (1,277) | (845) | ||||||||||||||
| Income tax benefit (expense) | 35 | 300 | 181 | ||||||||||||||
Net Income (Loss) | (1,293) | (977) | (664) | ||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | (4) | — | — | ||||||||||||||
Net Income (Loss) Attributable to Member | $ | (1,289) | $ | (977) | $ | (664) | |||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-62
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED DECEMBER 31
(Millions of Dollars)
| 2022 | 2021 | 2020 | |||||||||||||||
Net Income (Loss) | $ | (1,293) | $ | (977) | $ | (664) | |||||||||||
| Other Comprehensive Income (Loss) | |||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | (69) | (13) | 39 | ||||||||||||||
| Postretirement benefit actuarial gain (loss), net | (15) | 151 | (48) | ||||||||||||||
| Income tax benefit (expense) | 31 | (35) | (4) | ||||||||||||||
| Gains (losses) arising during the period, net of tax | (53) | 103 | (13) | ||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net | 33 | 2 | (36) | ||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | (2) | (2) | (12) | ||||||||||||||
| Postretirement benefit prior service (credits) costs, net | 1 | 1 | (1) | ||||||||||||||
| Postretirement benefit actuarial (gain) loss, net | 27 | 52 | 38 | ||||||||||||||
| Income tax (benefit) expense | (21) | (14) | 9 | ||||||||||||||
| Reclassifications from AOCI, net of tax | 38 | 39 | (2) | ||||||||||||||
Total Other Comprehensive Income (Loss) | (15) | 142 | (15) | ||||||||||||||
Comprehensive Income (Loss) | (1,308) | (835) | (679) | ||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | (4) | — | — | ||||||||||||||
Comprehensive Income (Loss) Attributable to Member | $ | (1,304) | $ | (835) | $ | (679) | |||||||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-63
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
CONSOLIDATED BALANCE SHEETS AT DECEMBER 31
(Millions of Dollars)
| 2022 | 2021 | ||||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | 724 | $ | 276 | |||||||
| Restricted cash and cash equivalents | 264 | 467 | |||||||||
| Accounts receivable, net | 408 | 115 | |||||||||
| Inventory, net | 457 | 403 | |||||||||
| Derivative instruments | 2,165 | 1,338 | |||||||||
| Other current assets | 247 | 200 | |||||||||
Total current assets | 4,265 | 2,799 | |||||||||
| Property, plant and equipment, net | 4,705 | 4,735 | |||||||||
| Nuclear decommissioning trust funds | 1,400 | 1,635 | |||||||||
| Derivative instruments | 228 | 645 | |||||||||
| Other noncurrent assets | 124 | 239 | |||||||||
Total Assets | $ | 10,722 | $ | 10,053 | |||||||
| Liabilities and Equity | |||||||||||
| Revolving credit facilities | $ | 848 | $ | 848 | |||||||
| Long-term debt, due within one year | 1,010 | 159 | |||||||||
| Inventory repurchase obligations | — | 165 | |||||||||
| Deferred capacity obligations | — | 174 | |||||||||
| Accrued interest | 278 | 67 | |||||||||
| Accounts payable and other accrued liabilities | 454 | 280 | |||||||||
| Derivative instruments | 1,927 | 1,742 | |||||||||
| Other current liabilities | 346 | 71 | |||||||||
Total current liabilities | 4,863 | 3,506 | |||||||||
| Long-term debt | 2,494 | 3,735 | |||||||||
| Liabilities subject to compromise | 2,825 | — | |||||||||
| Derivative instruments | 363 | 719 | |||||||||
| Postretirement benefit obligations | — | 315 | |||||||||
| Asset retirement obligations and accrued environmental costs | 567 | 767 | |||||||||
| Deferred income taxes | 75 | 216 | |||||||||
| Other noncurrent liabilities | 17 | 62 | |||||||||
Total Liabilities | 11,204 | 9,320 | |||||||||
| Commitments and Contingencies - Note 16 | |||||||||||
| Equity | |||||||||||
| Member’s Equity | (573) | 733 | |||||||||
| Noncontrolling interests | 91 | — | |||||||||
Total Equity | (482) | 733 | |||||||||
Total Liabilities and Equity | $ | 10,722 | $ | 10,053 | |||||||
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-64
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
CONSOLIDATED STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED DECEMBER 31
(Millions of Dollars)
| 2022 | 2021 | 2020 | |||||||||||||||
| Operating Activities | |||||||||||||||||
| Net income (loss) | $ | (1,293) | $ | (977) | $ | (664) | |||||||||||
| Reconciliation adjustments: | |||||||||||||||||
| Impairments | — | — | 681 | ||||||||||||||
| (Gain) on sale of IEC | — | — | (144) | ||||||||||||||
| (Gain) loss on consolidation of Cumulus Digital Holdings and deconsolidation of NGG | 170 | — | (71) | ||||||||||||||
| Unrealized (gains) losses on derivative instruments | (647) | 684 | 69 | ||||||||||||||
| Nuclear fuel amortization | 94 | 96 | 103 | ||||||||||||||
| Depreciation, amortization and accretion | 549 | 555 | 469 | ||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) | 227 | (158) | (138) | ||||||||||||||
| Deferred income taxes | (48) | (324) | (203) | ||||||||||||||
| Organizational restructuring | 488 | — | — | ||||||||||||||
| Non-cash reorganization (income) expenses, net | 99 | — | — | ||||||||||||||
| Other | 200 | (150) | 94 | ||||||||||||||
| Change in assets and liabilities: | |||||||||||||||||
| Accounts receivable, net | (298) | 24 | (30) | ||||||||||||||
| Inventory, net | (55) | 72 | 27 | ||||||||||||||
| Other assets | (46) | (138) | (18) | ||||||||||||||
| Accounts payable and accrued liabilities | 187 | 24 | 9 | ||||||||||||||
| Accrued interest | 250 | 3 | — | ||||||||||||||
| Other liabilities | 310 | (5) | (82) | ||||||||||||||
Net cash provided by (used in) operating activities | 187 | (294) | 102 | ||||||||||||||
| Investing Activities | |||||||||||||||||
| Property, plant and equipment expenditures | (232) | (142) | (106) | ||||||||||||||
| Nuclear fuel expenditures | (80) | (82) | (55) | ||||||||||||||
| Proceeds from the sale of IEC | — | — | 153 | ||||||||||||||
| Nuclear decommissioning trust funds investment purchases | (2,271) | (1,834) | (2,587) | ||||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds | 2,243 | 1,817 | 2,574 | ||||||||||||||
| Investments in equity of affiliates and equity method investments | (162) | (65) | — | ||||||||||||||
| Increase (decrease) in cash and restricted cash due to consolidation of subsidiaries | 123 | — | — | ||||||||||||||
| Other investing activities | 11 | 26 | 32 | ||||||||||||||
Net cash provided by (used in) investing activities | (368) | (280) | 11 | ||||||||||||||
| Financing Activities | |||||||||||||||||
| Talen Energy Supply long-term debt issuance proceeds | 987 | 131 | 400 | ||||||||||||||
| Talen Energy Supply long-term debt repayments | — | (114) | (206) | ||||||||||||||
| Prepetition Deferred Capacity Obligations issuance proceeds | — | 370 | — | ||||||||||||||
| Prepetition Deferred Capacity Obligations repayments | (176) | (209) | — | ||||||||||||||
| Prepetition Inventory Repurchase Obligations, net increase (decrease) | (165) | — | 15 | ||||||||||||||
| Prepetition RCF, net increase (decrease) | — | — | (105) | ||||||||||||||
| Prepetition CAF proceeds | 62 | 827 | — | ||||||||||||||
| Prepetition CAF repayments | (62) | — | — | ||||||||||||||
| LMBE-MC TLB repayments | (52) | (27) | (33) | ||||||||||||||
| Derivatives with financing elements | (104) | — | — | ||||||||||||||
| Deferred finance costs | (59) | (23) | (9) | ||||||||||||||
| Other | (5) | 1 | 3 | ||||||||||||||
Net cash provided by (used in) financing activities | 426 | 956 | 65 | ||||||||||||||
Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents | 245 | 382 | 178 | ||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | 743 | 361 | 183 | ||||||||||||||
| End of period cash and cash equivalents and restricted cash and cash equivalents | $ | 988 | $ | 743 | $ | 361 | |||||||||||
See Note 23 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-65
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
CONSOLIDATED STATEMENTS OF EQUITY
(Millions of Dollars)
| Member’s Equity | Noncontrolling Interest | Total Equity | |||||||||||||||
December 31, 2019 | $ | 2,236 | $ | — | $ | 2,236 | |||||||||||
| Net income (loss) | (664) | — | (664) | ||||||||||||||
| Other comprehensive income (loss) | (15) | — | (15) | ||||||||||||||
December 31, 2020 | $ | 1,557 | $ | — | $ | 1,557 | |||||||||||
| Net income (loss) | (977) | — | (977) | ||||||||||||||
| Other comprehensive income (loss) | 142 | — | 142 | ||||||||||||||
Non-cash contribution from member (a) | 11 | — | 11 | ||||||||||||||
December 31, 2021 | $ | 733 | $ | — | $ | 733 | |||||||||||
| Net income (loss) | $ | (1,289) | $ | (4) | $ | (1,293) | |||||||||||
| Other comprehensive income (loss) | (15) | — | (15) | ||||||||||||||
Non-cash consolidation of affiliate subsidiary (b) | — | 71 | 71 | ||||||||||||||
| Cash contribution | — | 7 | 7 | ||||||||||||||
Non-cash contributions from member (c) | — | 17 | 17 | ||||||||||||||
Non-cash distribution to member (d) | (2) | — | (2) | ||||||||||||||
December 31, 2022 | $ | (573) | $ | 91 | $ | (482) | |||||||||||
__________________
(a)An adjustment to Talen’s preferred equity investments in the Cumulus Affiliates based on the “Hypothetical Liquidation Book Value” method.
(b)In September 2022, TES consolidated Cumulus Digital Holdings. See Note 12 in Notes to the Annual Financial Statements for additional information.
(c)Primarily relates to contributions of cryptocurrency mining machines by TeraWulf to Nautilus. See Note 12 in Notes to the Annual Financial Statements for additional information.
(d)Primarily relates to a tax indemnity agreement. See Note 12 in Notes to the Annual Financial Statements for additional information.
The accompanying Notes to the Annual Financial Statements are an integral part of the financial statements.
F-66
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
TALEN ENERGY SUPPLY, LLC AND SUBSIDIARIES
DEBTORS-IN-POSSESSION
NOTES TO THE ANNUAL FINANCIAL STATEMENTS
Capitalized terms and abbreviations appearing in the Notes to the Annual Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted. The terms “Talen,” “Talen Energy Supply,” the “Company,” “we,” “us” and “our” refer to Talen Energy Supply, LLC and its consolidated subsidiaries, unless the context clearly indicates otherwise. This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to Talen Energy Supply insofar as such subsidiary’s financial information is included in Talen Energy Supply’s consolidated financial information. Talen Energy Supply 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 high-quality 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 the 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 nature of our wholly-owned coal fleet through the conversion to lower-carbon fuels. In addition, we are developing a hyperscale data center campus adjacent to Susquehanna 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, 2022, our generation capacity was 12,436 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 financial statements are prepared in accordance with GAAP and include the accounts of all controlled subsidiaries. Intercompany transactions are eliminated in consolidation.
Any undivided interests in jointly owned facilities are consolidated on a proportionate basis. See Note 14 for additional information.
Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for VIEs. Talen consolidates a VIE when it is determined that it has a controlling interest in the VIE, and Talen is the primary beneficiary of the entity. See “Variable Interest Entities” below for additional information.
As described further below, prior to September 2021, Cumulus Data and Cumulus Coin were consolidated by Talen Energy Supply; between September 2021 and September 2022, Cumulus Data and Cumulus Coin were accounted for as non-consolidated equity method investments by Talen Energy Supply, and since September 2022, both Cumulus Data and Cumulus Coin have been consolidated by Talen Energy Supply.
In September 2022, Talen Energy Supply and its Talen Growth subsidiary exchanged their preferred units in Cumulus Coin Holdings and Cumulus Data Holdings for common units in Cumulus Digital Holdings. Following the consummation of the exchange and other related transactions contemplated by the Cumulus Term Sheet, Talen Energy Supply 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 was consolidated by Talen Energy Supply as of September 30, 2022. See Note 12 for additional information.
F-67
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
In September 2021, Talen Energy Supply deconsolidated Cumulus Coin Holdings and sold its common equity ownership interest in Cumulus Data to an affiliate. See Note 12 for additional information.
As of June 30, 2021, Talen Energy Supply, under the terms of the agreement then-governing the convertible preferred equity interests of Cumulus Coin Holdings, held a controlling financial interest in Cumulus Coin Holdings. Accordingly, Cumulus Coin Holdings was consolidated in Talen Energy Supply’s financial statements as of June 30, 2021. In September 2021, the terms of these convertible preferred equity interests were amended in connection with the consummation of the Cumulus Digital TLF and Talen Energy Supply deconsolidated Cumulus Coin Holdings. See Note 12 for additional information.
In April 2020, Talen deconsolidated NorthEast Gas Gen and recognized an immaterial investment in NorthEast Gas Gen. Therefore, beginning in April 2020, the carrying value of NorthEast Gas Gen’s assets and liabilities and its operating results were no longer consolidated in Talen’s financial statements. See Note 19 for additional information.
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. Entities for which a controlling financial interest is not demonstrated through voting interests are evaluated based on accounting guidance for VIEs. Talen consolidates a VIE when it is determined that it has a controlling interest in the VIE, and Talen is the primary beneficiary of the entity. See Notes 11 and 12 for additional information on our equity method and preferred equity investments.
Going Concern and Restructuring. These financial statements have been prepared on a going concern basis, which contemplates the realization of assets and settlement of liabilities in the ordinary course of business. As of the Emergence Date, we removed the substantial doubt about Talen’s ability to continue as a going concern. See Note 3 for additional information on the Restructuring.
Summary of Significant Accounting Policies
Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity or cash flows.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Restructuring Effects. In May 2022, as a result of the Restructuring, the Company adopted the authoritative accounting guidance in ASC 852-10 - Reorganizations. ASC 852-10 provides for changes in the accounting and presentation of significant items on the balance sheet, particularly pre-petition liabilities. Due to the adoption of ASC 852-10, the Company included two new financial statement line items: “Liabilities subject to compromise” on the Consolidated Balance Sheet and “Reorganization income (expense), net” on the Consolidated Income Statement. Prepetition liabilities and obligations whose treatment and satisfaction are dependent on the outcome of the Restructuring are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet. The carrying value of prepetition liabilities that are 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 Sheet may be subject to future adjustments depending on Bankruptcy Court actions, further 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, with respect to a Debtor, the date on which such Debtor commenced the Restructuring, either May 9, 2022 or May 10, 2022 (the “Petition Date”), are presented as “Reorganization income (expense), net” on the Consolidated Statement of Operations.
F-68
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
As of the Petition Date, the Debtors ceased recognizing interest expense on certain outstanding unsecured or under-secured prepetition indebtedness. Contractual interest expense represents amounts due under the terms of outstanding prepetition indebtedness. See Note 18 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.
See Notes 4, 14, 20 and 21 for fair value disclosures.
Concentrations of Credit Risk. Talen is subject to concentrations of credit risk primarily within its 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 4 for additional information on concentrations of credit risk.
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 16 for additional information.
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 power generation facilities owned by Talen 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 ISOs and RTOs for electric generation and for ancillary services provided such as regulation and reserve services and other products that support transmission and grid operations; (ii) amounts earned for wholesale electricity sales to bilateral counterparties; (iii) amounts earned for retail electricity sales to commercial and industrial retail customers; and (iv) realized gains and losses on commodity derivative instruments.
F-69
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Sales of 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. Electric generation sales are presented net of energy purchases from RTOs and ISOs on an hourly basis. Where the effect of such netting results in a net purchase, the net hourly amounts are presented as “Fuel and energy purchases” on the Consolidated Statements of Operations.
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.
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.
Sales of retail electricity to commercial and industrial retail customers under executory bilateral contracts represent performance obligations recognized over a contractually agreed period of time based on volumes delivered to the customer at the contractually agreed price. Accrued and unbilled revenue of retail electricity to commercial and industrial customers is based on contractually agreed prices and the estimated volumes of customer usage since the last meter reading date provided by ISOs, RTOs, or electric distribution companies. The estimated revenues are adjusted when actual usage is known and billed to customers in the month following service delivery or the provision for service. Payments for customer invoices are generally due within a short time period based on the contractually agreed due date of the underlying agreements. As part of the Restructuring, Talen filed an order to reject its retail contracts and will have no further obligations under these retail contracts upon Emergence. See Note 3 for additional information.
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 settlements of financial and physical transactions for hedging and portfolio optimization related to electricity contracts that stabilize the financial performance of Talen’s generation facilities. Realized settlements of financial and physical commodity 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 the changes in fair value of certain contracts related to electricity contracts that qualify as derivative instruments. See “Derivative Instruments” below for the recognition criteria of unrealized gains and losses on commodity derivative instruments. See “Energy Expenses” below for additional information on unrealized gains and losses of derivative instruments presented as “Energy expenses” on the Consolidated Statements of Operations.
See Note 5 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 purchase contracts.
Fuel and energy purchases. Primarily includes: (i) fuel costs; (ii) environmental product costs; (iii) energy purchases; (iv) gross receipts taxes; and (v) realized gain (loss) on commodity derivative instruments.
Fuel costs include the costs incurred by Talen-owned generation facilities for the conversion of coal, natural gas, and (or) oil products to electricity. Fuel for electric generation from coal and oil product inventories are recognized at the applicable weighted average inventory cost of volumes consumed. Fuel for electric generation
F-70
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
Environmental product costs include RGGIs, RECs, and 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.
Energy purchases include costs incurred for purchases of electricity from ISOs, RTOs and bilateral counterparties, which are used to fulfill wholesale physical contract requirements and commercial and industrial retail power sales requirements when such requirements are in excess of volumes generated by Talen-owned generation facilities. Physical electricity purchases are recognized upon delivery at contractually agreed day-ahead market prices, real-time market prices or bilateral contract prices. Energy purchases from ISOs and RTOs are presented net of electric generation sales on an hourly basis. Where the effect of such netting results in a net purchase, the net hourly amounts are presented as “Fuel and energy purchases” on the Consolidated Statements of Operations.
Gross receipt taxes include taxes levied on retail electricity sales to commercial and industrial customers, where applicable.
Realized gains and losses on commodity derivative instruments include settlements of financial and physical transactions for hedging and portfolio optimization related to fuel contracts and environmental product contracts that stabilize the financial performance of Talen’s generation facilities. Realized settlements of financial and physical commodity derivative instruments are recognized and presented net 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” 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 the changes in 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 values of derivative instruments are presented as “Derivative instruments” within assets or liabilities on the Consolidated Balance Sheets. In most instances, master netting agreements govern derivative transactions between parties and contain certain provisions for setoff rights. However, the fair value of derivative instruments is presented on the Consolidated Balance Sheets gross of setoff rights and gross of any collateral deposits exchanged between parties that may be required when certain credit limits are exceeded.
The classification for the income effect of a derivative instrument, which is due to changes in such instrument’s fair value over the term of the underlying contract, depends on the intent for holding the instrument.
Unrealized gains or losses, net of income tax, associated with a derivative instrument that: (i) is intended to hedge the cash flows of a separate transaction; and (ii) qualifies for specialized cash flow hedge accounting are presented as “Other Comprehensive Income (Loss)” on the Consolidated Statement of Comprehensive Income in the period when such gains or losses arise. The fair value of a derivative instrument is presented on the Consolidated Balance Sheets as AOCI. Such amounts are transferred from AOCI to the same financial statement line on the Consolidated Statements of Operations that is used to present the earnings effect of the separate hedged transaction in the same period when the income effect of the separate hedged transaction arises. At December 31, 2022 and 2021, there are no derivatives with hedge accounting designations.
F-71
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
If a hedging relationship between a derivative instrument and the separate hedged transaction that previously qualified for cash flow hedge accounting is discontinued and the separate hedged transaction is still probable of occurring, amounts previously recognized in AOCI are reclassified to the same financial statement line on the Consolidated Statements of Operations that is used to present the earnings effect of the separate hedged transaction in the same period when the income effect of the separate hedged transaction arises. From the date the hedging relationship is discontinued, any subsequent changes in the fair value of the derivative are recognized in the Consolidated Statements of Operations. See Note 4 for additional information on discontinued cash flow hedges.
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. Changes in 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 within “Interest expense and other finance charges” on the Consolidated Statements of Operations.
See Notes 4 and 20 for additional information on the presentation of derivative contracts and fair value measurements.
Operation, maintenance and development. The costs of removal, repairs, maintenance and other operating costs, including salaries and benefits for operations personnel that 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. Such expenses are presented as “Operation, maintenance and development” on the Consolidated Statements of Operations.
Operation, maintenance and development also includes “development” expenses that are related to a pipeline of renewable energy and battery storage projects, developing a hyperscale data center campus and our Nautilus joint venture during their pre-commercial operation stage.
Income Taxes. Talen Energy Corporation and its subsidiaries file a consolidated U.S. federal income tax return, which includes Talen Energy Supply. The provision for income taxes is calculated as if Talen Energy Supply and its subsidiaries file a separate consolidated 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.
Sales taxes that are collected from retail customers are presented as “Accounts receivable” and “Accounts payable and other accrued liabilities” on the Consolidated Balance Sheets. Accordingly, sales taxes are not presented on the Consolidated Statements of Operations.
See Note 6 for additional information on income taxes.
F-72
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Earnings Per Unit. Earnings per unit has not been presented because the Company’s members hold interests and not units.
Cash and Cash Equivalents. Bank deposits, liquid investments, and other similar assets with original maturities of three months or less.
Restricted Cash and Cash Equivalents. 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 23 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. See Note 7 for additional information on allowance for doubtful accounts.
Inventory. Inventory consists of fuel for generation (primarily coal and fuel oil), materials and supplies, and environmental products all of which are valued at the lower of weighted average cost or net realizable value. See Note 9 for additional information on inventory.
Leases. Talen’s operating leases are primarily related to offices, land, and generation facility equipment. Several of these lease agreements contain extension options allowing Talen, at its discretion, to renew the lease term for additional periods. The decision to include these renewal periods in the lease term and in the minimum lease payments in the calculation of lease liabilities is dependent on whether it is reasonably certain that the extension option will be exercised. 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 each class of leased assets. Additionally, 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.
Right-of-use assets are presented as “Other current assets” and “Other noncurrent assets” on the Consolidated Balance Sheets and represent the right to use an underlying asset for the lease term, while lease liabilities are presented as “Other current liabilities” and “Other noncurrent liabilities” on the Consolidated Balance Sheets and represent the payment obligations related to these assets over the lease term. Right-of-use assets and lease liabilities are recognized on commencement of the lease based on the present value of lease payments over the lease term. The discount rate for a lease is the rate implicit in the lease unless that rate cannot be readily determined. In such a case, the discount rate utilized is Talen’s incremental secured borrowing rate over a similar time period and economic environment as the lease, based on information available at the lease commencement date. See Note 10 for additional information on leases.
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.
In the third quarter 2022, Talen Energy Supply became the primary beneficiary of Cumulus Digital Holdings and its subsidiaries. These entities were consolidated by Talen Energy Supply.
F-73
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
During 2021, Talen held interests in two material VIEs, Cumulus Coin Holdings and Cumulus Data Holdings, but was not the primary beneficiary of the VIEs. Our interests in entities that are considered VIEs for which Talen is not the primary beneficiary are accounted for under the equity method.
During 2021 and 2022, Talen Energy Supply utilized the hypothetical liquidation at book value method to recognize earnings associated with its investments in Cumulus Coin Holdings and Cumulus Data Holdings. Under the hypothetical liquidation at book value method, the amounts of income and loss attributable to the preferred equity investments held by Talen Energy Supply and its subsidiaries were computed as the amount the members would hypothetically receive at each balance sheet date under the respective liquidation provisions in the applicable limited liability company agreement. Such computation assumed the underlying net assets of these entities were liquidated at their carrying values after taking into account any capital transactions, such as contributions and distributions, between the entities and the members. As the members are under common control, any income allocated to the preferred equity investments under the hypothetical liquidation at book value method that recovers a basis difference between the book value of capital contribution. The liquidation preference value on such contributions is considered a reallocation of equity between the members under common control.
See Notes 11 and 12 for additional information on Talen Energy Supply equity and equity-method investments.
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 13 and 20 for additional information on investments in debt and equity securities.
Property, Plant and Equipment. Expenditures for land, the construction of generation, data center or Bitcoin 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. Generation, data center or Bitcoin 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 within “Other operating income (expense), net” on the Consolidated Statements of Operations.
Expenditures for intangible assets such as contractual rights, software and licenses are capitalized at cost. Intangible assets acquired in a business combination are recognized at fair value. In each case, such amounts are presented as “Property, plant and equipment” on the Consolidated Balance Sheets. Reductions in the carrying value
F-74
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
of intangible assets with finite useful lives are accumulated over the estimated useful life of each intangible asset using an amortization pattern in which the economic benefits of each intangible asset is utilized. Such periodic reduction is presented as a charge to “Depreciation, amortization and accretion” on the Consolidated Statements of Operations. The carrying value of intangible assets with indefinite useful lives is not material.
See “Impairments” below for additional information regarding impairments on the carrying values of property, plant and equipment.
See Note 14 for additional information on property, plant and equipment.
Generation Facility Useful Life Revisions.
Effective December 31, 2022, the estimated useful life of Montour’s coal-fired power generation related PP&E was amended from May 2025 to December 2023. The change in the estimated useful life will increase Montour’s depreciation expense by approximately $49 million for the period from January 2023 through December 2023. Previously, effective September 30, 2020, Montour’s estimated useful life was changed from 2035 to 2025. After adjusting for the impact of Montour’s non-cash impairment charge, the change in the estimated useful life will increase Montour’s depreciation expense by approximately $53 million annually through 2024 and $22 million in 2025. See Note 14 for additional information on Montour’s impairment.
Effective December 31, 2022, the estimated useful life of Camden was amended from June 2029 to June 2040. The change in the estimated useful life has an immaterial effect on the depreciation expense of the generation facility.
Effective September 1, 2021, the estimated useful lives of certain peaking units were respectively amended from June 2030 to April 2022 or June 2022 due to revisions in deactivation dates. The change in the estimated useful lives for the generation facilities increased aggregate depreciation expense by approximately $11 million for the period from September 2021 through June 2022.
Effective June 1, 2021, the estimated useful lives of Newark Bay and Pedricktown were respectively amended from June 2033 and June 2032 to May 2022 due to revisions in deactivation dates. The change in the estimated useful lives for the generation facilities increased aggregate depreciation expense by approximately $38 million for the period from June 2021 through May 2022.
As each of these changes is a change in estimate, the changes are accounted for prospectively. Additionally, actual depreciation expense for each useful life revision may vary from estimates based on a number of factors which include, but are not limited to, additions or retirements of property, plant and equipment carrying values subsequent to the effective date of each revision.
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 as a charge to “Operation and maintenance” 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
F-75
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 14 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.
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 15 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 16 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
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 “Debt restructuring gain (loss), net” 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.
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.
Talen uses an accelerated amortization method for the recognition of gains and losses for defined benefit pension plans. Under the accelerated method, 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. 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.
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 allowable 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 21 for additional information about the plans and the accounting for defined benefits.
New Accounting Standards
Postretirement Benefits (Adopted). On January 1, 2021, Talen adopted the guidance in ASU 2018-14, which amends disclosure requirements around defined benefit plans. The adoption of this guidance did not have a material effect on Talen.
Reference Rate Reform (Pending). In March 2020, the FASB issued ASU 2020-04, which provides optional expedients and exceptions for applying GAAP to contract modifications and hedging relationships, subject to meeting certain criteria, that reference LIBOR or another rate that is expected to be discontinued. The optional expedients are available to be used upon issuance of this guidance and if elected, will permit entities to treat such modifications as the continuation of the original contract without any required accounting reassessments or
F-77
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
remeasurements. Talen has not modified contracts that qualify for the expedient described above, therefore, the guidance has not been applied. While a material impact as a result of the adoption of this standard is not expected, the assessment to determine the ultimate impact on the financial statements is ongoing.
3. Talen Restructuring
Voluntary Reorganization Under Chapter 11 of the Bankruptcy Code
In May 2022, Talen Energy Supply and the other initial Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. In December 2022, Talen Energy Corporation 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.
Subject to certain exceptions, under the Bankruptcy Code, the commencement of the Restructuring automatically enjoined, or stayed, the continuation of most judicial or administrative proceedings or filings of other actions against the Debtors or their property to recover, collect, or secure a claim arising prior to the commencement of the Restructuring, including under the Debtors’ prepetition funded debt obligations.
From the commencement and through consummation of the Restructuring, the Debtors continued to operate their business as debtors-in-possession under the jurisdiction of and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court.
The Bankruptcy Court approved, on a final basis, the first-day motions filed by the Debtors that were designed primarily to mitigate the impact of the Restructuring on the Debtors’ operations and employees. The Debtors were authorized, under orders approving the first-day motions, to conduct their business activities in the ordinary course, and pursuant to orders entered by the Bankruptcy Court, are authorized to, among other things and subject to the terms and conditions of such orders: (i) pay employee wages and related obligations; (ii) pay certain taxes; (iii) pay amounts owed to certain critical vendors for work performed prior to the commencement of the Restructuring; (iv) continue Talen’s hedging program under both prepetition agreements and new postpetition agreements; (v) maintain their insurance programs; and (vi) continue their cash management system (including funding of certain transactions with the Cumulus Affiliates and LMBE-MC).
Under the Bankruptcy Code, the Debtors were permitted to assume, assign, or reject certain contracts, subject to the approval of the Bankruptcy Court and to certain other conditions. Other parties to the rejected contracts were permitted to assert claims in the Bankruptcy Court against the Debtors for damages related to these rejections. See “—Liabilities Subject to Compromise and Claims” for additional information.
Talen Restructuring Support Agreement
Prior to the commencement of the Restructuring, the Debtors entered into the RSA with certain holders of Talen Energy Supply’s unsecured notes (the “Consenting Noteholders”) and agreed to support the transactions set forth in the restructuring term sheet attached as an exhibit to the RSA, as may be amended, supplemented, or otherwise modified from time to time (the “RSA Term Sheet”). The RSA Term Sheet provided for an up to $1.9 billion common equity rights offering that, when combined with Talen’s projected available cash at the time of consummation, would provide for the payment of claims under the DIP Facilities, the Prepetition CAF, the Prepetition TLB, the Prepetition Secured Notes and the Prepetition Secured ISDAs. Certain of the Consenting Noteholders have agreed to backstop up to $1.55 billion of the Rights Offering, as further described below.
The RSA included, among other things, certain consent rights for the Consenting Noteholders, certain commitments of the Consenting Noteholders and the other parties to the RSA to support the Restructuring, termination rights for both the Consenting Noteholders and the Debtors, and customary milestone dates by which certain events in the Restructuring must have occurred by.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
In August 2022 and December 2022, the Debtors and the Consenting Noteholders executed amendments to the RSA incorporating the settlement of all claims, interests and controversies among the Debtors, the Consenting Noteholders, the holders of claims under the Prepetition CAF and the holders of claims under the Prepetition TLB and Prepetition Secured Notes, and the TEC Global Settlement. As a result of these settlements, the holders of claims under the Prepetition CAF, holders of claims under the Prepetition TLB and Prepetition Secured Notes, TEC and Riverstone settled outstanding issues, and agreed to join the parties to the RSA and to support the Plan of Reorganization. Each of these settlements was incorporated into the Plan of Reorganization.
Additionally, in connection with the TEC Global Settlement, TES, TEC, certain of the Cumulus Affiliates, Riverstone and Orion entered into the Cumulus Term Sheet, which, among other things, provided for additional funding for Cumulus Data and Cumulus Coin, conversion of Talen’s preferred equity in Cumulus Data Holdings and Cumulus Coin Holdings into common equity of Cumulus Digital Holdings, and increased governance and consent rights for TES with respect to Cumulus Digital Holdings and its subsidiaries. See Note 12 for additional information on the Cumulus Term Sheet.
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. In the third quarter 2022, the Debtors recognized a $310 million charge associated with the Backstop Commitment Letter and (or) its possible termination presented as “Reorganization income (loss), net” on the Consolidated Statement of Operations. Pursuant to the Rights Offering, Talen Energy Corporation 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 Talen Energy Corporation 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% 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.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
◦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.
•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; 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. To the extent any proceeds are recovered by the Debtors pursuant to the PPL/Talen Montana litigation, 10% of the net proceeds recovered will be contributed to the pool of cash, subject to a cap of $11 million. See Note 16 for information on the PPL/Talen Montana litigation.
Payments Due on Certain Indebtedness
The Restructuring resulted in immediate acceleration of the Prepetition Indebtedness (other than the PEDFA 2009B and 2009C Bonds). As a result, the principal amount of such indebtedness, together with accrued interest, immediately became due and payable. However, any efforts to enforce these payment obligations were automatically stayed as of the Petition Date and are subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. See Notes 17 and 18 for details on revolving credit facilities and long-term debt.
The filing of the Restructuring also provided the counterparties under certain commodity and derivative related agreements with the right to declare an event of default and to terminate and accelerate amounts owed under such agreements, subject to the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court. In June 2022, the Bankruptcy Court entered a final order with respect to the DIP Facilities, which, among other things, permits, or in certain circumstances, requires, the Debtors to pay interest on the prepetition secured debt, subject to, among other terms and conditions, minimum liquidity requirements.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
DIP Facilities
In May 2022, the Debtors entered into a superpriority secured DIP credit agreement and entered into several new or amended ISDAs with certain hedge counterparties to allow the Debtors to enter into postpetition hedging transactions. These agreements provided Talen with sufficient liquidity to recommence its hedging activities, which had been constrained prior to the filing of the Restructuring. See Note 17 for additional information on the DIP Facilities and DIP Secured ISDAs.
Liabilities Subject to Compromise and Claims
Under the Bankruptcy Code, the Debtors may assume, assign, or reject certain contracts, subject to the approval of the Bankruptcy Court and to certain other conditions. Other parties to the rejected contracts may assert claims in the Bankruptcy Court against the Debtors for damages related to these rejections.
At December 31, 2022, “Liabilities subject to compromise” on the Consolidated Balance Sheet presents the expected allowed amount of the prepetition claims of the Debtors that are not fully secured and that have at least a possibility of not being repaid at the full claim amount. Management will continue to evaluate the amount and classification of its prepetition liabilities until Talen’s Debtors emerge from the Restructuring. Any additional liabilities that were subject to compromise were recognized accordingly, and the aggregate amount of liabilities subject to compromise were subject to change up through the Emergence Date.
| December 31, 2022 | |||||
Debt (a) | $ | 1,558 | |||
| Termination of retail 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.
In the preceding table:
•“Debt” represents principal values of long-term unsecured debt;
•“Derivatives” represent the fair value of prepetition derivative instruments with counterparties that, as of the filing date, have not executed new or amended ISDAs or consent agreements committing to any postpetition hedging arrangements under the DIP Facilities;
•“Postretirement benefit obligations” and “Asset retirement obligations and accrued environmental costs” are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet as they represent unsecured liabilities. However. under the terms of the Plan of Reorganization, these liabilities will be assumed by Talen upon Emergence; other than a non-material amount associated with Talen’s legacy non-qualified supplemental pension plan;
•“Asset retirement obligations and accrued environmental costs” represent all the Debtors’ AROs except those related to Susquehanna Nuclear, which are secured by the NDT, and all the Debtors’ accrued environmental costs; and
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
•“Postretirement benefit obligations” represent all of the Debtors’ unfunded or underfunded postretirement obligations.
In May 2022, the Bankruptcy Court issued an order that allowed the Debtors to reject contracts for power supply related to the Talen Energy Marketing retail business. In the second quarter 2022, the Debtors recognized a charge of $447 million on the Consolidated Statement of Operations in “Operational restructuring” and as “Liabilities subject to compromise” on the Consolidated Balance Sheet relating to the rejected retail supply contracts. In addition, the Bankruptcy Court issued an order that allowed the Debtors to reject contracts for certain service agreements, contracts for the supply of gypsum, and a land lease. In the fourth quarter 2022, the Debtors recognized an associated charge of $41 million on the Consolidated Statement of Operations in “Operational restructuring” and as “Liabilities subject to compromise” on the Consolidated Balance Sheet. Both of these charges are management’s estimates of damages for allowed claims for the counterparties to the rejected contracts. Payment of these claims is subject to and limited by the final Plan of Reorganization.
Claims Processing
The Debtors have filed with the Bankruptcy Court schedules and statements setting forth, among other things, the assets and liabilities of the Debtors, on the basis of certain assumptions filed in connection therewith. The schedules and statements may be subject to further amendment or modification after filing.
As of February 28, 2023, the Debtors had received 37,430 proofs of claim, primarily representing general unsecured claims, for an aggregate amount of approximately $88.3 billion. These values represent total claims filed and may include duplicative amounts.
Differences in amounts presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet and claims filed by creditors are investigated and resolved, including through the filing of objections with the Bankruptcy Court, where appropriate.
Reorganization Income (Expense), net
Reorganization Income (Expense), net for the year ended December 31 consisted of:
| 2022 | |||||
| Backstop Premiums | $ | (310) | |||
| Professional fees | (210) | ||||
| Make-whole premiums and accrued interest on certain indebtedness | (183) | ||||
| Professional fees incurred to obtain the DIP Facilities | (70) | ||||
| Write-off of deferred financing cost and original issue discount | (30) | ||||
| Gains (Losses) on contract terminations | (4) | ||||
| Other | (5) | ||||
| Reorganization Income (Expense), net | $ | (812) | |||
In the preceding table:
•see “Settlements, Restructuring Support Agreement and Backstop Commitment Letter” above for information on the Backstop Premiums; and
•“Make-whole premiums and accrued interest on certain indebtedness” in the table above primarily represents charges recognized by the Debtor’s for estimates related to make-whole premiums and accrued interest, where applicable, on the Prepetition CAF and certain senior secured indebtedness. The charges are presented as “Reorganization income (expense), net” on the Consolidated Statement of Operations and included in “Accrued interest” on the Consolidated Balance Sheet.
F-82
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Cash paid for reorganization expense, net, excluding cash outlays for DIP financing fees, was $156 million for the year ended December 31, 2022. Cash outlays for the DIP financing fees are presented as “Financing Activities” on the Consolidated Statement of Cash Flows.
Condensed Combined Financial Information
This condensed combined financial information has been prepared on the same basis as Talen Energy Supply’s financial statements. Intercompany transactions between Debtors have been eliminated in the amounts presented below. The following table presents summarized condensed combined financial information of debtors of Talen Energy Supply as of and for the year ended December 31:
| 2022 | |||||
| Cash and cash equivalents | $ | 722 | |||
| Restricted cash and cash equivalents | 182 | ||||
| Accounts receivable, net | 415 | ||||
| Inventory, net | 445 | ||||
| Derivative instruments | 2,195 | ||||
| Other current assets | 228 | ||||
| Current assets | 4,187 | ||||
| Property, plant and equipment, net | 3,868 | ||||
| Nuclear decommissioning trust funds | 1,400 | ||||
| Derivative instruments | 228 | ||||
| Investments in affiliate subsidiaries | 322 | ||||
| Other noncurrent assets | 139 | ||||
Total Assets | $ | 10,144 | |||
| Revolving credit facilities | $ | 848 | |||
| Long-term debt, due within one year | 1,000 | ||||
| Accrued interest | 277 | ||||
| Accounts payable and other accrued liabilities | 422 | ||||
| Derivative instruments | 1,927 | ||||
| Other current liabilities | 322 | ||||
Total current liabilities | 4,796 | ||||
| Long-term debt | 2,022 | ||||
| Liabilities subject to compromise | 2,827 | ||||
| Derivative instruments | 363 | ||||
| Asset retirement obligations and accrued environmental costs | 564 | ||||
| Deferred income taxes | 75 | ||||
| Other noncurrent liabilities | 54 | ||||
Total Liabilities | 10,701 | ||||
Member’s Equity | (557) | ||||
Total Liabilities and Equity | $ | 10,144 | |||
“Accounts receivable, net” in the table above, includes $9 million due for transactions between the debtors and non-debtors including: (i) LMBE-MC Holdco and its subsidiaries; (ii) Talen Receivables Funding LLC; (iii) the Cumulus Affiliates; and (iv) Talen Energy Corporation. The transactions primarily include: (i) amounts due under certain energy management agreements, support services or support cost reimbursement agreements; (ii) amounts due related to TRF’s receivables sales agreement that was terminated in May 2022; and (iii) amounts due for TES’s
F-83
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
payment of certain expenses and liabilities incurred by Talen Energy Corporation. See Notes 12 and 24 for additional information on amounts due from Cumulus-related entities and Talen Energy Corporation.
“Derivative instruments,” in the table above within current assets, includes $38 million related to an ISDA between Debtor, Talen Energy Marketing, and non-Debtor, LMBE-MC Holdco, pursuant to which Talen Energy Marketing enters into commodity hedging transactions with respect to the sale of energy and capacity and the purchase of fuel by Talen Energy Marketing under energy management agreements with LMBE-MC Holdco’s subsidiaries.
| 2022 | |||||
| Capacity revenues | $ | 295 | |||
Energy revenues (a) | 1,708 | ||||
Unrealized gain (loss) on derivative instruments (a) | 697 | ||||
Operating Revenues | 2,700 | ||||
Energy Expenses | |||||
Fuel and energy purchases (a) | (688) | ||||
| Nuclear fuel amortization | (94) | ||||
Unrealized gain (loss) on derivative instruments (a) | (16) | ||||
Operating Expenses | |||||
| Operation and maintenance | (547) | ||||
General and administrative (b) | (115) | ||||
| Postretirement benefits service cost | (5) | ||||
| Depreciation, amortization and accretion | (483) | ||||
| Operational restructuring | (488) | ||||
| Other operating income (expense), net | (12) | ||||
| Operating Income (Loss) | 252 | ||||
| Interest expense and other finance charges | (349) | ||||
| Nuclear decommissioning trust funds gain (loss), net | (184) | ||||
| Consolidation of subsidiary gain (loss) | (170) | ||||
| Postretirement benefits gain (loss), net | (7) | ||||
| Debt restructuring gain (loss), net | (5) | ||||
| Reorganization income (expense), net | (812) | ||||
| Other non-operating income (expense), net | (36) | ||||
Income (Loss) Before Income Taxes | (1,311) | ||||
| Income tax benefit (expense) | 34 | ||||
Net Income (Loss) | (1,277) | ||||
| Less: Net income (loss) attributable to noncontrolling interest | (3) | ||||
Net Income (Loss) Attributable to Members | $ | (1,274) | |||
__________________
(a)Includes a non-material amount of revenue for the twelve months ended period, net related to transactions with non-debtor subsidiaries.
(b)See Note 12 for information on related party activity with Cumulus-related entities.
F-84
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Included in above, is a non-material amount of revenue, net related to an ISDA between debtor, Talen Energy Marketing, and non-debtor, LMBE-MC Holdco, pursuant to which Talen Energy Marketing enters into commodity hedging transactions with respect to the sale of energy and capacity and the purchase of fuel by Talen Energy Marketing under energy management agreements with LMBE-MC Holdco’s subsidiaries.
| 2022 | |||||
Cash provided by (used in) operating activities | $ | 118 | |||
Investing Activities | |||||
| Property, plant and equipment expenditures | (155) | ||||
| Nuclear fuel expenditures | (80) | ||||
| Nuclear decommissioning trust funds investment purchases | (2,271) | ||||
| Nuclear decommissioning trust funds investment sale proceeds | 2,243 | ||||
| Investments in preferred equity of affiliates and equity method investments | (157) | ||||
| Other investing activities | 11 | ||||
Net cash provided by (used in) investing activities | (409) | ||||
| Financing Activities | |||||
| Talen Energy Supply DIP long-term debt issuance proceeds, net | 987 | ||||
| Talen Deferred Capacity Obligation repayments | (176) | ||||
| Prepetition Inventory Repurchase Obligations, net increase (decrease) | (165) | ||||
| Prepetition CAF proceeds | 62 | ||||
| Prepetition CAF repayments | (62) | ||||
| Derivatives with financing elements | (104) | ||||
| Deferred finance costs | (59) | ||||
| Other | (5) | ||||
Net cash provided by (used in) financing activities | $ | 478 | |||
4. 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 to manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. The Company’s Risk Management Committee, comprised of certain senior management members across the Talen organization and one independent member, oversees the management of these risks in accordance with our risk policy.
Management has established procedures to monitor, measure, and manage hedge and optimization 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 analysis, 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 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.
F-85
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Within the parameters of our risk policy, we generally utilize conventional exchange-traded and over-the-counter traded derivative instruments, and in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives at December 31, 2022 range in maturity through 2025. The net notional volumes of open commodity derivatives were:
December 31, 2022 (a) | December 31, 2021 (a) | ||||||||||
| Power (MWh) | (34,810,559) | (33,993,941) | |||||||||
| Natural gas (MMBtu) | 57,621,580 | 43,867,702 | |||||||||
| Emission allowances (tons) | 5,000,000 | 4,700,000 | |||||||||
__________________
(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. Certain interest rate derivative instruments were required through December 2021 under the LMBE-MC Credit Agreement; others are entered into at the discretion of Talen.
Open interest rate derivatives at December 31, 2022 range in maturity dates through 2023. The net notional volumes of open interest rate derivatives were:
| December 31, 2022 | December 31, 2021 | ||||||||||
Interest rate (in millions) (a) | $ | 289 | $ | 842 | |||||||
__________________
(a)Value at December 31, 2022 relates to LMBE-MC 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 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 credit worthiness, 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 manage 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 these are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the future 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 Energy Marketing.
Outstanding accounts receivable include those from sales of capacity, generated electricity and ancillary services through contracts directly with ISOs and RTOs, sales of physical electricity to commercial and industrial retail customers 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 which are operated by the Company. The majority of outstanding receivables,
F-86
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
which are continually monitored, have customary payment terms. Allowances for doubtful accounts were $6 million at December 31, 2022 and $10 million at December 31, 2021. See “ERCOT 2021 Winter Market Conditions” below for additional information on the allowance for doubtful accounts recognized during the first quarter 2021.
Concentrations of Credit Risk. At December 31, 2022 Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, letters of credit and any allowances for doubtful collections, was $2,808 million and its credit exposure net of such effects was $201 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 85% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Credit Risk Contingent Features. 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, which contain credit risk-related contingent features, was $2 million at December 31, 2022 and was $13 million at December 31, 2021. There was $2 million in collateral posted on those positions at December 31, 2022 and December 31, 2021. The additional potential collateral requirements, which primarily related to further adequate assurance features, were not material at December 31, 2022 and $1 million at December 31, 2021.
Effect of Netting. Generally, the right of set off 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 as Consolidated Balance Sheets without the effect of such permitted netting.
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 | Net Amounts | ||||||||||||||||||||||||||||||
| December 31, 2022 | |||||||||||||||||||||||||||||||||||
| Assets | $ | 2,393 | $ | (2,194) | $ | — | $ | 199 | $ | — | $ | 199 | |||||||||||||||||||||||
Liabilities (a) | 2,291 | (2,194) | 1 | 96 | (75) | 21 | |||||||||||||||||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||||||||||||||
| Assets | $ | 1,983 | $ | (1,957) | $ | — | $ | 26 | $ | — | $ | 26 | |||||||||||||||||||||||
| Liabilities | 2,461 | (1,957) | — | 504 | (312) | 192 | |||||||||||||||||||||||||||||
__________________
(a)Includes amounts that are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheets. See Note 3 for additional information.
Discontinued Cash Flow Hedges
The pre-tax gain (loss) of discontinued cash flow hedges, which were discontinued prior to the formation of Talen in 2015, reclassified from AOCI into the Consolidated Statements of Operations for the years ended December 31 were:
| Location of Gain (Loss) | 2022 | 2021 | 2020 | |||||||||||||||||
| Depreciation, amortization and accretion | $ | 2 | $ | 2 | $ | 3 | ||||||||||||||
| Impairments | — | — | 9 | |||||||||||||||||
| Total | $ | 2 | $ | 2 | $ | 12 | ||||||||||||||
In September 2020, a non-cash impairment charge on Montour’s property, plant, and equipment carrying values resulted in the accelerated amortization of $9 million in non-cash gains on discontinued cash flow hedges that were
F-87
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
previously presented as AOCI. Such amount is presented as “Impairments” on the Consolidated Statement of Operations for the year ended December 31, 2020.
At December 31, 2022 and 2021, the carrying value, net of tax, of qualifying derivatives held within AOCI was $9 million and $11 million. During the next 12 months, $2 million is expected to be reclassified into earnings with the remained expected to be reclassified through 2028.
In 2022, 2021, and 2020 there were no derivatives actively designated as cash flow hedges.
Derivative Instrument Presentation
The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
December 31, 2022 (a) | December 31, 2021 | ||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | ||||||||||||||||||||
| Commodity contracts | $ | 2,156 | $ | 1,928 | $ | 1,338 | $ | 1,731 | |||||||||||||||
| Interest rate contracts | 9 | — | — | 11 | |||||||||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | 1 | — | — | |||||||||||||||||||
| Total current derivative instruments | $ | 2,165 | $ | 1,927 | $ | 1,338 | $ | 1,742 | |||||||||||||||
| Commodity contracts | $ | 228 | $ | 363 | $ | 645 | $ | 716 | |||||||||||||||
| Interest rate contracts | — | — | — | 3 | |||||||||||||||||||
| Total non-current derivative instruments | $ | 228 | $ | 363 | $ | 645 | $ | 719 | |||||||||||||||
__________________
(a)A portion of liability values have been presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet. See Note 3 for additional information.
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income. 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. Changes in fair value and realized settlements of interest rate derivatives are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations. See Note 20 for additional information on fair value.
The location and pre-tax effect of derivative instruments presented on the Consolidated Statements of Operations for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Realized gain (loss) on commodity contracts | |||||||||||||||||
Energy revenues (a) | $ | (613) | $ | (228) | $ | 464 | |||||||||||
Fuel and energy purchases (a) | 127 | 230 | (74) | ||||||||||||||
| Nuclear fuel amortization | — | — | (2) | ||||||||||||||
| Unrealized gain (loss) on commodity contracts | |||||||||||||||||
Operating revenues (b) | $ | 677 | $ | (847) | $ | (69) | |||||||||||
Energy expenses (b) | (52) | 135 | 36 | ||||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | |||||||||||||||||
| Interest expense and other finance charges | $ | 30 | $ | 12 | $ | (45) | |||||||||||
__________________
(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.
F-88
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Contract Terminations
Commodity Hedge Terminations. In March and April 2022, Talen Energy Marketing and a commercial counterparty terminated certain outstanding economic hedges that were scheduled to be priced and delivered from April 2022 through December 2022. As a result, Talen Energy Marketing realized a $124 million termination loss and agreed to settle the obligation on a monthly basis through January 2023. For year ended December 31, 2022, the realized termination loss is presented as “Energy revenues” on the Consolidated Statement of Operations and repayments are presented as “Derivatives with financing elements” on the Consolidated Statement of Cash Flows.
In May 2022, as a result of the Restructuring, certain commodity counterparties terminated power and natural gas agreements with a carrying value and fair value of $(33) million prior to the agreements’ scheduled termination dates. Accordingly, for the year ended December 31, 2022 Talen Energy Marketing recognized a $33 million net loss presented as either “Energy revenues” or “Fuel and energy purchases” on the Consolidated Statement of Operations. During 2022, Talen Energy Marketing received approximately $16 million in settlements from counterparties and at December 31, 2022 carries an approximately $40 million obligation to counterparties presented as “Accounts payable and accrued expenses” on the Consolidated Balance Sheet. Such amounts were settled upon Emergence.
Interest Rate Swap Terminations. In May 2022, as a result of the Restructuring, certain financing counterparties terminated interest rate swap agreements with a carrying value and fair value of $11 million prior to the agreements’ scheduled termination dates. The total notional amount terminated was approximately $500 million. As a result, Talen received $13 million of cash for the terminated positions and a return of previously posted collateral related to such positions and recognized a realized gain of $11 million to “Interest expense and other finance charges” on the Consolidated Statement of Operations during the year ended December 31, 2022.
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 commercial loss associated with its ERCOT activities during Winter Storm Uri for the year ended December 31, 2021.
Additionally, due to defaults of other ERCOT market participants, ERCOT instituted “short payments.” The short payment delays 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 the defaulting parties or through the collection of default uplift payments. Due to the uncertainty of when and how the short payments would ultimately be recovered from ERCOT, Talen recognized a charge of approximately $9 million during the year ended December 31, 2021 to fully reserve the amounts due to Talen that are subject to short-payment reimbursements. The outstanding reserve was approximately $4 million and $9 million at December 31, 2022 and 2021.
No assurance can be provided that these losses will not vary based on the final market settlements or any legal and (or) regulatory actions. See Note 16 for additional information on ERCOT systemic risks including a settlement by ERCOT with one of co-ops that had short-paid.
F-89
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
5. Revenue
The disaggregation of our operating revenues for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Capacity revenues | $ | 377 | $ | 444 | $ | 315 | |||||||||||
| Electricity sales and ancillary services, ISO/RTO | 2,534 | 1,960 | 475 | ||||||||||||||
| Physical electricity sales, bilateral contracts, other | 298 | 572 | 508 | ||||||||||||||
| Total revenue from contracts with customers | 3,209 | 2,976 | 1,298 | ||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | (120) | (2,048) | 428 | ||||||||||||||
| Operating revenues | $ | 3,089 | $ | 928 | $ | 1,726 | |||||||||||
Accounts Receivable
During the years ended December 31, 2022 and 2021, there were no significant changes in accounts receivable other than normal billing and collection transactions. See Note 4 for additional information on Talen’s credit risk on the carrying value of its receivables. See Note 7 for information on an allowance for doubtful accounts reserve recognized during the year ended December 31, 2021 and Note 11 for additional information on a Talen Energy Marketing receivables sales arrangement that was terminated in May 2022.
Accounts receivable, net presented on the Consolidated Balance Sheets at December 31 were:
| 2022 | 2021 | ||||||||||
| Customer accounts receivable | $ | 350 | $ | 56 | |||||||
| Other accounts receivable | 58 | 59 | |||||||||
| Accounts receivable, net | $ | 408 | $ | 115 | |||||||
Future Performance Obligations
In the normal course of business, Talen subsidiaries have future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements.
At December 31, 2022, the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
| 2023 | 2024 | 2025 | 2026 | 2027 | |||||||||||||||||||||||||
| Expected capacity revenues | $ | 231 | $ | 72 | $ | 2 | $ | — | $ | — | |||||||||||||||||||
The PJM capacity auctions for the 2025/2026 PJM Capacity Year and for any years thereafter have not yet been held. The 2023/2024 PJM Capacity Year auction was completed in June 2022 and the 2024/2025 PJM Capacity Year auction was completed in December 2022 but PJM delayed release of the results until February 2023. For the 2024/2025 PJM Capacity Year, Talen was awarded capacity revenue of $95 million for 2024 and $67 million for 2025. See Note 16 for additional information on the PJM RPM and these auctions.
PJM Capacity Sale and Prepetition Deferred Capacity Obligation
In March 2021, Talen entered into an arrangement with an unaffiliated third party to sell future capacity revenues awarded by PJM and cleared by Talen in PJM’s capacity auctions for the 2021/2022 PJM Capacity Year related to most of Talen’s generation facilities located in Pennsylvania, Maryland and New Jersey, excluding the Lower Mt. Bethel and Martins Creek facilities. Under the terms of the arrangement, Talen transferred the rights of future cash flows for certain cleared capacity with aggregate volumes of 7,352 MW and aggregate revenues of approximately $405 million. In exchange, Talen was advanced proceeds of $385 million that were further reduced by a $15 million purchaser discount. Talen received its remaining $20 million payment in variable monthly
F-90
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
installments that began in September 2021 and continued until the expiration of the arrangement in June 2022. During the term of the arrangement, Talen remained responsible for operating its generation facilities, retained the obligation to perform as a PJM generation capacity resource with respect to the capacity sold in the transaction, had retained its rights for any earned Capacity Performance bonus payments, and had retained the risks associated with performance deficiency penalties. The Prepetition Deferred Capacity Obligations were completed in June 2022 and were not renewed or extended.
As Talen continued to have future Capacity Performance obligations to PJM during the term of the arrangement, amounts advanced to Talen pursuant to the Prepetition Deferred Capacity Obligations were presented as “Deferred capacity obligations” on the Consolidated Balance Sheets. Capacity revenues were recognized over a period of time consistent with the fulfillment of Talen’s obligations to PJM. The $15 million purchaser discount paid by Talen to the unaffiliated third party represented an implied finance charge. Such amount was being amortized through expiry of the agreement and is presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations, with amortization totaling a non-material amount in 2022 and $13 million in 2021.
6. Income Taxes
The components of “Income tax benefit (expense)” for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Federal | $ | (9) | $ | (25) | $ | (21) | |||||||||||
| State | (4) | 1 | (1) | ||||||||||||||
| Current income taxes | (13) | (24) | (22) | ||||||||||||||
| Federal | 68 | 263 | 171 | ||||||||||||||
| State | (21) | 60 | 30 | ||||||||||||||
| Deferred income taxes | 47 | 323 | 201 | ||||||||||||||
| Investment tax credit | 1 | 1 | 2 | ||||||||||||||
| Income tax benefit (expense) | $ | 35 | $ | 300 | $ | 181 | |||||||||||
| Income (loss) before income taxes | $ | (1,328) | $ | (1,277) | $ | (845) | |||||||||||
| Effective income tax rate | 2.6 | % | 23.5 | % | 21.4 | % | |||||||||||
F-91
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Income (loss) before income taxes | $ | (1,328) | $ | (1,277) | $ | (845) | |||||||||||
| Income tax benefit (expense) | 35 | 300 | 181 | ||||||||||||||
| Effective tax rate | 2.6 | % | 23.5 | % | 21.4 | % | |||||||||||
| Federal income tax statutory tax rate | 21 | % | 21 | % | 21 | % | |||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | $ | 279 | $ | 269 | $ | 177 | |||||||||||
| Income tax increase (decrease) due to: | |||||||||||||||||
| State income taxes, net of federal benefit | 19 | 59 | 34 | ||||||||||||||
| Change in valuation allowance | (198) | — | — | ||||||||||||||
| Permanent differences | (94) | — | — | ||||||||||||||
| Nuclear decommissioning trust taxes | 28 | (28) | (27) | ||||||||||||||
| Other | 1 | — | (3) | ||||||||||||||
| Income tax benefit (expense) | $ | 35 | $ | 300 | $ | 181 | |||||||||||
The effective tax rate for the years ended December 31, 2022, 2021, and 2020 differed from the statutory rate primarily due to the change in valuation allowance, additional 20% trust tax on the NDT income, permanent differences, and state taxes.
Deferred Taxes
The components of deferred tax liabilities and deferred tax assets at December 31 were:
| 2022 | 2021 | ||||||||||
| Property, plant and equipment, net | $ | 436 | $ | 534 | |||||||
| Nuclear decommissioning trust | 394 | 520 | |||||||||
| Unrealized gain on qualifying derivatives | 25 | — | |||||||||
| Deferred tax liabilities | 855 | 1,054 | |||||||||
| Less: | |||||||||||
| Accrued pension costs | 68 | 76 | |||||||||
| Unrealized loss on qualifying derivatives | — | 124 | |||||||||
| Federal net operating loss carryforwards | 258 | 304 | |||||||||
| State net operating loss carryforwards | 34 | 57 | |||||||||
| Federal credits | 8 | 7 | |||||||||
| Accrued liabilities | 155 | 24 | |||||||||
| Interest limitation carryforward | 242 | 195 | |||||||||
| Investment in Subsidiaries | 33 | — | |||||||||
| Other | 96 | 56 | |||||||||
| Deferred tax assets | 894 | 843 | |||||||||
| Valuation allowance | (198) | (5) | |||||||||
| Deferred tax liabilities | $ | 159 | $ | 216 | |||||||
F-92
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Net Operating Losses
The components of NOL carryforwards at December 31 were:
| 2022 | 2021 | ||||||||||
| Federal, expirations 2036 - 2037 | $ | 58 | $ | 285 | |||||||
| Federal, indefinite expiration, limited to annual utilization of 80% | 1,198 | 1,189 | |||||||||
| State, expirations 2023 - 2041 | 647 | 785 | |||||||||
If substantial changes in our ownership occur, there could be an annual limitation on the amount of carryforwards that could be utilized.
Unrecognized Tax Benefits
| 2022 | 2021 | ||||||||||
| Balance, January 1 | $ | 9 | $ | 9 | |||||||
| Additions for tax positions of prior years | — | — | |||||||||
| Balance, December 31 | $ | 9 | $ | 9 | |||||||
Included in the balance of unrecognized tax benefits at both December 31, 2022 and 2021 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 ending December 31, 2019 and forward are open to examination by the relevant taxing authorities.
Valuation Allowance
As of December 31, 2022 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 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, including at the Emergence Date, management will continue to assess the available positive and negative evidence to determine the need for a valuation. Additionally, it is reasonably possible that sufficient positive evidence may become available that concludes a significant portion of the valuation allowance should be released. No assurance can be provided as to the timing or any amount associated with a valuation allowance release.
F-93
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
7. Other Operating Income (Expense)
The components of “Other operating income (expense), net” for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
Legal settlements (a) | $ | (18) | $ | (1) | $ | (3) | |||||||||||
| Organization change initiatives | (9) | (10) | (13) | ||||||||||||||
Accrued environmental costs liability revisions (b) | (13) | 4 | — | ||||||||||||||
ARO revisions on fully depreciated property, plant and equipment (b) | (5) | 3 | 6 | ||||||||||||||
ERCOT, allowance for doubtful accounts (c) | 5 | (9) | — | ||||||||||||||
Gain (loss) on asset sales (d) | 3 | 3 | 141 | ||||||||||||||
Fuel inventory net realizable value and obsolescence adjustments (e) | — | (2) | (31) | ||||||||||||||
| Lower Mt. Bethel casualty losses | — | — | (6) | ||||||||||||||
| Talen Montana closure expenses | — | — | (6) | ||||||||||||||
| Other | (3) | (3) | (1) | ||||||||||||||
| Other operating income (expense), net | $ | (40) | $ | (15) | $ | 87 | |||||||||||
__________________
(a)See Note 16 for additional information on the expenses incurred during 2022 related to the Kinder Morgan litigation.
(b)See Note 15 for additional information on accrued environmental costs and ARO revisions.
(c)See Note 4 for additional information on this allowance related to Winter Storm Uri.
(d)See Note 25 for additional information on the gain related to the sale of IEC in 2020.
(e)See Note 9 for additional information.
8. Other Non-Operating Income (Expense)
The components of “Other non-operating income (expense), net” for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Professional and legal expenses primarily for liability management initiatives | $ | (49) | $ | (23) | $ | — | |||||||||||
Earnings from equity investments (a) | 7 | — | — | ||||||||||||||
Gain on transfer of assets from the PA Mines UMWA Plan VEBA (b) | — | 15 | 22 | ||||||||||||||
| Professional and legal expenses on certain litigation | — | (5) | (4) | ||||||||||||||
| Postretirement benefit gain (loss), net | (7) | (31) | (25) | ||||||||||||||
| Debt restructuring gain (loss), net | (6) | (11) | (3) | ||||||||||||||
| Other | 11 | 7 | 1 | ||||||||||||||
| Other non-operating income (expense), net | $ | (44) | $ | (48) | $ | (9) | |||||||||||
__________________
(a)See Note 12 for additional information.
(b)See Note 21 for additional information.
F-94
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
9. Inventory
| December 31, 2022 | December 31, 2021 | ||||||||||
| Coal | $ | 189 | $ | 134 | |||||||
| Oil products | 61 | 64 | |||||||||
| Fuel inventory for electric generation | 250 | 198 | |||||||||
| Materials and supplies, net | 195 | 187 | |||||||||
| Environmental products | 12 | 18 | |||||||||
| Inventory, net | $ | 457 | $ | 403 | |||||||
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 not material for the years ended December 31, 2022 and 2021, and $31 million for the year ended December 31, 2020.
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 not material for the years ended December 31, 2022 and 2021, and $17 million for the year ended December 31, 2020.
Prepetition Inventory Repurchase Obligations
Pursuant to the Prepetition Inventory Repurchase Obligations, which were terminated in May 2022, Talen from time to time sold and transferred title to certain fuel inventory quantities to an unaffiliated party and was advanced cash consideration. Talen was required to subsequently repurchase the quantities as needed for electric generation or at expiry of the arrangement. The sales and repurchases occurred at a preset formula partially tied to market prices and outstanding repurchase obligations were reported at market value of inventory subject to the arrangement, limited to $165 million. The carrying value of inventory was reported at the lower of weighted average cost or net realizable value.
While the agreement was in place, Talen was required to subsequently repurchase the quantities transferred to the unaffiliated party. The inventories subject to the arrangement were not derecognized by Talen and any cash consideration advanced to Talen was presented as “Inventory repurchase obligations” on the Consolidated Balance Sheets. Advances were subject to change based on certain conditions in the arrangement, but were limited to $165 million, at any time. Under the arrangement, outstanding advances accrued fees of LIBOR plus 8.0%, and such fees are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
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.
The outstanding Prepetition Inventory Repurchase Obligations and the carrying value of inventories subject to the arrangement were:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Prepetition Inventory Repurchase Obligations outstanding | $ | — | $ | 165 | |||||||
Carrying value of inventories subject to arrangement (a) | — | 181 | |||||||||
__________________
(a)Presented as “Inventory, net” on the Consolidated Balance Sheets
F-95
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
10. Leases
The carrying value of operating lease right-of-use assets, operating lease liabilities, and characteristics associated with operating leases presented on the Consolidated Balance Sheets at December 31 were:
| 2022 | 2021 | ||||||||||
Other noncurrent assets (a) | $ | 4 | $ | 7 | |||||||
| Other current liabilities | $ | 1 | $ | 2 | |||||||
| Other noncurrent liabilities | 3 | 5 | |||||||||
Total operating lease liabilities (a) | $ | 4 | $ | 7 | |||||||
| Weighted-average remaining lease term (in years) | 13 | 10 | |||||||||
| Weighted-average discount rate | 6.5 | % | 6.5 | % | |||||||
__________________
(a)Excludes any amounts attributable to leases with a duration of less than 12 months.
Operating lease expense presented within the Consolidated Statement of Operations and operating lease cash expenditures and right-of-use assets obtained in exchange for new operating lease liabilities during the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
Lease expense (a) | $ | 2 | $ | 3 | $ | 3 | |||||||||||
Lease expenditures (a) | 2 | 3 | 3 | ||||||||||||||
__________________
(a)Excludes any amounts attributable to leases with a duration of less than 12 months.
The total estimated future annual minimum lease payments at December 31 were:
| 2022 | |||||
| 2023 | $ | 1 | |||
| 2024 | 1 | ||||
| 2025 | 1 | ||||
| 2026 | — | ||||
| 2027 | — | ||||
| Thereafter | 4 | ||||
| Total undiscounted payments | 7 | ||||
| Less: present value adjustment | 2 | ||||
| Total discounted lease payments | $ | 5 | |||
F-96
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
11. Equity Method Investments
The carrying values of equity-method investments which are presented as “Other noncurrent assets” on the Consolidated Balance Sheets were:
| Formation | Ownership Interest (a) | December 31, 2022 | December 31, 2021 | ||||||||||||||||||||
Talen Receivables Funding, LLC (b) | 2019 | 100.00 | % | $ | — | $ | 8 | ||||||||||||||||
| Conemaugh Fuels, LLC | 2002 | 22.22 | % | 15 | 7 | ||||||||||||||||||
| Keystone Fuels, LLC | 2000 | 12.34 | % | 8 | 3 | ||||||||||||||||||
Renewable joint ventures (c) | 2019 - 2021 | 49% / 50% | 6 | 3 | |||||||||||||||||||
| Total | $ | 29 | $ | 21 | |||||||||||||||||||
__________________
(a)Ownership at December 31, 2022.
(b)Investment derecognized in June 2022 upon termination. See “Receivables Company” below for additional information.
(c)The equity interests in these investments are owned through its Cumulus Affiliates.
Receivables Company
Under a receivables sales arrangement that was terminated in connection with the Restructuring, Talen Energy Marketing sold qualifying retail receivables at fair value for cash and equity consideration to TRF. Talen Energy Marketing derecognized the carrying value of the receivables at the time of sale with the difference between cash proceeds and carrying value presented as “Other non-operating income (loss), net.” TRF in-turn sold 100% of the receivables to an unaffiliated financial institution. Talen Energy Marketing serviced the receivables sold to TRF in exchange for a servicing fee. In May 2022, as a result of the Restructuring, the unaffiliated buyer terminated its agreement with TRF, which in turn terminated further sales of receivables from Talen Energy Marketing to TRF. Talen Energy Marketing continued to act as servicer under the arrangement, and collections of receivables sold under the arrangement prior to termination continued to be remitted to the unaffiliated buyer until all amounts owed by TRF to the buyer in respect thereof were paid in June 2022. See Note 3 for additional information on the Restructuring.
Prior to termination of the arrangement during 2022 and during 2021 and 2020, Talen was not the primary beneficiary of TRF because it did not have the power to direct the most significant activities that impact TRF’s economic performance. These activities included the power to select receivables that were sold by TRF to the unaffiliated purchaser and to appoint the servicer to manage collection activities. Accordingly, TRF was not consolidated by Talen from the date of execution of the agreement through June 2022. Talen’s risk of loss related to TRF was limited to its investment carrying value. See below for information on the consolidation of TRF beginning in June 2022.
The sales, contributions and return of capital activities associated with TRF for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Receivable sales by Talen to TRF | $ | 137 | $ | 492 | $ | 440 | |||||||||||
| Receivable contributions by Talen to TRF (non-cash) | 2 | 6 | 18 | ||||||||||||||
| Return of capital to Talen by TRF | 5 | 19 | 9 | ||||||||||||||
Any net income or net losses associated with the activities of TRF were recognized by Talen as equity earnings that are presented as “Other non-operating income (loss), net” on the Consolidated Statements of Operations. Additionally, gains and losses associated with the sale of Talen Energy Marketing receivables to TRF, servicing fee income earned by Talen Energy Marketing and equity earnings recognized by Talen were not material for the years ended December 31, 2022, 2021, and 2020.
In June 2022, in connection with the termination of the receivables sale arrangement and the settlement of final transactions, Talen Energy Marketing obtained a controlling financial interest in TRF, which was no longer
F-97
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
determined to be a VIE. Accordingly, Talen Energy Marketing derecognized its $5 million equity method investment in TRF and consolidated $5 million of TRF assets and liabilities, net, which included $7 million of cash. The receipt of cash is presented as “Investing Activities” on the Consolidated Statement of Cash Flows.
Fuels Companies
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 for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Fuel purchases | $ | 63 | $ | 52 | $ | 39 | |||||||||||
| Return of capital | 5 | 2 | 4 | ||||||||||||||
| (Capital contributions) | (17) | (4) | (2) | ||||||||||||||
Renewable Development Joint Ventures
Talen, through its Cumulus Affiliates, is party to joint venture agreements with various third parties, including Pattern Energy, an affiliate of Riverstone, and BQ Energy, for potential solar and wind projects to be located on or near Talen owned land adjacent to certain current and previously owned generation facilities. The joint ventures are pursuing an aggregate 280 MW of photovoltaic solar development projects and 600 MW of wind development projects. The joint venture project companies are currently each owned either 49% or 50% by Talen. Cash contributions by Talen Energy Supply to these joint ventures were $5 million for the year ended December 31, 2022 and non-material for the years ended December 31, 2021 and 2020.
While Talen believes that these projects are commercially viable, no assurance can be provided that requisite capital resources to complete development will be obtained or that these projects will be successfully completed.
12. Talen Energy Supply Equity Investments
Equity Investments
At December 31, 2022, Talen Energy Supply held the following investments in its Cumulus Affiliates, which are consolidated by Talen Energy Supply for financial statement reporting purposes. As Talen Energy Supply consolidates the below companies, the equity carrying value is eliminated in consolidation. The Cumulus Affiliates are not Debtors in the Restructuring.
| Affiliate Company | Carrying Value | Voting Percentage | ||||||||||||
Cumulus Digital Holdings (a) (b) (c) (e) (f) | $ | 114 | 74.5 | % | ||||||||||
Cumulus Growth subsidiaries (d) | ||||||||||||||
| Cumulus Real Estate Holdings | 7 | 99.9 | % | |||||||||||
| Cumulus Renewables Holdings | 10 | 99.9 | % | |||||||||||
| Cumulus Compute Holdings | 4 | 99.9 | % | |||||||||||
| Cumulus Battery Storage Holdings | 1 | 99.9 | % | |||||||||||
| Cumulus PT Energy Transitions Holdings | — | 66.7 | % | |||||||||||
__________________
(a)See below for additional information on the Cumulus Digital Holdings investment.
(b)Includes subsidiaries Cumulus Coin Holdings, Cumulus Coin, Cumulus Data Holdings, Cumulus Data, and Nautilus Cryptomine.
(c)Nautilus commenced commercial operations in February 2023.
F-98
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(d)Talen holds convertible voting preferred units.
(e)Excludes noncontrolling interest value.
(f)Talen Energy Supply has provided services through December 31, 2022 for which common equity has not been issued as of the date of these financial statements but is expected to be issued later in 2023.
Cumulus Digital Holdings common equity units are held by Talen Energy Supply and Talen Growth. These common equity units were issued in September 2022, in exchange for then-existing preferred equity investments in Cumulus Coin Holdings and Cumulus Data Holdings pursuant to the Cumulus Digital Equity Conversion.
Cumulus Term Sheet and Cumulus Digital Equity Conversion
In August 2022, in connection with the TEC Global Settlement, Talen Energy Supply and Talen Growth entered into the Cumulus Term Sheet to resolve a variety of issues relating to Cumulus Digital and its subsidiaries. The Cumulus Term Sheet provided for, among other things: (i) incremental funding commitments into Cumulus Digital by Talen Energy Supply, Riverstone, and Orion; (ii) conversion of all of Talen’s preferred units in Cumulus Coin Holdings and Cumulus Data Holdings into voting common units of Cumulus Digital Holdings, the indirect parent of Cumulus Coin Holdings and Cumulus Data Holdings (the Cumulus Digital Equity Conversion); (iii) increased Talen ownership of Cumulus Digital Holdings based on incremental funding by Talen; (iv) additional control over Cumulus Digital Holdings by Talen in the form of a new corporate governance structure and additional consent rights under the applicable LLC agreements; (v) a waiver by Orion of potential defaults and events of default under the Cumulus Digital Credit Agreement and amendments to the Cumulus Digital Credit Agreement to facilitate the Cumulus Term Sheet transactions; (vi) the affirmative right for Talen to refinance, repay, or purchase all amounts under such credit agreement; (vii) the release of certain claims related to the formation, governance, and operation of Cumulus Growth; (viii) assumption by the Debtors of all material agreements with Cumulus Digital Holdings and its subsidiaries, and (ix) further deferral of certain preexisting and ongoing fees owed to Talen by Cumulus Digital.
In September 2022, following authorization by the Bankruptcy Court Talen Energy Supply consummated the transactions contemplated by the Cumulus Term Sheet. As contemplated by the Cumulus Term Sheet: (i) Talen and Riverstone have provided incremental funding of $77 million and $3 million, respectively, to Cumulus Digital Holdings; (ii) Orion funded the remaining $89 million of its loan commitment under the Cumulus Digital Credit Agreement; and (iii) Riverstone sold $2 million of its common equity in Cumulus Digital Holdings to one current and one former member of the Talen management team.
Until the Emergence Date, each of Talen and Riverstone had the right to designate two members of the board of managers of Cumulus Digital Holdings, and to jointly designate an independent member subject to the approval of the Consenting Noteholders. Upon the Emergence Date, Talen has the right to designate four members of the board of managers of Cumulus Digital Holdings and Riverstone has the right to designate one board member.
2022 Cumulus Coin Matters
In August 2022, Cumulus Coin and TeraWulf executed an amendment to the Nautilus limited liability company agreement, pursuant to which Cumulus Coin agreed, among other things, to provide increased funding to Nautilus in exchange for increasing Cumulus Coin’s ownership percentage from 50% to approximately 67%. The agreement also included increased governance rights for Cumulus Coin, as well as provisions allowing each member to cover shortfalls by the other in exchange for increased ownership. As a result of the increased ownership and control by Cumulus Coin, it was determined that Cumulus Coin is the primary beneficiary of Nautilus, a VIE, and Nautilus was consolidated by Cumulus Coin for financial reporting purposes beginning in August 2022.
In September 2022, Cumulus Coin contributed an additional $20 million to Nautilus, which included funding a $5 million capital shortfall by TeraWulf. Accordingly, Cumulus Coin’s ownership percentage in Nautilus was increased to approximately 71% following such contribution. In October 2022, both Cumulus Coin and TeraWulf contributed their share of a $15 million planned contribution. In November 2022, Cumulus Coin contributed an additional $19 million to Nautilus, which included funding a $5 million shortfall by TeraWulf. Accordingly, Cumulus Coin’s ownership percentage was increased to approximately 75% following such contribution.
F-99
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
2022 Cumulus Digital Holdings Consolidation
In September 2022, as described above, the Bankruptcy Court approved the Cumulus Term Sheet and associated transactions, which resulted in an increase of Talen Energy Supply’s ownership in, and a change in the governance structure of, Cumulus Digital Holdings. While Talen and Riverstone, a related party, have equal representation on the board of managers of Cumulus Digital Holdings until the Emergence Date and could jointly direct the activities of Cumulus Digital Holdings that most significantly impact economic performance, Talen held the controlling financial interest, provided its employees to support all activities of Cumulus Digital Holdings, and directed the day-to-day management of Cumulus Digital Holdings. Therefore, it was determined that Talen is the primary beneficiary of Cumulus Digital Holdings and Talen began consolidating Cumulus Digital Holdings and its subsidiaries for financial reporting purposes as of September 30, 2022. In addition, in August 2022, as a result of amendments to the Nautilus LLC agreement, Cumulus Digital Holdings’ subsidiary, Cumulus Coin, consolidated Nautilus for financial reporting purposes. See “2022 Cumulus Coin Matters” above for additional information on Cumulus Coin’s consolidation of Nautilus.
The September 30, 2022 Cumulus Digital Holdings consolidation into Talen Energy Supply and the August 30, 2022 Nautilus consolidation into Cumulus Coin were accounted for as business combinations. The identifiable tangible and intangible assets and liabilities of Cumulus Digital Holdings and Nautilus (and its noncontrolling interests) were adjusted to their estimated fair values on the consolidation date. The following table summarizes the third quarter 2022 allocation of the fair values of the major classes of assets and liabilities of Cumulus Digital Holdings (including Nautilus) to Talen Energy Supply’s Consolidated Balance Sheet. The following allocations, other than “Restricted cash and cash equivalents,” were primarily non-cash in nature:
| Restricted cash and cash equivalents | $ | 116 | |||
| Other current assets | 32 | ||||
Property, plant and equipment (a) | 234 | ||||
| Accounts payable and other accrued liabilities | (43) | ||||
Long-term debt (b) | (180) | ||||
| Noncontrolling interest | (71) | ||||
Net assets acquired (c) | $ | 88 | |||
__________________
(a)Primarily represents construction work-in-progress.
(b)See Note 18 for additional information on this debt.
(c)Other assets and liabilities were revalued at Cumulus Digital and its subsidiaries that eliminate in consolidation of Talen Energy Supply.
The estimated fair value of Cumulus Digital Holdings was determined: (i) for Cumulus Coin by a discounted cash flow technique; and (ii) for Cumulus Data, based on book value. The technique for Cumulus Coin utilized significant unobservable inputs including discount rates varying from 13.5% to 14.5%. The range of discount rates and other discounted cash flow assumptions that were utilized are believed to be consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for Cumulus Digital Holdings, including, but not limited to estimated available future expected operating revenues and useful lives, capacity prices, energy prices, Bitcoin pricing, operating costs and capital expenditures.
As a result of the consolidation of Cumulus Digital Holdings and its related valuation, which included Nautilus, Talen recognized a loss of $170 million. The loss is primarily associated with the impairment of Cumulus Coin’s investment in Nautilus based upon the discounted cash flow valuation. The loss is presented on the Consolidated Statement of Operations as “Consolidation of subsidiary gain (loss), net.”
In addition, the September 2022 consolidation of Cumulus Digital Holdings, resulted in other non-cash changes to the Talen Energy Supply’s Consolidated Balance Sheet as shown below.
| Other noncurrent assets - accounts receivable with affiliate | $ | (15) | |||
| Other noncurrent assets - equity investments | (243) | ||||
F-100
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Prior to the September 2022 consolidation of Cumulus Digital Holdings, Talen Energy Supply had an affiliate accounts receivable asset with an aggregate carrying value of $15 million presented as “Noncurrent assets” on the Consolidated Balance Sheet, which is now eliminated in consolidation.
Prior to the September 2022 consolidation of Cumulus Digital Holdings, Talen Energy Supply owned preferred equity investments in Cumulus Coin Holdings and Cumulus Data Holdings with an aggregate carrying value of $243 million presented as “Noncurrent assets” on the Consolidated Balance Sheet that was converted to common equity and replaced with the consolidated assets and liabilities of Cumulus Digital Holdings and its subsidiaries.
Cumulus Digital Letters of Credit and Other Assurances
See Note 18 for information on letters of credit and other assurances issued by related parties for the Cumulus Digital TLF.
In the first quarter 2022, Talen Energy Supply issued a surety bond in the amount of $10 million, on behalf of Cumulus Data, for support of its development and construction activities.
Affiliate Related Party Agreements
Talen Energy Supply and (or) its subsidiaries have executed certain related party agreements in connection with the activities of the Cumulus Affiliates, in addition to the investments described above in “Equity Investments.”
Energy Supply Agreements. Cumulus Data is party to two separate agreements with Talen Generation for energy supply from Susquehanna Nuclear: an agreement for up to 300 MW to provide submetered power for Cumulus Coin-related activities and a separate agreement for up to 650 MW for data center-related activities. As of June 9, 2023, Cumulus Data has elected to receive 150 MW under the first agreement and none for the second agreement.
In the second quarter 2021, Talen Generation entered into a five-year agreement to supply Cumulus Data with up to 100 MW of retail power at a market-based fixed rate for the initial term of the agreement. The agreement supports Cumulus Data’s obligation to provide submetered power under a Ground Lease Agreement with Nautilus. Delivery of power under the agreement, together with the five-year initial term of the agreement, commenced in February 2023. Under the terms of the retail agreement, Cumulus Data may elect to increase the 100 MW capacity to up to 300 MW as Cumulus Coin and associated activities expand operations. The rate for power on the additional capacity would be fixed at the time of election based on a combination of the then-forward locational marginal price of power and auction-clearing capacity pricing at Susquehanna during the remainder of the initial term. In March 2023, Cumulus Data elected to increase the capacity under the retail energy agreement by an additional 50 MW. Cumulus Coin has no plans to expand operations beyond 150 MW at this time. The agreement has two three-year renewal options at the election of Cumulus Data. Upon the exercise of a renewal option, the rate for power during the renewal term would be fixed at the time of election based on a combination of the then-forward locational marginal price of power and auction-clearing capacity pricing at Susquehanna during the renewal term. Talen Generation’s obligation to supply power to Cumulus Data under the retail agreement is backstopped by a wholesale energy supply agreement with Susquehanna Nuclear on substantially the same terms as the retail agreement.
Pursuant to the Cumulus Term Sheet, the retail and wholesale agreements were amended in September 2022 to provide for an adjustment to the price thereunder upon the occurrence of both: (i) commercial operation of the Nautilus facility; and (ii) refinancing of the indebtedness under the Cumulus Digital TLF or the principal amount thereunder having been reduced to $100 million or less. At such time, the price will be adjusted to a then-current market price as determined by an independent third party, plus the statutory rate for renewable energy production tax credits on energy delivered thereunder to the extent Susquehanna is disqualified from being able to claim such credits due to Cumulus Data being an affiliate.
In the third quarter 2021, Talen Generation and Susquehanna Nuclear entered into an agreement that provides Cumulus Data the option to purchase up to 650 MW of retail power for seven years at a market-based fixed rate for its data center. Cumulus Data has five years from the date of the execution of the agreement to exercise the option. The agreement has two three-year renewal options. It is expected that Cumulus Data will provide submetered power
F-101
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
to its tenants in the Cumulus Data Center Campus. The option agreement will backstop Cumulus Data’s obligation to provide submetered power pursuant to the leases with its tenants. The cost of this power would be fixed at the time of exercise of the option based upon a combination of the then forward locational marginal price of power and auction-clearing capacity pricing at Susquehanna plus the statutory rate for renewable energy production tax credits described above, if any, subject to a floor at all times and prior to the date that the Cumulus Digital TLF has been refinanced or has been repaid to a principal balance of less than $100 million, a cap. As of December 31, 2022, Cumulus Data had not exercised any option to acquire power from Talen under this agreement.
Under the terms of the Plan of Reorganization and the TEC Global Settlement, Riverstone received TEC common stock (or cash, as applicable) equal to 25.00% of the net present value of projected savings under both of the aforementioned 300 MW and 650 MW agreements, as further described in the Plan of Reorganization. See Note 3 for additional information on the Plan of Reorganization and the TEC Global Settlement.
No revenue has been recognized under either power supply agreement during the year ended December 31, 2022. As a result of the September 2022 consolidation by Talen Energy Supply of Cumulus Digital Holdings, which includes Cumulus Data and Cumulus Coin’s investment in Nautilus, any revenue or expense recognized by Talen Generation or Cumulus Data will eliminate in consolidation at Talen Energy Supply and have no impact Talen’s consolidated results of operations.
These agreements were assumed by Talen upon the Bankruptcy Court’s approval of the transactions contemplated by the Cumulus Term Sheet.
Nautilus Ground Lease Agreement. The Nautilus facility is located on land at the Cumulus Data Center Campus leased by Nautilus pursuant to a Nautilus Ground Lease Agreement with Cumulus Data executed in 2021. The initial term of the lease expires on June 15, 2027. The lease may be extended for terms of three years, six months, and three years, respectively, at the election of Nautilus.
The Nautilus Ground Lease Agreement provides for submetering of electricity to Nautilus. The lease initially provided for 100 MW submetered, which was increased to 150 MW at Nautilus’s election in March 2023.
Corporate and Operational Services Agreement. Cumulus Digital and its subsidiaries have no employees. As a result, Cumulus Digital has contracted with Talen for services.
In September 2021, Talen Energy Supply agreed to provide corporate, administrative and operational services to Cumulus Digital and its subsidiaries under the Cumulus Digital COSA, including support of Cumulus Digital’s obligation to Nautilus under the Nautilus CSA.
In exchange for providing these services, Talen Energy Supply is entitled to an annual management fee of $750 thousand 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. Under the terms of the agreement, after giving effect to amendments in September 2022 in connection with the Cumulus Term Sheet, cash payment of fees is deferred until the earlier of: (i) two years from the commercial operations date of the Nautilus facility and (ii) the date Cumulus Data and Cumulus Coin meet a minimum interest coverage threshold under the Cumulus Digital TLF. Talen Energy Supply may elect to receive additional common units in Cumulus Digital Holdings in lieu of cash payments. Cash payment for the deferred fees, if any, will be payable ratably over the next succeeding 24 months following the deferral period. Fees and expenses payable under the agreement, combined with fees under the LC reimbursement agreement described in Note 18, and the amount of common units of Cumulus Digital Holdings Talen Energy Supply may elect to receive as compensation instead of cash payments, are subject to certain caps. The agreement terminates in September 2027, subject to earlier termination by Cumulus Digital upon 60 days prior notice or by Talen Energy Supply upon 180 days prior notice. Talen Energy Supply has recognized $13 million for the year ended December 31, 2022 on the Consolidated Statements of Operations as a reduction to general and administrative expenses for the management fees, reimbursable costs and expenses under the ASAs (described below). As a result of the September 2022 consolidation by Talen Energy Supply of Cumulus Digital Holdings, for activity going forward, any revenue or expense recognized by Talen Energy Supply or Cumulus Digital will eliminate in consolidation at Talen Energy Supply and have no impact on Talen’s results of operations.
F-102
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
In connection with the Cumulus Term Sheet, in September 2022, the Cumulus Digital COSA was combined with the Cumulus Digital ASA described below and, as amended, was assumed by Talen Energy Supply upon the Bankruptcy Court’s approval of the transactions contemplated by the Cumulus Term Sheet.
Preferred Unit Purchase Agreements for Support Services. In May 2022, Talen Energy Supply entered into several preferred unit purchase agreements with certain of the Cumulus Affiliates to compensate Talen Energy Supply for support costs incurred that were not covered by the Cumulus Digital COSA or not previously addressed for the other Cumulus Affiliates. These agreements relate to costs incurred from October 2021 through March 2022.
Talen Energy Supply determined that from October 2021 through March 2022, $2 million of excess support costs had been incurred for Cumulus Coin Holdings and Cumulus Data Holdings, of which $1 million related to the period January 2022 through March 2022. Because Cumulus Coin Holdings and Cumulus Data Holdings were not then consolidated with Talen Energy Supply for financial reporting purposes, Talen Energy Supply reduced general and administrative expenses by $2 million for the year ended December 31, 2022 on the Consolidated Statements of Operations and recognized an affiliate accounts receivable. As of the third quarter 2022, Cumulus Coin Holdings and Cumulus Data Holdings are now consolidated as part of Talen Energy Supply, therefore the affiliate accounts receivable eliminates in consolidation. The amounts related to the 2021 periods were recognized in 2021. In May 2022, Cumulus Coin Holdings and Cumulus Data Holdings issued approximately 2 million voting-convertible preferred units in the aggregate to Talen Energy Supply pursuant to the preferred unit purchase agreements in recognition of the excess support costs incurred from October 2021 through March 2022, which included 1 million units in respect of the $1 million incurred from October to December 2021 discussed above.
Talen Energy Supply determined that from October 2021 through March 2022, $1 million of support costs had been incurred related to Cumulus Renewables Holdings, Cumulus Battery Storage Holdings, Cumulus Compute Holdings, and Cumulus Real Estate Holdings. No adjustment to income and expenses was required, however, because these entities were at all applicable times controlled by Talen Energy Supply and accordingly are consolidated with Talen Energy Supply for financial reporting purposes during the periods covered. In May 2022, the Cumulus Affiliates issued approximately 2 million voting, convertible preferred units in the aggregate to Talen Energy Supply pursuant to the preferred unit purchase agreements in recognition of the support costs incurred from October 2021 through March 2022, which included 1 million units in respect of the $1 million incurred from October to December 2021 discussed above.
Affiliate Services Agreements. In May 2022, Talen Energy Supply entered into affiliate service agreements to provide corporate, administrative and operational services to each of Cumulus Real Estate Holdings, Cumulus Battery Storage Holdings, Cumulus Renewables Holdings and Cumulus Compute Holdings. At the same time, Talen Energy Supply entered into the Cumulus Digital ASA with Cumulus Digital and certain of its subsidiaries designed to compensate Talen Energy Supply for costs incurred in support of Cumulus Digital and its subsidiaries that were not contemplated by, or that were in excess of, amounts then-payable under the Cumulus Digital COSA. The agreements are terminable by either party upon 60 days prior notice or other events.
In connection with the Cumulus Term Sheet, in September 2022, the Cumulus Digital ASA was combined with the Cumulus Digital COSA described above, and the combined agreement assumed by Talen Energy Supply upon the Bankruptcy Court’s approval of the transactions contemplated by the Cumulus Term Sheet.
Amounts owed under the remaining ASAs are paid, at the option of the Cumulus counterparty, in cash or in additional convertible preferred units, provided that the form of payment becomes at Talen Energy Supply’s option at November 9, 2023 or upon Talen Energy Supply ceasing to own at least 50% of the outstanding equity of the Cumulus counterparty on an as-converted basis.
Talen Energy Supply determined that $4 million of support costs had been incurred related to the Cumulus Affiliates (excluding Cumulus Digital and its subsidiaries activity which is presented as Corporate and Operational Services Agreement above) during the year ended December 31, 2022. No adjustment to income and expenses was required, however, because these entities were all at applicable times controlled by Talen Energy Supply and accordingly are consolidated with Talen Energy Supply for financial reporting purposes during the periods covered.
F-103
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
At December 31, 2021, Talen Energy Supply had a $4 million balance on the Consolidated Balance Sheet (within Accounts receivable, net and Other noncurrent assets) for amounts due from Cumulus Digital and its subsidiaries, Cumulus Coin Holdings and Cumulus Data Holdings, related to the Cumulus Digital COSA, preferred unit purchase agreements, ASAs and other cost reimbursements, including LC fee reimbursements. As a result of the September 2022 consolidation by Talen Energy Supply of Cumulus Digital Holdings, the affiliate accounts receivable or payable recognized by Talen Energy Supply or Cumulus Digital will eliminate in consolidation at Talen Energy Supply and have no impact Talen’s financial condition. See Note 18 for information on the LC reimbursement agreement.
Nautilus Facility Operations Agreement. In December 2022, Nautilus and Talen Energy Supply executed a Facilities Operations Agreement (the “Beowulf FOA”) whereby Talen Energy Supply 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’ ongoing business at the Nautilus facility. The services were previously provided to Nautilus under the Beowulf FOA with Beowulf E&D, which was terminated upon execution of the Beowulf FOA with Talen Energy Supply. Talen Energy Supply 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 Beowulf FOA expires in December 2025.
Payment Netting Agreement. In December 2022, Nautilus, Cumulus Coin, Cumulus Digital, TeraWulf and Beowulf E&D entered into a Payment Netting Agreement pursuant to which the parties agreed to offset and (or) assume various amounts owed (i) by Nautilus to Cumulus Digital under the Nautilus CSA, (ii) by Nautilus to Beowulf E&D under the Beowulf FSA, and (iii) by Cumulus Coin and TeraWulf to Nautilus under the Nautilus limited liability company agreement. Among other things, Cumulus Coin agreed to assume approximately $2 million of Nautilus’ payment obligation to Cumulus Digital under the Nautilus CSA and approximately $400 thousand of TeraWulf’s deferred rent obligations under the amendment to the Nautilus Ground Lease Agreement discussed above. Pursuant to the Payment Netting Agreement, Cumulus Coin made a cash payment of approximately $2 million to Beowulf E&D.
Other. See Note 18 for information on LCs provided by Talen Energy Supply in support of the Cumulus Digital TLF and associated reimbursement agreement.
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 Talen Energy Corporation (or, at Talen Energy Corporation’s option, Talen Energy Supply) 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 Talen Energy Supply in excess of $33 million, if any, utilized to reduce income tax obligations of Talen Energy Corporation which, absent such tax attributes, would have otherwise been payable in connection with such transactions.
In December 2022, prior to confirmation of the Plan of Reorganization, the agreement was amended to provide that Riverstone’s indemnity obligation will terminate upon commencement of the wind-up or dissolution of the Riverstone affiliates party to the agreement, except to the extent an audit or redetermination has occurred or is pending at such time.
During the year ended December 31, 2022, Talen Energy Supply recognized a $2 million non-cash distribution presented as “Non-cash distribution to member” on the Consolidated Statement of Equity as the estimated impact of the agreement.
F-104
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
13. Nuclear Decommissioning Trust Funds
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | ||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 6 | $ | — | $ | — | $ | 6 | $ | 5 | $ | — | $ | — | $ | 5 | |||||||||||||||||||||||||||||||
| Equity securities | 521 | 485 | 69 | 937 | 531 | 664 | 17 | 1,178 | |||||||||||||||||||||||||||||||||||||||
| Debt securities | 507 | 1 | 31 | 477 | 444 | 8 | 2 | 450 | |||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | (20) | — | — | (20) | 2 | — | — | 2 | |||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds | $ | 1,014 | $ | 486 | $ | 100 | $ | 1,400 | $ | 982 | $ | 672 | $ | 19 | $ | 1,635 | |||||||||||||||||||||||||||||||
See Note 20 for additional information on the fair value of the Nuclear decommissioning trust funds. There were no available-for-sale debt securities with credit losses at December 31, 2022 or December 31, 2021.
As of December 31, 2022, 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 at December 31, 2022 were:
| Fair Value | Unrealized Losses | ||||||||||
| Corporate debt securities | $ | 107 | $ | 21 | |||||||
| Municipal debt securities | 62 | 2 | |||||||||
| U.S. Government debt securities | 206 | 8 | |||||||||
Total debt securities in unrealized loss position (a) | $ | 375 | $ | 31 | |||||||
__________________
(a)Unrealized losses primarily attributed to widening credit spreads.
There were securities in an unrealized loss position for a duration of one year or longer. The aggregate fair value of these securities and unrealized losses at December 31, 2022 were:
| Fair Value | Unrealized Losses | ||||||||||
| Corporate debt securities | $ | 28 | $ | 7 | |||||||
| Municipal debt securities | 4 | 1 | |||||||||
| Total debt securities in unrealized loss position | $ | 32 | $ | 8 | |||||||
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Maturities within one year | $ | 32 | $ | 27 | |||||||
| Maturities within two to five years | 173 | 159 | |||||||||
| Maturities thereafter | 272 | 264 | |||||||||
| Debt securities, fair value | $ | 477 | $ | 450 | |||||||
F-105
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The sales proceeds, gains, and losses for available-for-sale debt securities for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
Sales proceeds of nuclear decommissioning trust funds investments (a) | $ | 2,081 | $ | 1,571 | $ | 2,382 | |||||||||||
| Gross realized gains | 10 | 13 | 47 | ||||||||||||||
| Gross realized (losses) | (43) | (15) | (11) | ||||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the trust.
14. Property, Plant and Equipment
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (Years) | Cost | Accumulated Provision | Carrying Value | Cost | Accumulated Provision | Carrying Value | |||||||||||||||||||||||||||||||||||
| Electric generation | 3 - 27 | $ | 10,596 | $ | (6,797) | $ | 3,799 | $ | 10,664 | $ | (6,423) | $ | 4,241 | ||||||||||||||||||||||||||||
| Nuclear fuel | 1 - 7 | 491 | (316) | 175 | 510 | (326) | 184 | ||||||||||||||||||||||||||||||||||
| Other property and equipment | 1-20 | 157 | (82) | 75 | 147 | (76) | 71 | ||||||||||||||||||||||||||||||||||
| Intangible assets | 2-26 | 137 | (64) | 73 | 136 | (56) | 80 | ||||||||||||||||||||||||||||||||||
| Capitalized software | 1 - 5 | 102 | (95) | 7 | 98 | (90) | 8 | ||||||||||||||||||||||||||||||||||
| Construction work in progress | 576 | — | 576 | 151 | — | 151 | |||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 12,059 | $ | (7,354) | $ | 4,705 | $ | 11,706 | $ | (6,971) | $ | 4,735 | |||||||||||||||||||||||||||||
In 2022, Susquehanna Nuclear adjusted its ARO, which had an impact on PP&E. See Note 15 for additional information.
Brandon Shores. Brandon Shores is required by contract and permit to stop combusting coal by December 31, 2025. In the first quarter of 2023, the plan to convert the facility to oil combustion was reevaluated in light of increasing costs and declining PJM capacity revenues. Preliminary evaluations indicated that it has become probable that the facility will not operate after December 31, 2025. Accordingly, the Brandon Shores asset grouping, which has an aggregate carrying value of approximately $457 million as of December 31, 2022, will be assessed for recoverability in first quarter 2023.
The components of “Depreciation, amortization, and accretion” presented on the Consolidated Statements of Operations for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
Depreciation expense (a) | $ | 432 | $ | 436 | $ | 370 | |||||||||||
Amortization expense (b) | 12 | 19 | 23 | ||||||||||||||
Accretion expense (c) | 78 | 71 | 62 | ||||||||||||||
Qualifying derivative (gain) loss, net (d) | (2) | (2) | (3) | ||||||||||||||
| Depreciation, amortization, and accretion | $ | 520 | $ | 524 | $ | 452 | |||||||||||
__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 15 for additional information.
(d)Reclassified from AOCI.
The cost of nuclear fuel is charged to “Nuclear fuel amortization” on the Consolidated Statements of Operations.
F-106
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
In September 2022, as a result of the Cumulus Digital Equity Conversion, Talen Energy Supply began consolidating Cumulus Digital Holdings for financial reporting purposes. Accordingly, the above table includes property, plant and equipment of Cumulus Data Holdings. See Note 12 for additional information.
Interest on indebtedness capitalized to property, plant, and equipment under construction for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Capitalized interest expense | $ | 12 | $ | 4 | $ | 4 | |||||||||||
Estimated capitalized software and intangible asset amortization expense for each of the next five years is:
| 2023 | 2024 | 2025 | 2026 | 2027 | |||||||||||||||||||||||||
| Estimated amortization expense | $ | 10 | $ | 9 | $ | 7 | $ | 5 | $ | 5 | |||||||||||||||||||
Canceled Projects. During the year ended December 31, 2020, based on information confirmed in an inspection during the spring 2020 refueling outage, Talen confirmed that a capital project at Susquehanna Nuclear Unit 1 was no longer required. Accordingly, the project was canceled and its $21 million of accumulated “construction work in progress” carrying value was charged to “Operation and maintenance” presented on the Consolidated Statement 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 25 for information on a pending acquisition by Talen Montana of an additional interest in Colstrip Units 3 and 4.
The Colstrip Units have no carrying value at December 31, 2022 and 2021, and therefore are not displayed in the table below.
F-107
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The proportionate shares of property, plant and equipment 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, 2022 | |||||||||||||||||||||||
| 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 | |||||||||||||||
| December 31, 2021 | |||||||||||||||||||||||
| Electric generation | $ | 4,901 | $ | 24 | $ | 14 | $ | 1 | |||||||||||||||
| Nuclear fuel | 510 | — | — | — | |||||||||||||||||||
| Other property and equipment | 57 | — | — | 21 | |||||||||||||||||||
| Capitalized software | 17 | — | — | — | |||||||||||||||||||
| Intangible assets | 75 | — | — | — | |||||||||||||||||||
| Construction work in progress | 87 | 1 | — | — | |||||||||||||||||||
| Proportionate property, plant and equipment, cost | 5,647 | 25 | 14 | 22 | |||||||||||||||||||
| Less: accumulated depreciation and amortization | 4,200 | 4 | 3 | 18 | |||||||||||||||||||
| Proportionate property, plant and equipment, net | $ | 1,447 | $ | 21 | $ | 11 | $ | 4 | |||||||||||||||
2020 Impairments
The components of “Impairments” presented on the Consolidated Statements of Operations for the years ended December 31 were:
| 2020 | |||||
| Electric generation impairments | $ | 671 | |||
| Other property and equipment impairments | 10 | ||||
| Impairments | $ | 681 | |||
Montour. Montour had determined in 2020 that it will cease coal-fired generation operations by the end of 2025 and provided notification of such date to the EPA in November 2020. It is expected that by ceasing coal-fired generation operations, Montour will: (i) be allowed by the EPA CCR Rule to continue to place ash in its Ash Basin 1, which is required to be capped by no later than October 2028; and (ii) be permitted to forgo the incurrence of certain expenditures that would otherwise be required under the EPA CCR Rule and EPA ELG Rule for ongoing operations. See Note 2 for information on a revision in 2022 of the useful life of Montour’s coal assets from 2025 to 2023.
F-108
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The decision to cease coal-fired generation operations triggered both: (i) a reassessment of Montour’s inclusion as part of its existing asset group in the application of recoverability tests; and (ii) a recoverability assessment on the carrying value of Montour’s property, plant and equipment given the downward revision in the Montour’s expected useful life by approximately 10 years.
In connection with ceasing coal-fired generation operations at Montour, we expect changes in the manner in which certain economic and operational decisions regarding the activities of the generation facility are made. Accordingly, management determined the lowest level of identifiable cash flows for Montour is at the generation facility level and it should be tested for recoverability on a standalone basis.
The Montour recoverability analysis indicated the generation facility’s carrying value exceeded its future estimated undiscounted cash flows requiring an impairment charge to amend the generation facility’s carrying value of its property, plant and equipment to its estimated fair value. The estimated fair value of Montour was determined by a discounted cash flow technique that utilized significant unobservable inputs including discount rates varying from 8.5% to 13.5%. The range of discount rates and other discounted cash flow assumptions that were utilized are believed to be consistent with those used by principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for Montour, 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, Talen recognized a $514 million non-cash pre-tax impairment charge on its undepreciated property, plant and equipment as of December 31, 2020. Additionally, as an impairment charge was recognized on Montour, a $9 million non-cash gain presented within AOCI related to certain discontinued hedge contracts that was previously amortized into earnings over Montour’s useful life was immediately reclassified into earnings and presented as “Impairments” on the Consolidated Statements of Operations.
Keystone and Conemaugh. Talen proportionally consolidates its 22.22%.undivided interest in Conemaugh and its 12.34% undivided interest in Keystone on its Consolidated Balance Sheets. Together, these generation facilities are an asset group in the application of recoverability tests. In July 2020, a Talen subsidiary executed an agreement to purchase an additional 5.97% undivided interest in Conemaugh, which at June 30, 2020 was 16.25%, from another co-owner. The purchase was completed in September 2020. As the purchase price was below the carrying value of Talen’s interests in the generation facilities, a recoverability analysis was performed in the second quarter 2020 on the asset group utilizing assumptions that are believed to be consistent with principal market participants. Such assumptions consider available evidence regarding the prospects of future cash flows for Keystone and Conemaugh, including, but not limited to estimated available future generation volumes and useful lives, capacity prices, energy prices, operating costs, capital expenditures, and environmental costs. As the Keystone and Conemaugh aggregate property, plant and equipment net carrying value at June 30, 2020 exceeded the future estimated undiscounted cash flows, Talen recognized a $162 million non-cash pre-tax impairment charge on the undepreciated property, plant and equipment during the year ended December 31, 2020. Given the recent sale transactions of Keystone and Conemaugh, the fair value estimates were based on quoted market prices for the assets.
Other Property and Equipment. In the second quarter 2020, Talen performed a recoverability analysis on certain other property and equipment and determined the carrying value of such assets exceeded the future estimated undiscounted cash flows. The discounted cash flow assumptions used to determine the estimated fair value contained unobservable inputs such as forecasted revenues, operating costs, and a discount rate that is believed to be consistent with market participants. Accordingly, Talen recognized a $10 million non-cash pre-tax impairment charge on the undepreciated property, plant and equipment. Subsequent to the impairment, the carrying value of the property, plant, and equipment was not material.
F-109
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
15. Asset Retirement Obligations and Accrued Environmental Costs
| December 31, 2022 | December 31, 2021 | ||||||||||
Asset retirement obligations (a) | $ | 751 | $ | 760 | |||||||
Accrued environmental costs (a) | 35 | 23 | |||||||||
Total asset retirement obligations and accrued environmental costs (a) | 786 | 783 | |||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) (b) (c) | — | 16 | |||||||||
Less: amounts presented as “Liabilities subject to compromise” (a) (c) | 219 | — | |||||||||
| Asset retirement obligations and accrued environmental costs due after one year | $ | 567 | $ | 767 | |||||||
__________________
(a)At December 31, 2022 a portion of these amounts are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet. See Note 3 for additional information.
(b)Presented as “Other current liabilities” or “Liabilities subject to compromise” on the Consolidated Balance Sheets.
(c)“Liabilities subject to compromise” includes $24 million of asset retirement obligations and accrued environmental costs due within one year.
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 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 EPA CCR rulemaking, as described in section 16 of 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.
The changes of the ARO carrying value during the years ended December 31 were:
| 2022 | 2021 | ||||||||||
| Carrying value, January 1 | $ | 760 | $ | 708 | |||||||
| Obligations settled | (13) | (14) | |||||||||
| Changes in estimates and (or) settlement dates | (80) | (7) | |||||||||
| Obligations incurred | 8 | 4 | |||||||||
| Accretion expense | 76 | 69 | |||||||||
| Carrying value, December 31 | $ | 751 | $ | 760 | |||||||
| Additional Breakdown | |||||||||||
Nuclear (a) | $ | 564 | $ | 599 | |||||||
Non-Nuclear (b) | 187 | 161 | |||||||||
| Carrying value, December 31 | $ | 751 | $ | 760 | |||||||
__________________
(a)Collateralized by the Susquehanna Nuclear NDT.
(b)Certain liabilities are collateralized by surety bonds, letters of credit and cash.
F-110
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
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.
See Notes 13 and 20 for additional information on the 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 $89 million at December 31, 2022 and $79 million at December 31, 2021.
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 “Montana Financial Assurance” in Note 16 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.
Brunner Island. In 2021, the carrying value of the Brunner Island ash impoundments ARO decreased by approximately $12 million due to a decline of expected remediation costs that resulted from management cost control initiatives.
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. In June 2022, work scope and estimate updates resulted in a $13 million charge presented as “Other operating income (expense), net” on the Consolidated Statements of Operations for the year ended December 31, 2022. At December 31, 2022 and December 31, 2021, liabilities of $34 million and $21 million, which were discounted based on a credit adjusted risk-free rate, were accrued to cover the costs of groundwater pumping and treating groundwater at the site for approximately 50 years. This liability is discounted based on a credit adjusted
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risk-free rate that was in existence at the time of liability recognition of 8.41%. At December 31, 2022 the expected undiscounted payments are estimated to be:
| 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| Payments | $ | 3 | $ | 4 | $ | 4 | $ | 10 | $ | 1 | $ | 115 | $ | 137 | |||||||||||||||||||||||||||
At December 31, 2022, all accrued environmental costs, including the ones described above, are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet.
16. Commitments and Contingencies
Litigation
Talen (or its affiliates) is involved in certain legal proceedings, claims and litigation. While Talen believes that we have meritorious defenses or claims, as applicable, 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. See “Talen Restructuring” below.
No estimate of the possible loss or range of loss in excess of amounts accrued, if any, can be made at this time regarding the matters specifically described below because the inherently unpredictable nature of legal proceedings may be exacerbated by various factors such as ongoing discovery, significant facts that are in dispute, the stage of the proceeding and the wide range of potential outcomes for any such matter. As a result, additional losses actually incurred in excess of amounts accrued could be substantial.
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.
Montana Hydroelectric Litigation. Talen Montana is a defendant in litigation in the U.S. District Court for the District of Montana relating to Talen Montana’s past ownership and operation of hydroelectric generation facilities in Montana, which were sold to NorthWestern in November 2014. 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 2012, the U.S. Supreme Court unanimously overturned judgments of the Montana state courts that had held in favor of the State of Montana and remanded the case to the Montana state courts for further proceedings. In April 2016, following an extended period of inactivity, the State filed an updated complaint against both Talen Montana and NorthWestern, making allegations substantially similar to those in the original suit. The case was subsequently removed to the U.S. District Court for the District of Montana (the Montana District Court). In August 2018, the Montana District Court granted Talen Montana’s motion to dismiss claims related to several facilities near Great Falls, Montana. These facilities represented approximately 50% of the damages awarded in the prior judgments that were overturned by the U.S. Supreme Court. In February 2019, the Montana District Court joined the United States and certain federal government entities as co-defendants based on the federal ownership interests in certain of the applicable streambeds. In October 2019, the State filed an amended complaint, adding claims against the United States under the Federal Quiet Title Act. A bench trial on the issue of defendants’ liability was held in January 2022. 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 Montana, the court stated that Talen Montana and NorthWestern will be required to compensate the State for past, present and future use. This holding may be appealed by any of the parties. Damages and defenses related to this proceeding are to be addressed in a future adjudication. Upon Emergence in May 2023, however, Talen Montana’s liability on all claims asserted
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by the State was discharged under the Plan of Reorganization; consequently, 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. 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 due to defendants’ other operational failures during Winter Storm Uri. Approximately 130 insurance companies filed a similar suit against the same Talen subsidiaries and certain other defendants seeking to recover payments to policyholders for damage to residential and commercial properties caused by Winter Storm Uri. The plaintiffs seek unspecified compensatory, punitive and other damages. The State of Texas multi-district litigation panel ordered all of these cases transferred to the multi-district litigation pretrial court, designated a district court and assigned a judge for purposes of pretrial matters. In January 2023, the district court issued an order denying a motion to dismiss filed by defendants owning generation facilities. These defendants will seek appellate review of the order. As a result of the Talen defendants’ bankruptcy cases, certain plaintiffs have agreed to voluntarily dismiss their claims against the Talen defendants. The Talen subsidiaries named as defendants in these lawsuits were Debtors. These remaining lawsuits have been stayed under the Bankruptcy Code and plaintiffs are limited to recovering any damages from the Talen defendants’ insurers under the plan of reorganization confirmed by the Bankruptcy Court in the Talen defendants’ bankruptcy cases.
In June 2021, Talen intervened in five cases in which, among other things, certain market participants are challenging the validity of the PUCT’s order setting the price cap at $9,000/MWh during Winter Storm Uri. One case is pending in the Texas Court of Appeals, Third District, and three of these cases are pending in the State of Texas District Court in Travis County. One district court case has been abated pending resolution of the appellate cases and no briefing schedule has been entered in the remaining two district court cases. In March 2023, the Third District issued an opinion in one of the cases that, in part, reversed the PUCT’s order setting the price cap at $9,000/MWh during Winter Storm Uri because such order exceeded the PUCT’s authority and remanded the case to the PUCT to take actions consistent with its opinion. The PUCT (along with Talen and others) has requested leave to appeal the Third Circuit’s ruling to the Texas Supreme Court. Talen is coordinating its efforts in these suits with certain of the other parties in the suits, including the PUCT. 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.
Kinder Morgan Litigation. In June 2021, an affiliate of Kinder Morgan filed a suit in the State of Texas District Court in Harris County against Talen Energy Marketing, Nueces Bay and affiliates of Texas Eastern and NextEra. In the suit, the Kinder Morgan affiliate alleges, among other things, that affiliates of Talen agreed to purchase natural gas from it during Winter Storm Uri at the then prevailing market rate. Talen disputes that it purchased gas from the Kinder Morgan affiliate. The case has been removed to the Bankruptcy Court. In September 2022, NextEra was dismissed from the case, and in December 2022, Texas Eastern was dismissed from the case. Discovery in the case is on-going. As a result of ongoing settlement negotiations, Talen recognized an $18 million charge during the year ended December 31, 2022, which is presented as “Other operating income (expense), net” on the Consolidated Statement of Operations. At this time, Talen cannot predict the final outcome of this matter or any additional effect on Talen’s results of operations and liquidity.
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 relating to a distribution by Talen Montana to PPL of $733 million of net proceeds from the sale of Talen Montana’s hydroelectric facilities in November 2014 (the “Distribution”), which was during PPL’s tenure as owner of Talen Montana. The action generally alleges that the Distribution was improper under applicable law and claims that PPL and its directors improperly made the Distribution, leaving Talen Montana without adequate funds to pay its obligations. Plaintiff seeks compensatory and punitive damages. In January 2020, PPL filed a motion to dismiss this suit for, among other things, lack of personal jurisdiction. In September 2020, the Montana state court denied PPL’s motion to dismiss, but granted a stay of the Montana claims until resolution of the Delaware case described below. After commencement of the Restructuring and following numerous procedural matters, the case has been transferred to the Bankruptcy Court.
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In November 2018, PPL filed a lawsuit in Delaware Court of Chancery (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. In October 2019, the Delaware Court granted Talen defendants’ motion to dismiss one of PPL’s claims but denied Talen defendants’ other requests for dismissal. After the commencement of the Restructuring and following numerous procedural matters, the case has been transferred to the Bankruptcy Court.
In addition, after the commencement of the Restructuring, Talen Montana filed an adversary complaint against PPL and its affiliates in the Bankruptcy Court. The adversary complaint asserts actual and constructive fraudulent transfer claims arising from the Distribution, similar to the claims asserted in the Montana action. In August 2022, the Bankruptcy Court entered an order consolidating the Montana and Delaware cases with the adversary proceeding and Talen Montana and Talen Energy Supply filed an amended and consolidated complaint. The amended and consolidated complaint asserts substantially the same fraudulent transfer claims as in the adversary complaint, an indemnity claim by Talen Energy Supply to recover damages, including defense costs, arising from PPL’s claims, and claims under the Bankruptcy Code to disallow claims asserted by PPL and its affiliates in the Bankruptcy Court and to subordinate any such claims that are allowed. In September 2022, the PPL defendants filed an answer responding to the amended and consolidated complaint and asserted counterclaims against the Talen defendants substantially similar to the claims asserted in the Delaware Court. At the PPL defendants’ request, the parties participated in a mediation in February 2023. No settlement was reached during the mediation. Talen Montana and its affiliates believe that PPL’s claims are without merit and intend to vigorously prosecute and defend these actions. PPL is expected to vigorously defend the claims asserted by Talen Montana. Talen Montana and Talen cannot predict the outcome of this matter or its effect on Talen Montana and Talen; however, a material adverse judgment could have an adverse effect on Talen Montana’s and 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 Talen Energy Supply, Talen Energy Corporation, the TERP, and the Talen Energy retirement plan committee, alleging that they are owed enhanced benefits under the TERP because: (i) either or both of the 2015 Talen Formation Transactions and (or) the 2016 take-private transaction constituted a change in control as defined in the TERP; and (ii) their employment was terminated within three years following such change in control. The plaintiffs also allege they are entitled to such benefits because certain provisions in a PPL pension plan were not included in the TERP, and that the availability of the claimed additional benefits was not properly disclosed or made known to them. The lawsuit seeks class action status on behalf of all Talen non-union employees (or their surviving beneficiaries) whose employment was terminated between June 1, 2015 and December 5, 2019 and who were age 55 or older at the time of termination. In February 2021, the Talen defendants filed a motion to dismiss the plaintiffs’ claims on the grounds that plaintiffs released the claims in connection with their termination of employment, and further that certain claims are time-barred by the applicable statute of limitations. In September 2021, the court denied this motion on procedural grounds and ordered the parties to commence discovery, but also noted that the court remained willing to consider the Talen defendants’ arguments at a later point in the proceeding. In January 2022, plaintiffs filed a motion for class certification seeking to certify the class outlined above. We filed our opposition to this motion in April 2022. After commencement of the Restructuring and following the filing of a joint motion, the District Court in Pennsylvania abated the litigation through January 31, 2023, subject to certain exceptions. In March 2023, the District Court granted plaintiffs leave to amend their complaint to add ten former retirement plan committee members as defendants, and the plaintiffs amended their complaint accordingly. Also in March 2023, the plaintiffs and the Talen defendants filed a joint stipulation with the District Court outlining their agreement with respect to the timing of the Talen defendants’ production of certain documents, which had been stayed as a result of the Restructuring. At this time, we cannot predict the outcome of this matter or its effect on Talen; however, a material adverse judgment could have an adverse effect on Talen’s results of operations and liquidity.
Railroad Surcharge Litigation. In September 2019, Talen Energy Supply 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, BNSF Railway Company, CSX Transportation, Inc., Norfolk Southern Railway Company and Union Pacific Railroad Company (collectively, the Railroads), violated the U.S. antitrust laws by conspiring during the periods
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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. During the relevant periods, the Talen plaintiffs purchased rail freight transportation directly from certain of the Railroads to ship coal. The Talen plaintiffs were assessed rail fuel surcharges in connection with that transportation, and the Talen plaintiffs claim that they paid higher rail freight shipment rates than they otherwise would have paid absent the alleged conspiracy. In the suit, the Talen plaintiffs have requested, among other things, compensatory damages, to be automatically trebled under the antitrust laws, and attorneys’ fees. In February 2020, this litigation was consolidated with certain other similar litigation in the District Court for the District of Columbia under the multi-district litigation rules. Talen expects the Railroads to vigorously defend this suit and the other similar suits. At this time, Talen cannot predict the outcome of this matter.
Spent Nuclear Fuel Litigation. There remains substantial uncertainty regarding the nuclear industry’s permanent disposal of spent nuclear fuel. Federal law requires the U.S. Government to provide for the permanent disposal of commercial spent nuclear fuel. Prior to May 2014, nuclear generation facility operators were required to contribute to a fund to pay for the transportation and disposal of spent nuclear fuel. 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.
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 spent nuclear fuel by the statutory deadline. The settlement agreement required the U.S. Government to reimburse certain costs to temporarily store spent nuclear fuel at the Susquehanna nuclear generation facility. In exchange, Susquehanna Nuclear waived any claims against the U.S. Government for costs paid or injuries sustained related to temporarily storing spent nuclear fuel. In 2022 and 2021, Susquehanna Nuclear received reimbursements of $7 million and $20 million for such costs. At December 31, 2022, the carrying value of allowable 2022 unreimbursed costs presented as “Accounts receivable, net” on the Consolidated Balance Sheet was $24 million. A claim for such costs will be submitted under the agreement in 2023. This agreement has been extended three times, most recently in September 2020, through the end of 2022. Susquehanna Nuclear has been notified by the U.S. Government of its desire and intention to renew and extend this agreement and Susquehanna Nuclear is currently in negotiating the terms of this planned extension. In November 2022, the U.S. Government expressed an intent to extend the settlement agreement through the end of 2025. The extension will likely be executed in the second quarter of 2023. We cannot be certain that subsequent amendments will extend these arrangements beyond 2025.
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 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.
Regulatory
Talen is subject to regulation by federal and state agencies in the various regions where we conduct business, including, but not limited to: the FERC; 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. During the Restructuring, the Debtors may be required to obtain regulatory approvals from various federal, state, and local regulators in order to consummate the plan and restructuring pursuant to the RSA and RSA Term Sheet.
Talen is party to proceedings before such agencies arising in the ordinary course of business and have other regulatory exposure due to new and (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 Capacity Market
PJM MOPR. In July 2021, PJM filed proposed tariff language that significantly reduces 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 therefore PJM’s MOPR tariff language went into effect in September 2021 by operation of law. Appeals relating to the narrowed PJM MOPR are pending before the U.S. Court of Appeals for the Third Circuit. As a result, the final impact on Talen’s financial condition, results of operations, or liquidity is not known at this time. In December 2021, in a related order, FERC requested that PJM delay the auction again and file the new auction schedule. 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 2025/2026 in June 2024, 2026/2027 in December 2024, 2027/2028 in June 2025, and 2028/2029 in December 2025.
2024/25 Capacity Auction. PJM delayed the release of the 2024/2025 PJM Base Residual Auction results due to certain issues. In December 2022, PJM filed a request with FERC to revise its tariff to enable PJM to adjust an auction parameter and to make adjustments to subsequent auction outcomes if similar issues arise in future auctions. In February 2023, FERC approved PJM’s filing. Rehearing of FERC’s order was denied by operation of law in April 2023, and several parties have appealed the order to the U.S. Court of Appeals for the Third Circuit. On February 27, 2023, PJM released its 2024/2025 auction results.
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 February 2022, FERC denied rehearing requests on its September 2021 order from multiple parties, including Talen. 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. The final impact of this order on Talen’s financial condition, results of operations or liquidity is unknown at this time.
Winter Storm Elliot. See “Regulatory – Winter Storm Elliot” below for information relating to Capacity Performance penalties and revenues arising from Winter Storm Elliott, which occurred from December 23 to 27, 2022.
ERCOT Market Systemic Risks. Due to the effects of Winter Storm Uri, certain market participants in ERCOT have defaulted on settlements and caused a deficit of payments to ERCOT. For example, a number of market participants, including co-ops and retail electric providers filed for bankruptcy protection following the winter events primarily in response to unpaid ERCOT settlement invoices. In May 2022, ERCOT reported a cumulative aggregate payment deficit of approximately $2.3 billion as result of winter storm events.
As a result of the ERCOT payment deficits, ERCOT has not been able to pay market participants for all amounts owed to them and has instituted “short payments.” The short payment delays 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.
There is a likelihood that due to market participant defaults, ERCOT could require Talen, as a non-defaulting market participant, to pay for unrecovered amounts in the form of uplift default charges or similar payments. The potential requirement for Talen and (or) our ERCOT QSE (on our behalf) to make default uplift payments or have short payments imposed could have a material impact on our results of operations, financial condition and cash flows. However, at this time, we cannot predict any amounts of uplift default charges or short payments that would be applicable to Talen.
In June 2021, Texas enacted a law that provides co-ops, retail electric providers and ERCOT the ability to finance, at low-interest rates, costs owed to ERCOT or outstanding default balances that are associated with Winter Storm Uri. Co-op and retail electric providers’ related costs financed through the legislatively designed mechanisms are capped at $2.1 billion and will be repaid by each covered entity. ERCOT’s costs financed through the legislatively designed mechanisms are capped at $800 million and will be repaid through a default charge which is applicable to all market participants. In July 2021, ERCOT filed applications with the PUCT to pursue financing of
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its default balance and retail electric providers’ related costs, and the PUCT adopted related debt obligation orders in October 2021. In November 2021, ERCOT notified market participants that payments authorized by the debt obligation order will be disbursed to affected QSEs. Also, in November 2021, Talen received a non-material amount from debt obligation disbursements for certain short payments. In September 2022, ERCOT reached a settlement agreement with the largest defaulting co-op. 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. The ERCOT Board voted to approve the settlement agreement, and the first payment to ERCOT occurred on December 15, 2022, based on the agreed upon payment schedule over a period of years.
Under PUCT rules that govern certain electricity system events, the ERCOT system-wide offer cap for energy for the remainder of 2021 was set at $2,000/MWh due to the length of the Winter Storm Uri event. While this cap was in place, generation resources could seek reimbursement for any actual marginal costs in excess of the larger of $2,000/MWh or the resource’s real-time energy price. In 2022, the system-wide offer cap was $5,000/MWh based on a December 2021 PUCT order, although the cap could be reduced to $2,000/MWh, if certain conditions are met.
In January 2023, the PUCT adopted the PCM market design in response to a directive contained within Texas Senate Bill 3 from 2021 to address market reliability concerns in Texas. There remains significant uncertainty surrounding the details of the proposed PUCT PCM design, the timing for implementation and whether the legislature will take further action to dictate a market design other than the PUCT PCM. At this time, Talen cannot fully predict the impacts of the PUCT PCM market design, when and if implemented, on its results of operation and liquidity.
See Note 4 for additional information on short payments to Talen by ERCOT and the effects of Winter Storm Uri and see “Legal Matters - ERCOT Weather Event Lawsuits” above for Talen intervening in certain PUCT orders related to the event.
Inflation Reduction Act of 2022. The Inflation Reduction Act of 2022 was signed into law in August 2022. Among the Act’s provisions are: (i) amendments to the Internal Revenue 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.
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 Nuclear 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 exceed $25 per MWh. The annual pro-rata decrease will be based upon a portion of the qualifying generation facility’s prior year gross receipts (as defined and calculated per implementation guidelines to be issued). The credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation). Susquehanna Nuclear generated approximately 18 million MWh in each of the calendar years 2022, 2021 and 2020.
Section 45 of the Internal Revenue Code was modified to provide qualified clean energy projects with a $3 per MWh, ten-year transferable credit for electricity produced and sold to an unrelated party during each tax year. To qualify for the credit, the eligible facility must be placed in service after December 31, 2021 or begin construction prior to January 1, 2025. Additionally, the Act expands the investment tax credit program, within section 48 of the Internal Revenue Code, beyond the existing technologies, such as solar, to include qualified energy storage projects. A transferable base credit equaling 6% of the basis value of qualified property is also created. These programs are each subject to potential adjustments for inflation escalators, meeting prevailing wage and apprenticeship requirements, attaining specified percentages of domestic content, and locating the project within an energy community. After January 1, 2025, under the relevant qualification criteria, clean energy projects with a zero-greenhouse gas emission rate qualify for a new 10-year clean electricity production credit and energy storage projects qualify for a new clean electricity investment credit with equivalent terms as above.
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These changes are expected to increase Susquehanna Nuclear’s income and impact the expected returns for Talen’s expected future clean energy development projects. However, the Act’s provisions are subject to implementation regulations, whose terms are not yet known. As such, Talen cannot fully predict the impacts to its liquidity or results of operations.
Winter Storm Elliott.
In April 2023, PJM notified Talen Energy Marketing of an update to the expected capacity performance penalties incurred by Talen’s nonperforming generation facilities and bonus revenues earned by performing generation facilities. Accordingly, Talen Energy Marketing has recognized in 2022 and 2023 an aggregate penalty of $48 million, net of expected bonus revenues. Talen Energy Marketing and its affiliates have filed complaints against PJM at FERC disputing a significant portion of the penalties assessed by PJM. As a result, the net penalty recognized by Talen Energy Marketing could be reduced if the complaints are successfully resolved or settled. Other suppliers are also disputing penalties assessed by PJM. If such disputes were successful, it also would reduce the bonuses payable to Talen Energy Marketing. FERC has not yet ruled on the merits of these complaints. At PJM’s request, FERC established settlement proceedings, which were terminated in early September 2023 as a result of the parties reaching a settlement in principle. No assurance can be provided that Talen Energy Marketing will be successful in reducing penalties assessed by PJM or that PJM will upwardly revise its net penalty assessment to Talen.
In April 2023, FERC approved tariff revisions proposed by PJM that impact the time by which capacity performance non-performance charges are assessed, including those stemming from Winter Storm Elliot. Specifically, the revisions allow PJM to permit non-performance charges associated with Winter Storm Elliot to be paid over nine-month period with interest assessed on amounts paid after May 2023. Talen Energy Marketing has elected the extended payment terms.
In December 2022, the FERC and the NERC announced that they were opening a joint inquiry into the operations of the bulk-power system leading up to and during the extreme winter weather conditions that occurred during Winter Storm Elliott. Reliability First and Texas Reliability Coordinator issued document holds for investigative purposes. On March 13, 2023, Talen, received data requests, along with all other PJM generators, from FERC and NERC regarding operations of its units during Winter Storm Elliott.
Environmental
Extensive federal, state and local environmental laws and regulations are applicable to our business, including 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 environmental statutes, regulations or requirements.
Water and Waste
In August and October 2020, the EPA finalized certain changes to the EPA CCR Rule and the EPA ELG Rule. Among other things, changes in both rules allows 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. With Talen’s plans to cease coal operations, Talen requested extensions for compliance for both the EPA ELG Rule and EPA CCR Rule that are applicable to certain Talen 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.
The EPA has recently proposed additional changes to the EPA ELG Rule in March 2023 and to the EPA CCR Rule in May 2023. The ELG 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. For the EPA CCR Rule changes, EPA has proposed to impose new requirements on legacy CCR impoundments and CCR Management Units, which could affect several Talen facilities. Furthermore, EPA’s interpretations on the EPA CCR Rule continue to evolve through enforcement. At this time, Talen cannot predict the
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outcome of these various rule changes on the operations of its coal-fired generation facilities and its results of operations.
Air
Since 2016 Connecticut, Delaware, Maryland and New York have submitted petitions to the EPA under Section 126 of the CAA requesting that EPA make findings that different upwind coal-fired power generation facilities, including our Brunner Island and Montour generation facilities and the Keystone and Conemaugh generation facilities, in which we own undivided interests, are emitting air pollutants that significantly contribute to non-attainment of the 2008 and (or) 2015 ozone EPA NAAQS in their respective states (each state pointing to different generation facilities). The EPA has denied each states’ petitions. After Delaware, Maryland, New York and certain environmental groups filed petitions for review of the decisions for their states in the U.S. Court of Appeals for the D.C. Circuit, the Court vacated and remanded the Maryland and New York denials. The EPA is in the process of reconsidering the denials. In a parallel effort to attain the EPA NAAQS, in May 2019 Maryland also requested, citing Section 184 of the CAA, that the Ozone Transport Commission petition EPA to lower air emissions from various generation facilities in Pennsylvania, including some generation facilities owned by Talen. After receiving public comment on the matter in June 2020, the Ozone Transport Commission recommended to EPA that they require additional nitrogen oxides control measures at the affected generation facilities. In December 2020, the EPA published a notice summarizing the OTC recommendations and seeking comments on the recommendations. Since receiving comments in February 2021, the EPA has not yet taken any action on the recommendation.
In February 2020, the states of New Jersey, Connecticut, Delaware, New York and Massachusetts, and the City of New York, filed a lawsuit in the U.S. District Court for the Southern District of New York seeking to compel EPA to promulgate EPA FIPS for the 2008 EPA NAAQS to address nitrogen oxide emissions from seven states, including Pennsylvania. In July 2020, the Court issued a decision requiring the EPA to issue those EPA FIPS in March 2021. Also, in March 2021, the EPA finalized revisions to the EPA CSAPR that, effective in June 2021, lowered the Ozone Season nitrogen oxide allowance budgets for certain upwind states, including Pennsylvania and Maryland, beginning in 2021. Talen had sufficient nitrogen oxide allowances to support generation in the 2022 ozone seasons and will manage its electricity generation and allowance inventory to maintain compliance going forward.
To address the 2015 ozone standard, in March 2023, EPA released a pre-publication of final changes to the EPA CSAPR ozone season nitrogen oxide allowance trading program for 2023 and beyond. The final changes are known as the “Good Neighbor FIP.” EPA has made some reductions in allowance allocations, among other changes, to minimize nitrogen oxide emissions during the ozone season. 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.
In May 2022, Pennsylvania updated its nitrogen oxide RACT standards for Montour and Keystone and Conemaugh and proposed those standards to EPA as part of its state implementation plan for the 2008 ozone standard. However, in August 2022 EPA finalized a FIP to tighten the standards. PA DEP agreed to stay the state standard while all the parties consider the different standards. The FIP has been appealed by other parties and Talen has intervened in the appellate proceeding. In November 2022, Pennsylvania finalized some changes to its nitrogen oxide RACT standards (RACT 3) for all power generation facilities to address the 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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RGGI
In October 2019, the Pennsylvania Governor signed an Executive Action Order instructing the PA DEP to move forward with a rulemaking process that would facilitate the entry of the state into the RGGI program. In September 2021, the Independent Regulatory Review Commission provided the final required regulatory approval of PA DEP’s proposed final rulemaking. However, in October and December 2021, the Pennsylvania House and Senate passed resolutions disapproving the PA DEP’s proposed final rulemaking. In January 2022, the Governor of Pennsylvania vetoed the disapproval resolution. In April 2022, the final rule was published in the “Pennsylvania Code and Bulletin” and became effective, triggering Pennsylvania’s entry into the RGGI program. Compliance with the rule was meant to begin on July 1, 2022. However, certain third parties have filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania is currently stayed. The timing and potential impacts associated with these legal proceedings is uncertain and therefore, may change the state’s participation in the RGGI program, including the compliance timeline. 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 U.S. executive administration and a majority in the U.S. Congress have identified climate change policy as a priority that includes, but is not limited to, goals for greenhouse gas emissions reductions. Specifically, for the power sector, the EPA is addressing these initiatives through a new rulemaking after the D.C. Circuit Court vacated and remanded the EPA ACE Rule. Such rulemaking will account for the U.S. Supreme Court’s June 2022 ruling in West Virginia vs. U.S. EPA, which limits EPA’s authority to regulate greenhouse gas emissions by power generation facilities. EPA has indicated that it plans to propose its new GHG rules for the power sector in the first half of 2023, with a final rule in 2024. Additionally, in February 2021, the U.S. rejoined the Paris Agreement on Climate Change and in November 2021, the U.S. joined other nations and pledged to make further progress in limiting the rise in global average temperature. It is expected that new executive orders, regulatory actions and (or) legislation intended to meet those goals will be proposed and (or) promulgated.
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, negotiate with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiate with property owners and other third parties alleging impacts from our operations and undertake similar actions necessary to resolve environmental matters that arise in the course of normal operations. See Note 15 for information on accrued environmental costs.
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 associated with the Talen Formation 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
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upon the occurrence of certain events. At December 31, 2022 and December 31, 2021, the aggregate amount of surety bonds outstanding was $248 million and $237 million, including surety bonds posted on behalf of Talen Montana as discussed below. See Note 12 for information on a surety bond issued, included in the prior amount, on behalf of a related party at December 31, 2022.
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.
Talen Energy Supply has posted an aggregate $113 million of surety bonds to the MDEQ on behalf of Talen Montana’s proportional share of remediation and closure activities at both December 31, 2022 and December 31, 2021. Talen Montana has agreed to reimburse Talen Energy Supply 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 a result of such reviews as Colstrip’s coal ash impoundments remediation and closure activities are completed. MDEQ is still performing the 2022 annual review. Any additional posting is expected to be made in the second quarter of 2023.
Cumulus Digital Assurances. See Note 18 for information on an LC that Talen Energy Supply has provided to unaffiliated parties in the support of the Cumulus Digital TLF.
NorthEast Gas Gen Letters of Credit Assurance. At December 31, 2022 and December 31, 2021, pursuant to the terms of NorthEast Gas Gen’s chapter 11 plan of reorganization which is unrelated to the Restructuring. Talen Energy Supply has provided $11 million and $17 million of letters of credit to backstop long-term letters of credit, including a letter of credit related to a property tax arrangement for Athens. Talen’s backstop LCs will remain outstanding but such amounts may be reduced in accordance with arrangements agreed to in connection with NorthEast Gas Gen’s chapter 11 plan of reorganization (as amended) until the earlier of the date the underlying letters of credit are no longer outstanding or the NorthEast Gas Gen’s generation facilities are no longer owned by NorthEast Gas Gen’s lender. Talen will be reimbursed by reorganized NorthEast Gas Gen, subject to a cap, for fees incurred for these backstop LCs.
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. At December 31, 2022, the liability limit per incident is $13.7 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers and an industry retrospective assessment program.
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 $275 million per incident, payable at a maximum of $41 million per year.
Additionally, Susquehanna Nuclear purchases property insurance programs from NEIL, an industry mutual insurance company of which Susquehanna Nuclear is a member. At December 31, 2022, 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
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premium is $44 million at December 31, 2022. 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 coal-mine operator an amendment to one of its mine permits expanding the area authorized for mining. Environmental groups 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 coal-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 vacating the permit amendment pending resolution of the appeal. Merits briefing is complete and oral argument will be held in April 2023.
In May 2022, MDEQ issued a second permit amendment expanding the area authorized for mining by the coal-mine operator. The environmental groups initiated proceedings at the MBER and in Montana state district court challenging the second permit amendment. Both proceedings are in the early stages.
In September 2022, the Montana Federal District Court entered an order upholding challenges by certain environmental groups to a third permit amendment expanding the area authorized for mining by the coal-mine operator. The environmental groups 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 environmental groups moved to dismiss the appeal for lack of jurisdiction, and the federal defendants do not oppose the motion to dismiss. The motion to dismiss and merits briefs are not yet complete.
At this time, Talen cannot predict the outcome of this matter or its effect on Talen Montana’s operations, results of operations or liquidity.
Labor Union Agreement. At December 31, 2022, collective bargaining agreements to which Talen Energy Supply and (or) its subsidiaries are subject govern 41% of our workforce. In November 2022, the Company and IBEW Local 1600 in Pennsylvania, which represents 32% of our workforce agreed to a memorandum of agreement to extend the term of the existing collective bargaining agreement to August 2025. The memorandum of agreement was ratified by Local 1600 in December 2022. The collective bargaining agreement with IBEW Local 1638, which covers approximately 180 Talen Montana employees, is set to expire in August 2023.
17. Revolving Credit Facilities and Other Facilities
Restructuring
In May 2022, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. The Restructuring constituted an event of default and accelerated obligations owed under Talen’s recourse credit facilities outstanding prior to the Petition Date. The covenants and limitations contained in such credit agreements were not enforceable against the Debtors as a result of the Restructuring, absent reinstatement of the defaulted indebtedness. Therefore, certain key terms related to those affected credit agreements were not addressed in the below disclosures. See Note 3 for additional information on the Restructuring.
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Revolving Credit and Other Facilities
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||
| Expiration | Committed Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | |||||||||||||||||||||||||||||||||||
| Recourse | |||||||||||||||||||||||||||||||||||||||||
| DIP RCF | November 2023 | $ | 300 | $ | — | $ | 33 | $ | 267 | $ | — | $ | — | ||||||||||||||||||||||||||||
| DIP LCF | November 2023 | 434 | — | 434 | — | — | — | ||||||||||||||||||||||||||||||||||
Prepetition CAF (a) | September 2024 | 848 | 848 | — | — | 848 | — | ||||||||||||||||||||||||||||||||||
| Prepetition RCF | March 2024 | — | — | — | — | — | 439 | ||||||||||||||||||||||||||||||||||
| Prepetition LCF-1 | June 2023 | — | — | — | — | — | 10 | ||||||||||||||||||||||||||||||||||
| Prepetition LCF-2 | December 2023 | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||
| Non-Recourse | |||||||||||||||||||||||||||||||||||||||||
| LMBE-MC RCF | December 2023 | 25 | — | 12 | 13 | — | 15 | ||||||||||||||||||||||||||||||||||
| Total | $ | 1,607 | $ | 848 | $ | 479 | $ | 280 | $ | 848 | $ | 464 | |||||||||||||||||||||||||||||
__________________
(a)The weighted average interest rate was 12.12% and 9.00% at December 31, 2022 and December 31, 2021.
Outstanding direct cash borrowings under the: (i) DIP RCF, (ii) Prepetition CAF, and (iii) LMBE-MC RCF are each presented as “Revolving credit facilities” on the Consolidated Balance Sheets. See Note 18 for information on long-term debt and interest expense and other finance charges.
LC issuances were not permitted under the Prepetition LCF-1 and LCF-2 due to the Restructuring.
At December 31, 2022: (i) Talen Energy Supply was not in default under the DIP Facilities, and LMBE-MC was not in default under the LMBE-MC RCF; and (ii) certain Debtors were in default of the Prepetition Indebtedness. See Note 3 for information on the Restructuring.
Talen DIP Credit Agreements. In May 2022, Talen Energy Supply entered into the DIP Facilities. The DIP Facilities consisted of the DIP RCF, DIP TLB and DIP LCF. The DIP TLB provided Talen with a $1 billion term loan excluding lender premiums and fees, and the DIP RCF provided access to up to $300 million of revolving loan commitments, that could be utilized to issue new letters of credit. The DIP LCF provided Talen with approximately $458 million of continuing letter of credit capacity permitting the continuation and further renewal of letters of credit outstanding under the Prepetition RCF as of the Petition Date. In June 2022, the Bankruptcy Court entered the final order with respect to the DIP Facilities, which, among other things, provided for payments of interest on prepetition secured indebtedness, subject to, among other terms and conditions, minimum liquidity requirements.
Borrowings under the DIP TLB and DIP RCF were available to be used to: (i) pay fees, costs and expenses required to be paid in connection with the DIP Facilities and the Restructuring; (ii) pay for working capital and other general corporate purposes of the Debtors; and (iii) to pay any obligations arising from or related to the “Carve Out” provisions in the Restructuring, in each case in accordance with the cash flow forecast defined in the agreement governing the DIP TLB and DIP RCF, and for amounts attributable to decarbonization capital expenditures and pension contributions, in accordance with the budget for the Restructuring.
The DIP Facilities had a maturity of November 2023, subject to: (i) a springing maturity in the event certain material events occur during the pendency of the Restructuring; and (ii) an automatic extension of six months solely to the extent necessary to obtain any applicable regulatory approvals necessary to consummate a plan of reorganization that has been approved by the Bankruptcy Court.
Borrowings under the DIP Facilities bore interest, at the borrowers’ option, at either a base rate (subject to a 1.75% floor), defined as a prime rate (subject to certain adjustments), or a SOFR-based rate (subject to a 0.75% floor), plus an applicable margin, with associated interest paid at least quarterly (or, if earlier, at the end of any SOFR period less than 90 days). The applicable margin on base rate loans was 3.75% and on SOFR-based loans was 4.75%. The lenders were paid an arranger premium and an upfront premium equal to 1.25% of the amount of each
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draw of term loans under the DIP TLB. In addition, the revolving commitments under the DIP RCF bore an undrawn commitment fee of 0.50% per annum on available but unused revolving facility capacity. Talen paid a fee with respect any letters of credit issued under the DIP RCF of 4.5% of the daily stated amount of each letter of credit.
Borrowings, if any, under the DIP LCF bore interest, at the borrowers’ option, at either a base rate (subject to a 1.75% floor), defined as a prime rate (subject to certain adjustments), or a SOFR-based rate (subject to a 0.75% floor), plus an applicable margin, with associated interest paid at least quarterly (or, if earlier, at the end of any SOFR period less than 90 days). The applicable margin on base rate loans was 7.0% and on SOFR-based loans was 8.0%. Talen Energy Supply paid a fee with respect any letters of credit issued under the DIP LCF of 4.5% of the daily stated amount of each letter of credit.
Borrowings under the DIP Facilities were subject to mandatory prepayment requirements upon the receipt of proceeds from certain non-permitted issuances of indebtedness, asset sales and condemnation or recovery events, subject to customary reinvestment rights.
Certain voluntary prepayments of the DIP TLB were subject to a 1.00% premium for the first six months.
Amounts borrowed under the DIP RCF could be re-drawn, subject to compliance with certain conditions.
The DIP Facilities contained customary negative covenants, including but not limited to, certain limitations on incurrence of liens and additional indebtedness, payment of dividends asset sales, investments and transactions with affiliates, in each case subject to thresholds, carve outs and baskets. The DIP Facilities also required that the Debtors not permit liquidity, defined as unrestricted cash and cash equivalents and availability under the Debtors’ revolving credit facility, to be less than $150,000,000 for any period of three consecutive days.
The DIP Facilities also contained negative covenants with respect to the Debtors’ ability to enter into hedging agreements. These restrictions included limitations, subject to conditions and exceptions on the Debtors’ ability to incur:
•indebtedness in the form of Bilateral Hedges (as defined in the agreements governing the DIP Facilities) and (or) FCM Hedges (as defined in the agreements governing the DIP Facilities); and
•liens on cash collateral and other credit support to secure obligations under Bilateral Hedges and (or) constituting initial and (or) variation margin to secure FCM Hedges.
Hedging agreements were also generally subject to a monthly cap on net hedging obligations and a limit on In-The-Money Generation (as defined in the agreements governing the DIP Facilities) in any particular month in the next 24 months after the date of incurrence (which time period was extended to 36 months effective November 1, 2022 pursuant to an amendment to the DIP Facilities executed in October 2022).
If an event of default had occurred, the lenders under the DIP Facilities would have been entitled to take various actions, including the acceleration of amounts due under the DIP Facilities, subject, if applicable, to the terms of the intercreditor agreement governing the DIP Facilities and other secured debt obligations.
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 the DIP Secured ISDAs, under which Talen Energy Supply and the Debtors provided the counterparty with superpriority liens (which rank pari passu with the liens securing the obligations under the DIP Facilities) against certain assets in lieu of posting collateral comprised of cash equivalents or LCs. The secured obligations under the DIP Secured ISDAs at December 31, 2022 were $77 million.
Prepetition ISDAs. Talen Energy Marketing was party to agreements based on a form of master agreement published by the International Swaps and Derivatives Association, Inc. (the “Prepetition ISDAs”), under which Talen Energy Supply and the Prepetition Guarantors provided the counterparty with a lien against certain assets in lieu of posting collateral comprised of cash equivalents or LCs. Although the obligations under the Prepetition ISDAs were still secured by the lien, the lien was subordinate to the liens securing the obligations under the DIP
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Facilities and the DIP Secured ISDAs. The secured obligations under the Prepetition ISDAs at December 31, 2022 and December 31, 2021 were $1 million and $195 million.
LMBE-MC RCF. The Restructuring was not an event of default under the LMBE-MC RCF. The LMBE-MC RCF allowed for, at LMBE-MC’s discretion, direct cash borrowings and letter of credit issuances up to an aggregate facility capacity of $25 million through its expiry in December 2023. Borrowings bore interest, at LMBE-MC’s option, at either: (i) a base rate, defined as a prime rate (subject to certain adjustments under the LMBE-MC RCF); or (ii) (a) prior to a January 2023 amendment to the LMBE-MC Credit Agreement that transitions the LIBOR-based agreement to a SOFR-based agreement, a LIBOR-based rate, or (b) following such amendment, a SOFR-based rate, in each case plus an applicable margin. Associated interest was paid at least quarterly. The applicable margin was (i) 3.00% on base rate loans; (ii) 4.00% on LIBOR-based loans; and (iii) 4.10%, 4.15%, and 4.25% on SOFR-based loans for one-month, three-month, and six-month tenors, respectively. Any current LIBOR-based borrowings continued based on a SOFR rate (or converted to base rate borrowings) once the interest period for such borrowing expired on March 31, 2023. In addition to interest, the lenders charged commitment fees on available, but unused facility capacity and customary letter of credit fees.
The LMBE-MC RCF was subject to customary negative covenants, including, but not limited to, certain limitations on incurrence of liens and additional indebtedness, payment of dividends and asset sales. The LMBE-MC RCF also contained customary representations and warranties, affirmative covenants and events of default. The LMBE-MC RCF required LMBE-MC to maintain a debt service coverage ratio of no less than 1.10 to 1.00 as of the last day of any fiscal quarter.
The LMBE-MC RCF commitments could be terminated upon the occurrence of an event of default. If an event of default occurred, the lenders under the LMBE-MC RCF would be entitled to take various actions, including the acceleration of amounts due under the LMBE-MC RCF.
Security Interests of DIP Facilities, Revolving Credit Facilities and Secured Hedging Obligations
DIP Facilities. The obligations under the DIP Facilities, which included LCs formerly issued under the Prepetition RCF and continued under the DIP LCF, were secured by superpriority liens and security interests in substantially all the assets of Talen Energy Supply and the Debtors and guaranteed by the Debtors. These security interests were equal and ratable with the security interests securing the DIP Secured ISDAs and senior to the liens securing the Prepetition CAF, Prepetition TLB, Prepetition Secured Notes and Prepetition ISDAs.
DIP Secured ISDAs. Obligations under the DIP Secured ISDAs were afforded superpriority administrative claim status and were secured by security interests in substantially all the assets of Talen Energy Supply and the Debtors. These security interests were equal and ratable with the security interests securing the DIP Facilities and senior to the liens securing the Prepetition CAF, Prepetition TLB, Prepetition Secured Notes and Prepetition ISDAs.
Recourse Revolving Credit Facilities. Obligations under the Prepetition CAF were guaranteed by Talen Energy Supply and the Prepetition Guarantors and secured by liens and security interests in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors. These security interests were junior to security interests securing the DIP Facilities and the DIP Secured ISDAs and otherwise were equal and ratable with the security interests securing the Prepetition TLB, Prepetition Secured Notes and Prepetition ISDAs.
In January 2022, in connection with the Prepetition CAF and certain waivers and amendments under the Prepetition RCF, Talen Energy Supply caused certain of its wholly owned subsidiaries that were not already Prepetition Guarantors to: (i) guarantee the obligations under the Prepetition CAF, the Prepetition RCF, the Prepetition TLB, the Prepetition Secured Notes, the Prepetition ISDAs, the Prepetition Inventory Repurchase Obligations and the Prepetition LCF-1 and the Prepetition LCF-2 (collectively, the “Prepetition Unsecured LCFs”); and (ii) grant liens and security interests in substantially all of their respective assets to secure the obligations under the foregoing (other than the Prepetition Unsecured LCFs).
Non-recourse Revolving Credit Facilities. Obligations under the LMBE-MC Credit Agreement, which included the LMBE-MC RCF, were secured by first-priority liens and security interests in substantially all the assets of LMBE-MC Holdco and each of its subsidiaries.
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Prepetition ISDAs. Obligations under the Prepetition ISDAs were secured by liens and security interests in substantially all the assets of Talen Energy Supply and the Prepetition Guarantors. These security interests were junior to security interests securing the DIP Facilities and the DIP Secured ISDAs and otherwise were equal and ratable with the security interests securing the Prepetition CAF, Prepetition TLB, Prepetition Secured Notes.
See Note 18 for information on guarantees and cross-default provisions related to Talen’s indebtedness.
18. Long-term Debt
Restructuring
In May 2022, the Debtors filed voluntary petitions seeking relief under Chapter 11 of the Bankruptcy Code. The Restructuring constituted an event of default and accelerated obligations owed under Talen’s long-term recourse indebtedness outstanding prior to the Petition Date, other than the Talen 2038 PEDFA Series 2009B and Talen 2037 PEDFA Series 2009C bonds. The covenants and limitations associated with the defaulted indebtedness were not enforceable against the Debtors as a result of the Restructuring, absent reinstatement of the defaulted indebtedness. Therefore, certain key terms, such as principal repayments and covenant terms, of defaulted indebtedness were not addressed in the below disclosures. See Note 3 for information on the Restructuring and execution of the DIP Facilities and Note 17 for more information on the terms of the DIP Facilities.
Long-term Debt
Interest Rate (a) | December 31, 2022 | December 31, 2021 | |||||||||||||||
| DIP TLB | |||||||||||||||||
| 2023 DIP TLB | 9.06 | % | $ | 1,000 | $ | — | |||||||||||
| Prepetition TLB | |||||||||||||||||
| 2026 Prepetition TLB | 8.13 | % | 427 | 427 | |||||||||||||
| Prepetition Secured Notes | |||||||||||||||||
| 7.25% Senior Secured Notes due 2027 | 7.25 | % | 750 | 750 | |||||||||||||
| 6.625% Senior Secured Notes due 2028 | 6.63 | % | 470 | 470 | |||||||||||||
| 7.625% Senior Secured Notes due 2028 | 7.63 | % | 400 | 400 | |||||||||||||
Prepetition Unsecured Notes (b) | |||||||||||||||||
| 9.5% Senior Notes due July 2022 | 9.50 | % | 17 | 17 | |||||||||||||
| 6.5% Senior Notes due September 2024 | 6.50 | % | 24 | 24 | |||||||||||||
| 6.5% Senior Notes due June 2025 | 6.50 | % | 543 | 543 | |||||||||||||
| 10.5% Senior Notes due January 2026 | 10.50 | % | 607 | 607 | |||||||||||||
| 7.0% Senior Notes due October 2027 | 7.00 | % | 20 | 20 | |||||||||||||
| 6.0% Senior Notes due December 2036 | 6.00 | % | 119 | 119 | |||||||||||||
PEDFA Bonds (b) | |||||||||||||||||
| 2038 PEDFA Series 2009A | 6.40 | % | 100 | 100 | |||||||||||||
| 2038 PEDFA Series 2009B | 4.81 | % | 49 | 50 | |||||||||||||
| 2037 PEDFA Series 2009C | 4.81 | % | 79 | 81 | |||||||||||||
| Total recourse principal | $ | 4,605 | $ | 3,608 | |||||||||||||
| Non-recourse Senior Secured Term Loan | |||||||||||||||||
| LMBE-MC TLB | 8.73 | % | 301 | 353 | |||||||||||||
| Total non-recourse principal | 301 | 353 | |||||||||||||||
| Limited-recourse Senior Secured Term Loan | |||||||||||||||||
| Cumulus Digital TLF, including PIK | 12.50 | % | 185 | — | |||||||||||||
| Total limited-recourse principal | 185 | — | |||||||||||||||
F-126
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
| Total principal | 5,091 | 3,961 | |||||||||||||||
Unamortized deferred finance costs and original issuance discounts, recourse (c) (d) | (25) | (61) | |||||||||||||||
| Unamortized deferred finance costs and original issuance discounts, non-recourse | (4) | (6) | |||||||||||||||
| Total carrying value | 5,062 | 3,894 | |||||||||||||||
Less: recourse long-term debt, due within one year (b) | 1,000 | 150 | |||||||||||||||
| Less: non-recourse long-term debt, due within one year | 10 | 9 | |||||||||||||||
Less: amounts presented as “Liabilities subject to compromise” (b) | 1,558 | — | |||||||||||||||
| Long-term debt | $ | 2,494 | $ | 3,735 | |||||||||||||
__________________
(a)Computed interest rate at December 31, 2022.
(b)At December 31, 2022, amounts or a portion of such are presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet. See Note 3 for additional information.
(c)The 2021 amount includes previously recognized fair value adjustments on certain exchanges of indebtedness.
(d)Previously unamortized fees related to unsecured indebtedness were written-off to “Reorganization income (expense), net” presented on the Consolidated Statements of Operations.
See Note 17 for information on revolving credit facilities, LC issuances and facilities and the Prepetition ISDAs.
At December 31, 2022: (i) Talen Energy Supply was not in default under the DIP TLB, LMBE-MC was not in default under the LMBE-MC TLB and Cumulus Digital was not in default under the Cumulus Digital TLF, and (ii) certain Debtors were in default of the Prepetition Indebtedness. See “Restructuring” above for information on the impact of the Restructuring on Talen’s recourse long-term debt.
The aggregate long-term debt maturities, including quarterly amortization and early redemption provisions, at December 31, 2022 were:
| 2023 | 2024 | 2025 | 2026 | 2027 | Thereafter | Other (a) | Total | ||||||||||||||||||||||||||||||||||||||||
| Recourse | $ | 1,000 | $ | — | $ | — | $ | 427 | $ | 750 | $ | 870 | $ | 1,558 | $ | 4,605 | |||||||||||||||||||||||||||||||
| Non-recourse | 10 | 5 | 286 | — | — | — | — | 301 | |||||||||||||||||||||||||||||||||||||||
| Limited-recourse | — | — | — | — | 185 | — | — | 185 | |||||||||||||||||||||||||||||||||||||||
| Total maturities | $ | 1,010 | $ | 5 | $ | 286 | $ | 427 | $ | 935 | $ | 870 | $ | 1,558 | $ | 5,091 | |||||||||||||||||||||||||||||||
__________________
(a)Indebtedness presented as “Liabilities subject to compromise” on the consolidated balance sheet.
Under the terms of the Plan of Reorganization related to the Restructuring, the $1.4 billion of recourse unsecured debt and the Talen 2038 PEDFA Series 2009A, presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet at December 31, 2022, were converted to TEC common stock upon Emergence. The Talen 2038 PEDFA Series 2009B and Talen 2037 PEDFA Series 2009C, presented as “Liabilities subject to compromise” at December 31, 2022, continued in accordance with the agreed upon terms. See Note 3 for additional information on the Restructuring.
F-127
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The components of “Interest expense and other finance charges” presented on the Consolidated Statements of Operations for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Recourse Interest Expense | |||||||||||||||||
| Prepetition RCF and DIP LCF | $ | 21 | $ | 15 | $ | 5 | |||||||||||
| DIP TLB | 46 | — | — | ||||||||||||||
| Prepetition CAF | 86 | 4 | — | ||||||||||||||
| Prepetition TLB and Notes | 140 | 132 | 124 | ||||||||||||||
| Prepetition Unsecured Notes | 40 | 116 | 116 | ||||||||||||||
| PEDFA Bonds | 2 | 7 | 11 | ||||||||||||||
Amortization (a) | 24 | 14 | 13 | ||||||||||||||
| Interest rate derivatives (gains) losses, net | (16) | (8) | 29 | ||||||||||||||
| Capitalized interest, other | (6) | — | (2) | ||||||||||||||
| Recourse interest expense | 337 | 280 | 296 | ||||||||||||||
| Prepetition Inventory Repurchase Obligations | 6 | 10 | 9 | ||||||||||||||
| Prepetition RCF and DIP RCF commitment fees | 1 | 1 | 3 | ||||||||||||||
Amortization (a) | 4 | 16 | 3 | ||||||||||||||
| Other finance charges | 2 | 1 | 1 | ||||||||||||||
| Total recourse interest expense and other finance charges | 350 | 308 | 312 | ||||||||||||||
| Non-recourse Interest Expense | |||||||||||||||||
| LMBE-MC RCF and LMBE-MC TLB | 21 | 19 | 22 | ||||||||||||||
| NGG RCF, NGG 2023 TLB, NGG 2023 TLC and NGG PIK interest | — | — | 12 | ||||||||||||||
Amortization (a) | 1 | 2 | 2 | ||||||||||||||
| Interest rate derivatives (gains) losses, net | (14) | (4) | 16 | ||||||||||||||
| Non-recourse capitalized interest, other | — | — | (1) | ||||||||||||||
| Total non-recourse interest expense and other finance charges | 8 | 17 | 51 | ||||||||||||||
| Limited-recourse Interest Expense | |||||||||||||||||
| Cumulus Digital TLF, including PIK interest | 6 | — | — | ||||||||||||||
| Capitalized interest, other | (5) | — | — | ||||||||||||||
| Total limited-recourse interest expense and other finance charges | 1 | — | — | ||||||||||||||
| Interest expense and other finance charges | $ | 359 | $ | 325 | $ | 363 | |||||||||||
__________________
(a)Non-cash amortization of: (i) original issuance discount; (ii) deferred finance costs; and (iii) previously recognized fair value adjustments on certain exchanges of indebtedness, as applicable.
Under GAAP, as a result of the Restructuring, Talen no longer accrued interest on certain outstanding debt, including the Prepetition Unsecured Notes and the PEDFA Bonds. For the year ended December 31, 2022, $77 million of contractual interest expense was not presented on the Consolidated Statement of Operations. Talen continued to reimburse the direct-pay LC provider for interest paid on the Talen 2038 PEDFA Series 2009B and Talen 2037 PEDFA Series 2009C bonds, as permitted by the final Bankruptcy Court order approving the DIP Facilities. The interest payments are treated as a reduction to principal.
F-128
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The components of debt restructuring gain (loss), net presented on the Consolidated Statements of Operations within “Other non-operating income (expense), net” for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Prepetition RCF extinguishment | $ | — | $ | (10) | $ | (1) | |||||||||||
| Prepetition TLB extinguishment | — | — | (2) | ||||||||||||||
| Prepetition CAF prepayment premiums | (6) | — | — | ||||||||||||||
| Other | — | (1) | — | ||||||||||||||
| Debt restructuring gain (loss), net | $ | (6) | $ | (11) | $ | (3) | |||||||||||
Long-Term Debt Transactions
2022 Transactions.
DIP TLB. In May 2022, Talen Energy Supply executed the $1 billion 2023 DIP TLB 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, Talen Energy Supply consolidated Cumulus Digital Holdings for financial reporting purposes and accordingly, presented the Cumulus Digital TLF in the Talen Energy Supply financial statements as of December 31, 2022. The settlement of all claims, interests and controversies among the parties to that certain Cumulus Term Sheet dated as of August 29, 2022, by and among Talen, Talen Energy Corporation, Cumulus Digital, Orion Energy Partners Investment Agent, LLC, and Riverstone, and certain of each of their affiliates (the “Cumulus Term Sheet”) the terms of which are set out in the Cumulus Term Sheet (the “Cumulus Settlement”), also amended certain aspects of the Cumulus Digital Credit Agreement as further described below. See Note 12 for additional information on the Cumulus Digital Equity Conversion and the other Cumulus Settlement transactions.
2021 Transactions.
Talen 2021 Secured Notes Repayment. In December 2021, Talen Energy Supply repaid an aggregate $114 million principal amount upon maturity.
Talen PEDFA Bond Remarketing. In February 2021, Talen Energy Supply completed the remarketing of the Talen 2028 PEDFA series 2009B bonds and the Talen 2037 PEDFA Series 2009C bonds, and issued $131 million principal amount of remarketed bonds and received proceeds of $128 million, net of fees, which are presented as new indebtedness on the Consolidated Balance Sheet and Consolidated Statements of Cash Flows as of and for the year ended December 31, 2021. In connection with this transaction, Talen Energy Supply issued backstop LCs in the amount of principal outstanding of the remarketed bonds plus an interest component. The Company continued to pay interest as due on the remarketed bonds during the Restructuring. See “Recourse Long-term Debt” below for additional information.
Recourse Long-Term Debt
Prepetition TLB. Interest for borrowings under the Prepetition TLB was variable and was equal to a LIBOR-based rate plus 3.75% (with a 0.00% LIBOR floor). Interest under the Prepetition TLB accrued and, prior to the Restructuring, was payable monthly. Pursuant to a June 2022 order of the Bankruptcy Court, Talen Energy Supply was permitted, and in some circumstances required, to pay interest under the Prepetition TLB, subject to certain minimum liquidity requirements and other conditions.
Prepetition Secured Notes. Any principal payments and redeemable provision terms were not in effect due to the Restructuring. Interest on borrowings under the Prepetition Secured Notes accrued at fixed-rates and, prior to the Restructuring, was payable semi-annually. Pursuant to a June 2022 order of the Bankruptcy Court, Talen Energy Supply was permitted, and in some circumstances were required, to pay interest under the Prepetition Secured Notes, subject to certain minimum liquidity requirements.
F-129
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Prepetition Unsecured Notes. Any principal payments and redeemable provision terms were not in effect due to the Restructuring. Interest on borrowings under the Prepetition Unsecured Notes accrued at fixed rates and, prior to the Restructuring, was payable semi-annually. As a result of the Restructuring, Talen is currently not accruing interest on these notes.
As a result of the Restructuring, these notes have been presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet.
PEDFA Bonds. Each series of PEDFA Bonds was issued by the PEDFA on behalf of Talen Energy Supply. Talen Energy Supply 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 Talen Energy Supply corresponding to each series of PEDFA Bonds contains principal, interest and prepayment provisions of the respective series.
The Talen 2038 PEDFA Series 2009A: (i) are not subject to mandatory tender prior to their stated maturity date but may be redeemed at the option of Talen Energy Supply beginning in September 2025; and (ii) accrue fixed rate interest which is payable semi-annually, as provided in the Series A loan agreement.
Talen Energy Supply completed the remarketing of the Talen 2038 PEDFA Series 2009B and the Talen 2037 PEDFA Series 2009C in February 2021. The Talen 2038 PEDFA Series 2009B and the Talen 2037 PEDFA Series 2009C accrue interest at a variable rate in accordance with the provisions of the trust indentures which is payable monthly. Obligations under the Talen 2038 PEDFA Series 2009B and the Talen 2037 PEDFA Series 2009C are supported by two irrevocable, direct-pay letters of credit, 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. Talen Energy Supply’s obligation to reimburse the third-party lender for payments made under each irrevocable, direct-pay letter of credit is in turn supported by a corresponding backstop letter of credit issued in favor of such lender under the Prepetition RCF.
The Talen 2038 PEDFA Series 2009B and the Talen 2037 PEDFA Series 2009C are: (i) subject to mandatory purchase by Talen Energy Supply at the option of each holder with at least a seven day advance notice, but may be redeemed at the option of Talen Energy Supply at any time; (ii) subject to mandatory tender and optional remarketing upon a conversion to an interest rate other than the daily rate as defined in the loan agreement or upon the cancellation, termination, expiration or substitution of the irrevocable, direct-pay letter of credit corresponding to the applicable PEDFA series; and (iii) subject to mandatory tender upon an event of default under the reimbursement agreement pursuant to which the irrevocable, direct-pay letter of credit for the applicable series was issued.
Each series of the PEDFA Bonds is subject to customary affirmative and negative covenants appropriate for such indebtedness. In addition, the Talen 2038 PEDFA Series 2009A includes certain limitations on incurrence of additional liens and asset sales. The indentures governing the PEDFA Bonds do not limit Talen Energy Supply’s ability to incur additional unsecured indebtedness. Each series of the PEDFA Bonds also contains customary events of default. If an event of default occurs, the lenders under each series of the 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 the Talen 2038 PEDFA Series 2009A bonds but was not an event of default under the Talen 2038 PEDFA Series 2009B and Talen 2037 PEDFA Series 2009C bonds. The Talen 2038 PEDFA Series 2009B and Talen 2037 PEDFA Series 2009C bonds continue to be supported by the letters of credit described above and Talen Energy Supply continues to perform its associated reimbursement obligations.
As a result of the Restructuring, these notes have been presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet.
Non-Recourse Senior Secured Long-Term Debt
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 TLB.
F-130
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
LMBE-MC TLB. The LMBE-MC TLB required quarterly amortization payments which equated on a quarterly basis to 0.25% of the total original principal amount, with the remaining principal balance due at maturity in December 2025. Additionally, the LMBE-MC TLB includes a quarterly cash sweep equal to the greater of: (i) 50% of excess cash flow of LMBE-MC; or (ii) up to 100% of excess cash flow of LMBE-MC to the extent required to reach target debt balances as defined under the LMBE-MC Credit Agreement. The LMBE-MC TLB permits quarterly cash distributions to Talen Energy Supply after meeting debt service and other cash flow requirements. As of the final 2022 quarterly cash sweep, the amount outstanding on the LMBC-MC TLB exceeds the target debt balance, therefore, cash distributions cannot occur until the balance is at or below the target in future quarters. Interest on borrowings under the LMBE-MC TLB is currently variable and is equal to a LIBOR-based rate plus 4.00%. As discussed in Note 17, following amendments to the LMBE-MC Credit Agreement, once the current interest period on these LIBOR-based borrowings expires on March 31, 2023, such borrowings can only be continued based on the applicable SOFR rate (or converted to base rate borrowings). The applicable margin is (i) 3.00% on base rate loans; and (ii) 4.10%, 4.15%, and 4.25% on SOFR-based loans for one-month, three-month, and six-month tenors, respectively.
The LMBE-MC TLB contains the same affirmative covenants, negative covenants and events of default as the LMBE-MC RCF. If an event of default occurs, the lenders under the LMBE-MC Credit Agreement, subject to certain limitations, are entitled to take various actions, including accelerating amounts due under such obligations. The LMBE-MC TLB requires LMBE-MC to maintain a debt service coverage ratio of no less than 1.10 to 1.00 as of the last day of any fiscal quarter.
Limited-Recourse Senior Secured Long-Term Debt
Cumulus Digital 2027 Senior Secured Term Loan. In September 2021, Cumulus Digital executed the Cumulus Digital Credit Agreement, 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 the Cumulus Settlement, Cumulus Digital borrowed the remaining available principal amount in the third quarter 2022. As a result, at December 31, 2022, the outstanding principal, including capitalized and accrued PIK interest was $185 million.
Interest on outstanding borrowings is 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 the Cumulus Settlement transactions, the Cumulus Digital Credit Agreement was amended to provide that all interest accruing thereunder from July 1, 2022 through June 30, 2023 will be capitalized as additional principal, and thereafter will be paid in cash.
The Cumulus Digital Credit Agreement contains customary representations and warranties, affirmative covenants, negative covenants, and events of default. Notable covenants include limitations on incurrence of liens and additional indebtedness, payment of dividends and asset sales. The agreement also includes a requirement that Cumulus Digital procure equity funding from May 2023 through June 2023 for Cumulus Data to complete construction of the first data center shell and related infrastructure.
The Cumulus Digital Credit Agreement contains customary events of default, including nonpayment of principal or interest when due, breach of covenants in Cumulus Digital TLF documents, and the bankruptcy of Cumulus Digital Holdings or any of its subsidiaries. It is also an event of default if Talen Energy Corporation files for bankruptcy while the Talen Energy Corporation guarantee described below remains in effect. This event of default was waived for purposes of Talen Energy Corporation’s voluntary petition for relief under Chapter 11 of the Bankruptcy Code in December 2022, provided that the guaranty is assumed by Talen Energy Corporation in the Restructuring as contemplated in the Plan of Reorganization. See Note 3 for more information on Talen Energy Corporation becoming a Debtor in the Restructuring.
F-131
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Security Interests of Long-term Debt
Recourse Debt. The obligations under the Prepetition TLB and Prepetition Secured Notes are secured by liens and security interests in substantially all of the assets of Talen Energy Supply and the Prepetition Guarantors. These security interests are equal and ratable with the security interests securing the Prepetition CAF, and Prepetition ISDAs, but are subordinated to the liens securing the DIP Facilities and the DIP Secured ISDAs.
Non-recourse Debt.
LMBE-MC Credit Agreement. Obligations under the LMBE-MC Credit Agreement, which includes the LMBE-MC TLB, are secured by first-priority liens and security interests in substantially all the assets of LMBE-MC Holdco and each of its subsidiaries. Such assets consist primarily of the property, plant and equipment of the Lower Mt. Bethel and Martins Creek generation facilities, materials and supplies, and restricted cash with an aggregate net book value of approximately $529 million at December 31, 2022.
LMBE-MC is the borrower under the LMBE-MC Credit Agreement, which includes the LMBE-MC RCF and the LMBE-MC TLB. Obligations under the LMBE-MC Credit Agreement are guaranteed by LMBE-MC Holdco and LMBE-MC’s subsidiaries. The maximum amount of potential future payments by the guarantors is equal to the maximum amount of outstanding obligations under the LMBE-MC Credit Agreement and may include unpaid interest, premiums, penalties, and (or) other fees and expenses. Talen Energy Supply and its subsidiaries (other than LMBE-MC Holdco and its subsidiaries) do not guarantee the obligations under the LMBE-MC Credit Agreement.
Limited-recourse Debt.
Cumulus Digital TLF. Obligations under the Cumulus Digital Credit Agreement are 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.
Guarantees and Cross-Defaults of Long-term Debt, Revolving Credit Facilities and Prepetition ISDAs
The Debtors guarantee the obligations of: (i) Talen Energy Supply under the DIP Facilities; and (ii) Talen Energy Marketing under the DIP Secured ISDAs. The maximum amount of potential future payments by the Postpetition 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 if not cured or waived under the DIP Facilities and certain DIP Secured ISDAs may result in a cross acceleration of amounts due and (or) cross termination across all these agreements.
The Prepetition Guarantors guarantee the obligations of: (i) Talen Energy Supply under the Prepetition RCF, Prepetition Unsecured LCFs, Prepetition TLB, Prepetition Secured Notes, Prepetition Unsecured Notes and PEDFA Bonds; (ii) Talen Energy Marketing, under the Prepetition ISDAs; and (iii) Talen Energy Marketing and Susquehanna Nuclear under the Prepetition CAF. The maximum amount of potential future payments by the Prepetition 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 if not cured or waived under the Prepetition RCF, Prepetition CAF, Prepetition TLB, Prepetition Secured Notes, Prepetition Unsecured LCF, Prepetition Unsecured Notes, and certain Prepetition ISDAs may result in a cross acceleration of amounts due and (or) cross termination across all these agreements.
The Prepetition Unsecured Notes, PEDFA Bonds, and Prepetition Unsecured LCFs are senior unsecured obligations of Talen Energy Supply that are effectively subordinated to the secured obligations of Talen Energy Supply, including the Prepetition RCF, Prepetition CAF, Prepetition TLB, Prepetition Secured Notes, and Prepetition ISDAs.
The guarantees under the Prepetition Unsecured Notes, PEDFA Bonds, and Prepetition Unsecured LCFs are the general unsecured obligations of the Prepetition Guarantors, guaranteeing such indebtedness, rank equally with all of such Prepetition Guarantors’ other senior unsecured indebtedness, and are effectively subordinated to the secured
F-132
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
obligations of the Prepetition Guarantors, including the Prepetition RCF, Prepetition CAF, Prepetition TLB, Prepetition Secured Notes, and Prepetition ISDAs.
Guarantees on Cumulus Digital TLF
All obligations under the Cumulus Digital Credit Agreement are guaranteed by Cumulus Digital Holdings and each of Cumulus Digital’s subsidiaries (other than Nautilus). The maximum amount of potential future payments by the guarantors is equal to the maximum amount of outstanding obligations under the Cumulus Digital Credit Agreement and may include unpaid interest, premiums, penalties, and (or) other fees and expenses.
Additionally, Talen Energy Corporation has 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 will terminate if the principal amount of loans outstanding is reduced to $50 million or less.
Letters of Credit. At December 31, 2022, under the terms of the Cumulus Digital Credit Agreement, Talen Energy Supply has provided $50 million in LCs to Orion to support certain of Cumulus Digital’s obligations under the Cumulus Digital TLF. The LCs can be drawn upon, among other events: (i) the acceleration of the Cumulus Digital loan due to an event of default; or (ii) a bankruptcy of Cumulus Digital. The amount of the LCs will be decreased from time to time based on the outstanding principal balance of the Cumulus Digital debt. In the event that the letters of credit are drawn, Cumulus Digital Holdings has agreed to issue additional common equity to Talen Energy Supply to reimburse it for the amount drawn. Cumulus Digital has agreed to reimburse Talen Energy Supply for fees associated with the LCs with payment of such amounts 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. Talen Energy Supply will have the option to receive payment for the deferred fees in cash payments ratably over the next succeeding 24 months or in additional common units of Cumulus Digital Holdings, subject to certain caps under the amended Cumulus Digital COSA. The LC reimbursement agreement was assumed by Talen Energy Supply upon the Bankruptcy Court’s approval of the Cumulus Settlement transactions. For the year ended December 31, 2022, Talen Energy Supply recognized $2 million of income within “Other non-operating income (expense), net” presented on the Consolidated Statements of Operations for this reimbursement of the LC costs. As a result of the September 2022 consolidation of Cumulus Digital Holdings, going forward, this income will no longer be recognized because it will eliminate in consolidation. See Note 12 for information on the Cumulus Digital COSA.
19. NorthEast Gas Gen
NorthEast Gas Gen Deconsolidation
VIE Reconsideration and Deconsolidation. In March 2020, NorthEast Gas Gen defaulted under the NGG First Lien Credit Agreement from the failure to pay a required quarterly cash interest payment due on March 31, 2020 and to deliver a compliance certificate by March 15, 2020. This triggered a cross default pursuant to the NGG Affiliate Second Lien Credit Agreement under which Talen Energy Supply was the lender. In April 2020, all interested parties consummated a series of forbearance arrangements that contained conditions agreed to with the unaffiliated lender that substantially limited our ability to make certain financial decisions for NorthEast Gas Gen in the ordinary course of business. These conditions triggered a VIE reconsideration assessment of Talen’s investment in NorthEast Gas Gen. As a result, we determined Talen did not have a controlling financial interest in NorthEast Gas Gen given the limiting effects of the forbearance conditions and that NorthEast Gas Gen had insufficient equity to finance its activities.
Accordingly, in April 2020, Talen deconsolidated NorthEast Gas Gen.
As a result of the deconsolidation of NorthEast Gas Gen, Talen recognized a non-material investment in NorthEast Gas Gen and fully reserved the carrying values of certain receivables owed to Talen by NorthEast Gas Gen. As the carrying values of NorthEast Gas Gen’s liabilities exceeded its assets, an aggregate non-cash gain is
F-133
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
presented as “Deconsolidation of subsidiary gain (loss), net” presented on the Consolidated Statements of Operations for the year ended December 31, 2020:
| NorthEast Gas Gen | |||||
| Restricted cash and cash equivalents | $ | 6 | |||
| Affiliate trade accounts receivable | 3 | ||||
| Inventory | 8 | ||||
| Other current assets | 8 | ||||
| Property, plant and equipment | 468 | ||||
| Other noncurrent assets | 1 | ||||
Total assets | $ | 494 | |||
| Revolving credit facilities | $ | 10 | |||
| Accrued interest | 5 | ||||
| Accounts payable and other accrued liabilities | 15 | ||||
| Long-term debt, due within one year | 529 | ||||
| Other current liabilities | 3 | ||||
Affiliate long-term debt, due within one year (a) | 30 | ||||
| Asset retirement obligations and accrued environmental costs | 2 | ||||
Affiliate noncurrent accounts payable (b) | 30 | ||||
| Other noncurrent liabilities | 1 | ||||
Total liabilities | $ | 625 | |||
Non-cash (gain) on deconsolidation of NorthEast Gas Gen’s net assets and liabilities | $ | (131) | |||
| Less: | |||||
Non-cash charge to fully reserve Talen’s carrying value of its loan receivable for NGG’s affiliate long-term debt (a) | 30 | ||||
Non-cash charge to fully reserve Talen’s subordinated account receivables for NGG’s affiliate accounts payable (b) | 30 | ||||
(Gain) loss, net on deconsolidation of NorthEast Gas Gen | $ | (71) | |||
__________________
(a)Carrying value of the NGG Second Lien Affiliate TL owed to Talen Energy Supply by NorthEast Gas Gen.
(b)Carrying value of a subordinated affiliated accounts payable owed to Talen Energy Supply by NorthEast Gas Gen.
2020 NorthEast Gas Gen Bankruptcy
A Chapter 11 plan of reorganization for NorthEast Gas Gen under the Bankruptcy Code became effective in December 2020 that, among other things: (i) transferred ownership of NorthEast Gas Gen and its subsidiaries from Talen to an affiliate of NorthEast Gas Gen’s lenders; (ii) required Talen to provide RGGIs to NorthEast Gas Gen for a portion of its RGGI obligation (the non-material impact of such was recognized on the statement of operations in the fourth quarter 2020); and (iii) except as expressly provided for in the plan of reorganization, released Talen from further liability related to NorthEast Gas Gen. The NorthEast Gas Gen bankruptcy activities were not material to Talen’s financial condition or results of operations.
NorthEast Gas Gen Related Party Transactions
During 2020, pursuant to short-term energy management arrangements, Talen Energy Marketing received a monthly fee in exchange for providing NorthEast Gas Gen with certain marketing services such as energy management and fuel procurement. Additionally, Talen received a monthly fee in exchange for providing NorthEast
F-134
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Gas Gen other support services. These agreements expired in December 2020. Talen’s related party activities with NorthEast Gas Gen subsequent to the NorthEast Gas Gen deconsolidation and under these agreements were:
•an aggregate $10 million natural gas sales to NorthEast Gas Gen for the year ended December 31, 2020, that is presented as “Energy revenues” on the Consolidated Statement of Operations;
•an aggregate $603 thousand of earned energy management fees for the year ended December 31, 2020 and an aggregate $1 million of earned support services fees for the year ended December 31, 2020; and
•an aggregate $2 million payable for commodity activities due to NorthEast Gas Gen under the energy management arrangements at December 31, 2020 that is presented as “Accounts payable and other accrued liabilities” on the Consolidated Balance Sheet.
20. 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 Susquehanna Nuclear NDT.
Energy Commodity Derivatives. Level 1 derivative assets and liabilities primarily consist of exchange-traded futures and options. Level 2 derivative assets and liabilities primarily consist of over-the-counter swaps, options and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers or price service companies that are all corroborated by market data. Level 3 derivative assets and liabilities consist of over-the-counter swaps, options and forward purchase and sale contracts where a significant portion of fair value is calculated from underlying market data that is not readily available. The derived value uses industry standard methodologies that may consider the historical relationships among various commodities, modeled market prices, time value, volatility factors and other relevant economic measures. The use of these inputs results in management’s best estimate of fair value.
Interest Rate Derivatives. Level 2 derivative assets and liabilities primarily consist of fixed for floating over-the-counter swaps which are valued using readily observable inputs, such as forward interest rates (e.g., LIBOR and government security rates).
Nuclear Decommissioning Trust Funds. Level 1 investments consist of individual equity securities and U.S. treasury bills and (or) U.S. government debt securities that are valued using unadjusted prices available from the underlying exchange. Level 2 investments primarily consist of municipal and investment grade corporate debt securities which are valued using benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities, and credit valuation adjustments. Certain investments in money market funds, real estate investment trusts, commingled equity funds, and commingled fixed income funds 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. Real estate investment trust shares are redeemable on a quarterly basis. However, the investment manager has discretion over when the redemptions are paid out which is dependent on liquidity and redemption and subscription queues.
VEBA Trust. Level 1 investments consist of U.S. treasury notes that are valued using unadjusted prices available from the underlying exchange. Level 2 investments primarily consist of investment grade corporate debt securities which are valued using benchmark yields, relevant trade data, broker/dealer bid/ask prices, benchmark securities, and credit valuation adjustments. Certain investments, when held, in money market funds 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.
F-135
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The classifications of recurring fair value measurements within the fair value hierarchy were:
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Total | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 6 | $ | 6 | $ | — | $ | — | $ | — | $ | 5 | $ | 5 | |||||||||||||||||||||||||||||||||||||||
Equity securities (a) | 508 | — | — | 429 | 937 | 629 | — | — | 549 | 1,178 | |||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 272 | — | — | — | 272 | 166 | — | — | — | 166 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | 91 | — | — | 91 | — | 109 | — | — | 109 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 114 | — | — | 114 | — | 174 | — | — | 174 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Other debt securities | — | — | — | — | — | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (b) | (20) | 2 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds | 780 | 205 | — | 435 | 1,400 | 795 | 284 | — | 554 | 1,635 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | — | — | — | — | — | 4 | — | — | 4 | |||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | — | — | — | — | — | 1 | — | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||
VEBA trust (c) | — | — | — | — | — | 1 | 4 | — | — | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | 1,807 | 565 | 12 | — | 2,384 | 1,797 | 176 | 10 | — | 1,983 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 9 | — | — | 9 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 2,587 | $ | 779 | $ | 12 | $ | 435 | $ | 3,793 | $ | 2,593 | $ | 464 | $ | 10 | $ | 554 | $ | 3,623 | |||||||||||||||||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives (d) | $ | 1,879 | $ | 411 | $ | — | $ | — | $ | 2,290 | $ | 2,101 | $ | 330 | $ | 16 | $ | — | $ | 2,447 | |||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | — | — | — | — | 14 | — | — | 14 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Less: amounts presented as “Liabilities subject to compromise” | — | 1 | — | — | 1 | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 1,879 | $ | 410 | $ | — | $ | — | $ | 2,289 | $ | 2,101 | $ | 344 | $ | 16 | $ | — | $ | 2,461 | |||||||||||||||||||||||||||||||||||||||
__________________
(a)Includes commingled equity and fixed income funds and real estate investment trusts.
(b)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
(c)Presented as “Other current assets” on the Consolidated Balance Sheet and relates to Talen Energy Supply’s health and welfare “wrap” plan. See Note 21 for additional information.
(d)A portion of these amounts have been presented as “Liabilities subject to compromise” on the Consolidated Balance Sheet. See Note 3 for additional information.
The changes in the net Level 3 commodity derivative assets and liabilities for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Asset (liability), net, beginning of the period | $ | (6) | $ | 41 | $ | (4) | |||||||||||
| Gains (losses), net, included in earnings | 8 | (24) | 41 | ||||||||||||||
| Settlements | 10 | (23) | 4 | ||||||||||||||
| Asset (liability), net, end of the period | $ | 12 | $ | (6) | $ | — | $ | 41 | |||||||||
The significant unobservable inputs used in the fair value measurement of Level 3 commodity derivatives at December 31, 2022 were:
| Transaction Type | Valuation Technique | Unobservable Input | Low End Range | High End Range | Weighted Average (a) | Fair Value | ||||||||||||||||||||||||||||||||
| Congestion Products | Historical congestion | Forward congestion price | $(11.18)/MWh | $77.65/MWh | $ | 1.05 | $ | 12 | ||||||||||||||||||||||||||||||
__________________
(a)Weighted average is based on notional volumes at December 31, 2022.
F-136
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The significant unobservable inputs used in the fair value measurement of Level 3 commodity derivatives at December 31, 2021 were:
| Transaction Type | Valuation Technique | Unobservable Input | Low End Range | High End Range | Weighted Average (a) | Fair Value | ||||||||||||||||||||||||||||||||
| Congestion Products | Historical congestion | Forward congestion price | $(8.05)/MWh | $94.08/MWh | $1.77 | $ | 10 | |||||||||||||||||||||||||||||||
| Heat rate options | Option models | Power volatilities | 11% | 145% | 54% | (16) | ||||||||||||||||||||||||||||||||
| Gas volatilities | 3% | 57% | 13% | |||||||||||||||||||||||||||||||||||
| Power and gas correlation | (5)% | 35% | 16% | |||||||||||||||||||||||||||||||||||
__________________
(a)Weighted average is based on notional volumes at December 31, 2021.
The significant unobservable inputs used in the fair value measurement of Level 3 commodity derivatives at December 31, 2020 were:
| Transaction Type | Valuation Technique | Unobservable Input | Low End Range | High End Range | Weighted Average (a) | Fair Value | ||||||||||||||||||||||||||||||||
| Congestion Products | Historical congestion | Forward congestion price | $(6.31)/MWh | $95.89/MWh | $ | 0.63 | $ | 4 | ||||||||||||||||||||||||||||||
| Heat rate options | Option models | Power volatilities | 7% | 158% | 43% | $ | 37 | |||||||||||||||||||||||||||||||
| Gas volatilities | 2% | 33% | 7% | |||||||||||||||||||||||||||||||||||
| Power and gas correlation | (5)% | 35% | 10% | |||||||||||||||||||||||||||||||||||
__________________
(a)Weighted average is based on notional volumes at December 31, 2020.
The sensitivity of fair value measurements to changes in the significant unobservable inputs at December 31, 2022 and December 31, 2021 were:
| Significant Unobservable Input | Position | Change in Input | Fair Value Effect | |||||||||||||||||
| Forward congestion price | Purchased pathway | Price increase / decrease | Higher / (Lower) | |||||||||||||||||
| Forward congestion price | Sold pathway | Price increase / decrease | Lower / (Higher) | |||||||||||||||||
| Power and gas spread volatilities | Sold call option | Spread increase / decrease | Lower / (Higher) | |||||||||||||||||
| Power and gas correlation | Sold call option | Correlation increase / decrease | Higher / (Lower) | |||||||||||||||||
The net gains and losses of Level 3 commodity derivatives for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Energy Revenues | |||||||||||||||||
| Gains (losses) included in earnings | $ | 8 | $ | (24) | $ | 41 | |||||||||||
Change in unrealized gains (losses) (a) | 18 | (47) | 41 | ||||||||||||||
| Energy Expenses | |||||||||||||||||
Change in unrealized gains (losses) (a) | — | — | 4 | ||||||||||||||
__________________
(a)Amounts included in earnings for positions still held at the end of each reporting date.
Nonrecurring Fair Value Measurements
See Note 11 for information on the nonrecurring fair value measurement of Cumulus Digital Holdings during the year ended December 31, 2022. There were no nonrecurring fair value measurements related to impairments of long-lived assets for the year ended December 31, 2021.
F-137
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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,” “Inventory repurchase obligations,” “Deferred capacity obligations,” 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 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.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||||||||||
| Revolving credit facilities | $ | 848 | $ | 848 | $ | 848 | $ | 848 | |||||||||||||||
Other short-term indebtedness (a) | — | — | 5 | 5 | |||||||||||||||||||
Long-term debt (b) | 5,062 | 4,386 | 3,894 | 2,995 | |||||||||||||||||||
__________________
(a)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
(b)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
21. 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. In May 2022, the Debtors filed for protection under Chapter 11 of the Bankruptcy Code. Subsequent to that filing, the Bankruptcy Court approved the continued management and operation of Talen’s pension and other postretirement plans during the Restructuring.
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 $28 million at December 31, 2022 and 2021 and by $24 million at December 31, 2020 are presented as “Other noncurrent assets” on the Consolidated Balance Sheets. The current portion of certain unfunded postretirement obligations were not material.
F-138
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The aggregate funded status and the weighted average assumptions at December 31 were:
| Pension Benefits | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Change in benefit obligation | |||||||||||||||||
| Benefit obligation at January 1 | $ | 1,721 | $ | 1,853 | $ | 1,732 | |||||||||||
| Service cost | 4 | 4 | 4 | ||||||||||||||
| Interest cost | 50 | 47 | 56 | ||||||||||||||
| Actuarial (gain) loss | (408) | (77) | 162 | ||||||||||||||
| Plan participant contributions | — | — | — | ||||||||||||||
| Actual benefits paid | (94) | (106) | (102) | ||||||||||||||
| Benefit obligation at December 31 | 1,273 | 1,721 | 1,852 | ||||||||||||||
Change in plan assets | |||||||||||||||||
| Plan assets fair value at January 1 | 1,437 | 1,388 | 1,305 | ||||||||||||||
| Actual return on plan assets | (359) | 141 | 184 | ||||||||||||||
| Employer contributions | 10 | 14 | — | ||||||||||||||
| Plan participant contributions | — | — | — | ||||||||||||||
| Actual benefits paid | (94) | (106) | (102) | ||||||||||||||
| Plan assets fair value at December 31 | 994 | 1,437 | 1,387 | ||||||||||||||
| Funded Status | $ | (279) | $ | (284) | $ | (465) | |||||||||||
| Accumulated benefit obligation | $ | 1,273 | $ | 1,721 | $ | 1,852 | |||||||||||
Aggregate amounts of underfunded plans | |||||||||||||||||
| Benefit obligation / Accumulated benefit obligation | 1,273 | 1,721 | 1,852 | ||||||||||||||
| Fair value of plan assets | 994 | 1,437 | 1,387 | ||||||||||||||
| Amounts recognized in accumulated other comprehensive income | |||||||||||||||||
| Net (gain) loss | $ | 239 | $ | 247 | $ | 450 | |||||||||||
| Prior service cost (credit) | — | — | — | ||||||||||||||
| Total accumulated other comprehensive income | $ | 239 | $ | 247 | $ | 450 | |||||||||||
| Assumptions | |||||||||||||||||
| Discount rate | 5.41 | % | 2.97 | % | 2.61 | % | |||||||||||
| Interest crediting rate | 6.00 | % | 6.00 | % | 6.00 | % | |||||||||||
| Rate of compensation increase | 3.45 | % | 3.45 | % | 3.45 | % | |||||||||||
F-139
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
| Other Postretirement Benefits | |||||||||||||||||
| 2022 | 2021 | 2020 | |||||||||||||||
| Change in benefit obligation | |||||||||||||||||
| Benefit obligation at January 1 | $ | 104 | $ | 108 | $ | 99 | |||||||||||
| Service cost | 2 | 2 | 2 | ||||||||||||||
| Interest cost | 3 | 3 | 3 | ||||||||||||||
| Actuarial (gain) loss | (24) | — | 11 | ||||||||||||||
| Plan participant contributions | 2 | 3 | 2 | ||||||||||||||
| Actual benefits paid | (10) | (11) | (9) | ||||||||||||||
| Benefit obligation at December 31 | 77 | 105 | 108 | ||||||||||||||
Change in plan assets | |||||||||||||||||
| Plan assets fair value at January 1 | 99 | 101 | 96 | ||||||||||||||
| Actual return on plan assets | (17) | 5 | 12 | ||||||||||||||
| Employer contributions | 1 | 1 | 1 | ||||||||||||||
| Plan participant contributions | 2 | 3 | 2 | ||||||||||||||
| Actual benefits paid | (10) | (11) | (9) | ||||||||||||||
| Plan assets fair value at December 31 | 75 | 99 | 102 | ||||||||||||||
| Funded Status | $ | (2) | $ | (6) | $ | (6) | |||||||||||
| Accumulated benefit obligation | $ | — | $ | — | $ | — | |||||||||||
| Aggregate amounts of underfunded plans | |||||||||||||||||
| Benefit obligation / Accumulated benefit obligation | 51 | 70 | 71 | ||||||||||||||
| Fair value of plan assets | 21 | 36 | 41 | ||||||||||||||
| Amounts recognized in accumulated other comprehensive income | |||||||||||||||||
| Net (gain) loss | $ | 4 | $ | 7 | $ | 8 | |||||||||||
| Prior service cost (credit) | (4) | (5) | (6) | ||||||||||||||
| Total accumulated other comprehensive income | $ | — | $ | 2 | $ | 2 | |||||||||||
| Assumptions | |||||||||||||||||
| Discount rate | 5.41 | % | 2.94 | % | 2.57 | % | |||||||||||
| Interest crediting rate | |||||||||||||||||
| Rate of compensation increase | 2.31 | % | 2.31 | % | 2.31 | % | |||||||||||
In 2022, 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. In 2021, the decrease in postretirement benefit obligations was primarily attributable to increasing interest rates, combined with actual returns in excess of expected returns on plan assets. In 2020, the increase in the postretirement benefit obligations was primarily attributable to decreasing interest rates, offset by actual returns in excess of expected returns on plan assets.
Net Periodic Benefit Cost and amounts recognized in OCI. Service cost is presented as “Postretirement benefits service cost” while the other components of net periodic defined benefit cost (credit) for pension and other postretirement plans are presented as “Postretirement benefits gain (loss), net” on the Consolidated Statements of Operations. The portion of net periodic benefit cost capitalized during the years ended December 31, 2022 and 2021 was not material.
F-140
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The components of net periodic benefit cost (credit), the amounts recognized in OCI and the associated weighted average assumptions for pension and other postretirement plans for the years ended and at December 31 were:
| Pension Benefits | Other Postretirement Benefits | ||||||||||||||||||||||
| 2022 | 2021 | 2022 | 2021 | ||||||||||||||||||||
| Net periodic benefit costs (credits): | |||||||||||||||||||||||
| Service cost | $ | 4 | $ | 4 | $ | 1 | $ | 2 | |||||||||||||||
| Interest cost | 50 | 47 | 3 | 3 | |||||||||||||||||||
| Expected return on plan assets | (68) | (67) | (4) | (4) | |||||||||||||||||||
| Amortization of prior service cost (credit) | — | — | (1) | (1) | |||||||||||||||||||
| Amortization of net (gain) loss | 27 | 52 | — | — | |||||||||||||||||||
| Net periodic defined benefit cost (credit) | 13 | 36 | — | — | |||||||||||||||||||
| Net actuarial (gain) loss | 19 | (151) | (3) | — | |||||||||||||||||||
| Reclassifications due to settlement and (or) curtailment: | |||||||||||||||||||||||
| Amortization of prior service cost (credit) | — | — | 1 | 1 | |||||||||||||||||||
| Amortization of net (gain) loss | (27) | (52) | (1) | — | |||||||||||||||||||
| Total recognized in OCI | (8) | (203) | (3) | 1 | |||||||||||||||||||
| 5 | |||||||||||||||||||||||
| Total recognized in net periodic costs and OCI | $ | 5 | $ | (167) | $ | (3) | $ | 1 | |||||||||||||||
| Assumptions | |||||||||||||||||||||||
| Discount rate | 2.97 | % | 2.61 | % | 2.94 | % | 2.57 | % | |||||||||||||||
| Rate of compensation increase | 3.45 | % | 2.96 | % | 2.31 | % | 2.61 | % | |||||||||||||||
| Expected return on plan assets | 5.75 | % | 5.75 | % | 3.89 | % | 3.89 | % | |||||||||||||||
Health care grading trend rates (a) | — | — | 5.60% to 4.50% | 6.75% to 4.93% | |||||||||||||||||||
__________________
(a)Trend rates grading to 2027.
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. The American Rescue Plan Act was enacted in March 2021 and provides pension plan funding relief for sponsoring employers. In the second quarter 2021, Talen Energy Supply made certain elections available under The American Rescue Plan Act with respect to its largest defined benefit pension plan that includes relief provisions for minimum defined benefit pension contributions. Accordingly, there were no minimum required contributions for any of our sponsored pension plans in 2022 and 2021. Talen Montana contributed $10 million and $13 million of discretionary contributions in 2022 and 2021 to the Talen Montana pension plan.
There are no expected minimum required contributions for any of our sponsored pension plans in 2022. Talen Montana expects to contribute approximately $6 million of discretionary contributions in 2023.
The aggregate benefits paid to pension and other postretirement plan participants was $104 million in 2022 and $117 million in 2021.
F-141
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The forecasted undiscounted benefit payments to plan participants at December 31, 2022 were:
| 2023 | 2024 | 2025 | 2026 | 2027 | 2027-2031 | ||||||||||||||||||||||||||||||
| Pension plans | $ | 98 | $ | 92 | $ | 93 | $ | 93 | $ | 93 | $ | 458 | |||||||||||||||||||||||
| Other postretirement plans | 7 | 7 | 7 | 6 | 6 | 27 | |||||||||||||||||||||||||||||
Pension plan assets. Pension plan assets are invested 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 manage concentrations of risk with asset diversification.
The weighted-average target asset allocations for the pension plan assets at December 31 were:
| 2022 | |||||
| Equity securities | 31 | % | |||
| Debt securities | 10 | % | |||
| Other | 6 | % | |||
| Growth portfolio | 47 | % | |||
| Debt securities | 38 | % | |||
| Other | 11 | % | |||
| Immunizing portfolio | 49 | % | |||
| Liquidity portfolio | 4 | % | |||
| Total | 100 | % | |||
The classification of pension plan asset fair value measurements within the fair value hierarchy were:
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Total | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 102 | $ | 102 | $ | — | $ | — | $ | — | $ | 139 | $ | 139 | |||||||||||||||||||||||||||||||||||||||
| Equity securities | — | — | — | — | — | — | — | — | 509 | 509 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt securities | — | — | — | 689 | 689 | — | — | — | 455 | 455 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Alternative and other investments | 1 | — | — | 188 | 189 | 4 | — | — | 254 | 258 | |||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (a) | 22 | 95 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total trust funds | 1 | — | — | 979 | 1,002 | 4 | — | — | 1,357 | 1,456 | |||||||||||||||||||||||||||||||||||||||||||||||||
Restricted 401(h) assets (b) | (8) | (19) | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total plan assets | $ | 1 | $ | — | $ | — | $ | 979 | $ | 994 | $ | 4 | $ | — | $ | — | $ | 1,357 | $ | 1,437 | |||||||||||||||||||||||||||||||||||||||
__________________
(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.
F-142
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 funds, 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.
The target asset allocations for other postretirement benefit assets at December 31 were:
| 2022 | |||||
| Cash and cash equivalents | 6 | % | |||
| Equity securities | 12 | % | |||
| Debt securities | 82 | % | |||
| Total | 100 | % | |||
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Pursuant to 17 C.F.R. Section 200.83
The classification of other postretirement benefit plan asset fair value measurements within the fair value hierarchy were:
| December 31, 2022 | December 31, 2021 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | NAV | Total | Level 1 | Level 2 | Level 3 | NAV | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | — | $ | 7 | $ | 7 | $ | — | $ | — | $ | — | $ | 4 | $ | 4 | |||||||||||||||||||||||||||||||||||||||
| Equity securities | — | — | — | 7 | 7 | — | — | — | 9 | 9 | |||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 6 | — | — | — | 6 | 5 | — | — | — | 5 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 17 | — | — | 17 | — | 19 | — | — | 19 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Commingled debt securities | — | — | — | 31 | 31 | — | — | — | 43 | 43 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total trust funds | 6 | 17 | — | 45 | 68 | 5 | 19 | — | 56 | 80 | |||||||||||||||||||||||||||||||||||||||||||||||||
Restricted 401(h) assets (a) | 7 | 19 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total plan assets | $ | 6 | $ | 17 | $ | — | $ | 45 | $ | 75 | $ | 5 | $ | 19 | $ | — | $ | 56 | $ | 99 | |||||||||||||||||||||||||||||||||||||||
__________________
(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 funds, 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 $18 million in 2022 and 2021.
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.
The funded status of each plan at December 31, 2022 were:
| Trust Asset Fair Value | Obligation Fair Value | Funded Status | |||||||||||||||
| Benefit Plan for UMWA Represented Retirees of Pennsylvania Mines, LLC | $ | 28 | $ | 20 | $ | 8 | |||||||||||
| Coal Worker’s Pneumoconiosis (Black Lung) Benefit Plan | 13 | 7 | 6 | ||||||||||||||
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
In January 2020, the Benefit Plan for UMWA Represented Retirees of Pennsylvania Mines, LLC was merged with and into Talen’s health and welfare “wrap” plan, under which Talen provides a variety of health and welfare benefits to employees and other eligible participants pursuant to a single ERISA administrative framework. 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 in the amount of $15 million for the year ended December 31, 2021. As such assets were not presented on the Consolidated Balance Sheets prior to the transfer of the assets from the PA Mines UMWA Plan VEBA, Talen recognized gains for the amounts transferred in their respective periods, which are presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operation.
22. Accumulated Other Comprehensive Income
The total changes in AOCI for the years ended December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Beginning balance | $ | (152) | $ | (294) | $ | (279) | |||||||||||
| Gains (losses) arising during the period | (84) | 138 | (9) | ||||||||||||||
Reclassifications to Consolidated Statements of Operations | 59 | 53 | (11) | ||||||||||||||
| Income tax benefit (expense) | 10 | (49) | 5 | ||||||||||||||
| Other comprehensive income (loss) | (15) | 142 | (15) | ||||||||||||||
| Accumulated other comprehensive income | $ | (167) | $ | (152) | $ | (294) | |||||||||||
The components of AOCI, net of tax, at December 31 were:
| 2022 | 2021 | 2020 | |||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | (16) | $ | 4 | $ | 10 | |||||||||||
| Qualifying derivatives unrealized gain (loss), net | 9 | 11 | 13 | ||||||||||||||
| Postretirement benefit prior service credits (costs), net | 7 | 6 | 5 | ||||||||||||||
| Postretirement benefit actuarial gain (loss), net | (167) | (173) | (322) | ||||||||||||||
| Accumulated other comprehensive income | $ | (167) | $ | (152) | $ | (294) | |||||||||||
The locations of pre-tax gains (losses) reclassified from AOCI and included on the Consolidated Statements of Operations for the years ended December 31 were:
| Location of gain (loss) | 2022 | 2021 | 2020 | |||||||||||||||||
Nuclear decommissioning trust funds gain (loss), net (a) | $ | (33) | $ | (2) | $ | 36 | ||||||||||||||
Depreciation, amortization and accretion (b) | 2 | 2 | 3 | |||||||||||||||||
Impairments (b) | — | — | 9 | |||||||||||||||||
Postretirement benefit gain (loss), net (c) | (28) | (53) | (37) | |||||||||||||||||
| Total | $ | (59) | $ | (53) | $ | 11 | ||||||||||||||
__________________
(a)Available-for-sale securities unrealized gain (loss), net
(b)Qualifying derivatives unrealized gain (loss)
(c)Postretirement benefit prior service credits (costs), net and Postretirement benefit actuarial gain (loss), net
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
The postretirement obligations components of AOCI are not presented in their entirety on the statement of operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 21 for additional information.
23. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the years ended December 31:
| 2022 | 2021 | 2020 | |||||||||||||||
| Cash paid (received) during the period | |||||||||||||||||
| Interest and other finance charges, net of capitalized interest ($12 million in 2022 and $4 million in 2021) | $ | 277 | $ | 316 | $ | 303 | |||||||||||
| Income taxes, net | 14 | 20 | 21 | ||||||||||||||
| Non-cash investing and operating activities | |||||||||||||||||
| Capital expenditure accrual increase (decrease) | $ | 2 | $ | (2) | $ | 2 | |||||||||||
Accounts receivable contributed to equity method investment (a) | 2 | 6 | 18 | ||||||||||||||
Non-cash preferred equity method investment contribution and accounts payable accrual (b) | — | 5 | — | ||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Operations: | |||||||||||||||||
| Depreciation, amortization and accretion | $ | 520 | $ | 524 | $ | 452 | |||||||||||
Amortization of deferred finance costs and original issuance discounts (interest expense) (b) | 29 | 31 | 17 | ||||||||||||||
| Total | $ | 549 | $ | 555 | $ | 469 | |||||||||||
| Non-cash financing/investing activities | |||||||||||||||||
Non-cash hypothetical liquidation at book value contribution to equity and noncurrent assets | $ | — | $ | 11 | $ | — | |||||||||||
Non-cash increase to PPE and decrease to other current assets for transfer of miners by Cumulus Coin (c) | 30 | — | — | ||||||||||||||
Non-cash increase to PPE and increase to noncontrolling interest for transfer of miners by TeraWulf (c) | 14 | — | — | ||||||||||||||
| Unrealized (gain) loss on derivatives: | |||||||||||||||||
| Commodity contracts | $ | (625) | $ | 712 | $ | 34 | |||||||||||
| Interest rate swap contracts | (23) | (28) | 35 | ||||||||||||||
| Total | $ | (648) | $ | 684 | $ | 69 | |||||||||||
| Operating Activities Reconciliation Adjustments, Other: | |||||||||||||||||
| Net periodic defined benefit cost | $ | 12 | $ | 36 | $ | 31 | |||||||||||
| Derivative option premium amortization | 67 | (176) | 23 | ||||||||||||||
| Non-cash environmental liability revisions | 13 | — | — | ||||||||||||||
| Non-cash “construction work in progress” capital project cancellations | — | — | 23 | ||||||||||||||
| Non-cash ARO revisions | — | (3) | (7) | ||||||||||||||
| Nonrecourse PIK interest | (1) | — | 11 | ||||||||||||||
| Derivatives with financing elements | 104 | — | — | ||||||||||||||
| Debt restructuring (gain) loss, net | 6 | 2 | 3 | ||||||||||||||
| Other | (1) | (9) | 10 | ||||||||||||||
| Total | $ | 200 | $ | (150) | $ | 94 | |||||||||||
__________________
(a)See Note 11 for information on equity method investments.
(b)Includes previously recognized fair value adjustments on certain exchanges of indebtedness.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(c)In 2022, the joint venture partners of Nautilus each made a non-cash contribution of cryptocurrency miners that increased PPE.
Other Non-cash Matters
In September 2021, Talen Energy Supply deconsolidated the assets and liabilities of Cumulus Coin Holdings, including its equity method investment in Nautilus, which resulted in the following non-cash change to Talen Energy Supply’s Consolidated Balance Sheet at September 30, 2021:
| Increase (Decrease) | |||||
| Other noncurrent assets | $ | (29) | |||
| Other noncurrent liabilities | (29) | ||||
In September 2021, Talen deconsolidated Cumulus Data which resulted in the following non-cash change to Talen Energy Supply’s Consolidated Balance Sheet at September 30, 2021:
| Increase (Decrease) | |||||
| Property, plant and equipment | $ | (31) | |||
| Other noncurrent assets | 23 | ||||
| Accounts payable and accrued liabilities | (8) | ||||
In September 2022, as a result of the Cumulus Digital Equity Conversion, Talen Energy Supply consolidated Cumulus Digital Holdings, which included restricted cash. See Note 12 for additional information on the Cumulus Term Sheet and consolidation of Cumulus Digital Holdings, which included certain non-cash impacts.
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:
| December 31, 2022 | December 31, 2021 | ||||||||||
| Cash and cash equivalents | $ | 724 | $ | 276 | |||||||
| Restricted cash and cash equivalents: | |||||||||||
| Commodity exchange margin and other collateral deposits | 174 | 442 | |||||||||
| Cumulus Digital Holdings debt restricted deposits | 49 | — | |||||||||
| Nautilus project restricted deposits | 19 | — | |||||||||
| LMBE-MC major maintenance reserve deposits | 7 | 15 | |||||||||
| LMBE-MC debt service reserve deposits | 7 | 10 | |||||||||
| TEC Global Settlement deposits | 7 | — | |||||||||
| Other | 1 | — | |||||||||
| Restricted cash and cash equivalents | 264 | 467 | |||||||||
| Total | $ | 988 | $ | 743 | |||||||
24. Related Party Transactions
Talen historically has 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, Talen adjusted amounts previously
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
accrued for these fees. The aggregate fees incurred for services and reimbursements for the years ended December 31 were:
| 2022 | 2021 | ||||||||||
Riverstone Holdings, LLC management fees (a) (c) | $ | — | $ | 1 | |||||||
Riverstone Holdings, LLC litigation fees (a) (b) (c) | (5) | 6 | |||||||||
__________________
(a)Presented as “General and administrative” on the Consolidated Statements of Operations.
(b)At December 31, 2021, $5 million was presented as “Accounts payable and other accrued liabilities” on the Consolidated Balance Sheets.
(c)Includes adjustments recognized in September 2022. See below for additional information.
In recent years, Talen Energy Supply has paid certain expenses and liabilities incurred by Talen Energy Corporation. Accordingly, at December 31, 2022 and 2021, Talen Energy Supply presented $2 million due from Talen Energy Corporation as “Accounts receivable, net” presented on the Consolidated Balance Sheets.
Pursuant to the TEC Global Settlement: (i) upon confirmation of the Plan of Reorganization in December 2022, Talen Energy Supply paid $8 million in fees and expenses of Talen Energy Corporation’s professional advisors; (ii) deposited $7 million in a custodial account presented as “Restricted cash” on the Consolidated Balance Sheet which will be used to pay fees and expenses of Talen Energy Corporation’s advisors when due at future dates; (iii) all other unpaid management fees and expenses owed to Riverstone was forfeited by Riverstone upon the Emergence Date; and (iv) amounts owed by Talen Energy Corporation to Talen Energy Supply were waived, at the option of TEC, upon the Emergence Date.
During the year ended December 31, 2022, as a result of the TEC Global Settlement and the agreement reached in November 2022 between the Debtors and the unsecured creditor’s committee (the “UCC Settlement”), Talen: (i) reversed prior amounts accrued due to Riverstone for unpaid management fees and expenses totaling $5 million (to “General and administrative”); and (ii) recognized expense totaling $8 million (to “Reorganization gain (loss)”), for certain fees and expenses incurred by Talen Energy Corporation which have been reimbursed by Talen Energy Supply pursuant to the TEC Global Settlement.
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, Talen paid approximately $88 thousand and $140 thousand under these agreements. Talen terminated the contracts with these independent contractors in July 2022 as their services are no longer required.
See Notes 12 for information on a related party transaction whereby Riverstone sold a portion of its common equity in Cumulus Digital Holdings to one current and one former member of the Talen management team.
See Notes 11 and 12 for additional information on other related party transactions.
25. Acquisitions and Divestitures
Potential Acquisition
Talen Montana Colstrip Units 3 and 4 Transaction. In September 2022, Talen Montana entered into a definitive agreement under which Puget Sound Energy, Inc. will transfer its 25% share of Colstrip Units 3 and 4 to Talen Montana for nominal consideration. As part of the transaction, Puget Sound Energy, Inc. will retain certain liabilities attributable to pre-closing operations, including environmental remediation and decommissioning costs. Until the closing of the transaction, Talen Montana is entitled to increased voting rights (via Puget’s voting rights) regarding certain decisions relating to Colstrip Units 3 and 4. The agreement is subject to customary closing conditions. In addition, the co-owners of Colstrip Units 3 and 4 have certain rights of first refusal which may entitle them to acquire a portion of the interest being transferred by Puget Sound Energy, Inc. The anticipated closing date of the transaction is December 31, 2025. Talen also enjoys a right of first refusal on any other changes in ownership in Colstrip Units 3 and 4.
F-148
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Talen Montana owns 30% of Colstrip Unit 3 and does not own any portion of Colstrip Unit 4. However, it is a participant in agreements regarding the ownership and operation of Colstrip Units 3 and 4, whereby Talen Montana is responsible for 15% of the total operating costs and expenditures of Colstrip Unit 3 and 15% of Colstrip Unit 4. Accordingly, it is entitled to 15% of the available generation from each of these units. Following the consummation of the transaction, assuming no co-owner exercises right of first refusal, Talen Montana will own a 55% share of Colstrip Unit 3 and a 25% share of Colstrip Unit 4 and continue to be the sole operator of both Colstrip Units 3 and 4.
Completed Acquisition
Conemaugh Generation Facility Additional Interest. In July 2020, Talen subsidiaries executed an agreement to purchase another co-owner’s 5.97% undivided interest in Conemaugh and its 5.97% membership interest in Conemaugh Fuels for a non-material amount of cash consideration. The purchase was completed in September 2020. After completion of the transaction, Talen owns a 22.22% interest in both Conemaugh and Conemaugh Fuels. Additionally, Talen recognized a $162 million non-cash impairment charge for the year ended December 31, 2021 on the aggregate carrying value of the Keystone and Conemaugh asset group’s property, plant, and equipment. See Note 14 for additional information on the impairment.
Completed Divestitures
IEC Pipeline. In January 2020, Talen consummated a sale of 100% of its equity interests in IEC and received $153 million of cash proceeds, net of transaction costs, which were used to repay a portion of Talen Energy Supply recourse indebtedness. Talen separately received $10 million in initial cash consideration in the fourth quarter 2017 contemporaneously with the execution of the IEC purchase and sale agreement. Upon completion of the sale, the purchaser of IEC began to provide firm transportation for natural gas to the Martins Creek and Lower Mt. Bethel generation facilities.
During the year ended December 31, 2020, the $144 million gain on IEC sale was presented as “Other operating income (expense), net” presented on the Consolidated Statement of Operations.
Other
The September 2022 Cumulus Digital Holdings and Nautilus August 2022 consolidations were accounted for as business combinations. See Note 12 for additional information.
26. 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 maker function reviews results and allocates resources. Segment Adjusted EBITDA is the key profit metric used to measure financial performance. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker function.
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;
•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 and Dartmouth. 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
F-149
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
our reportable segments; (ii) the development activities of Cumulus Growth Holdings; (iii) the development and operating activities of Cumulus Digital; (iv) other immaterial components that are not regularly reviewed by our chief operating decision maker; 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:
| 2022 | |||||||||||||||||||||||
| 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 | |||||||||||||||||||
| Segment Adjusted EBITDA | 964 | 105 | 1,069 | ||||||||||||||||||||
| 2021 | |||||||||||||||||||||||
| 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 | |||||||||||||||||||
| Segment Adjusted EBITDA | 372 | 61 | 433 | ||||||||||||||||||||
| 2020 | |||||||||||||||||||||||
| PJM | ERCOT and WECC | Corporate, Development, and Other | Total | ||||||||||||||||||||
| Operating revenues | $ | 1,321 | $ | 302 | $ | 103 | $ | 1,726 | |||||||||||||||
| Interest expense | — | — | 363 | 363 | |||||||||||||||||||
| Capital expenditures | 147 | 8 | 6 | 161 | |||||||||||||||||||
| Segment Adjusted EBITDA | 554 | 53 | 607 | ||||||||||||||||||||
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
| 2022 | 2021 | 2020 | |||||||||||||||
| Segment Adjusted EBITDA: | |||||||||||||||||
| PJM | $ | 964 | $ | 372 | $ | 554 | |||||||||||
| ERCOT and WECC | 105 | 61 | 53 | ||||||||||||||
Total Segment Adjusted EBITDA | $ | 1,069 | $ | 433 | $ | 607 | |||||||||||
| Reconciling items: | |||||||||||||||||
| Bankruptcy, liability management, and restructuring costs | $ | (1,538) | $ | (42) | $ | (16) | |||||||||||
| Interest expense and other finance charges | (365) | (336) | (366) | ||||||||||||||
| Income tax benefit (expense) | 35 | 300 | 181 | ||||||||||||||
| Depreciation, amortization and accretion | (520) | (524) | (452) | ||||||||||||||
| Nuclear fuel amortization | (94) | (96) | (106) | ||||||||||||||
| Unrealized gain (loss) on commodity derivative contracts | 625 | (712) | (33) | ||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | (184) | 196 | 172 | ||||||||||||||
| Unusual market events | (33) | (78) | — | ||||||||||||||
| Impairments, canceled projects, obsolescence, and receivables allowance | 2 | (17) | (753) | ||||||||||||||
| Gain (loss) on non-core asset sales | 3 | 3 | 141 | ||||||||||||||
| Consolidation/deconsolidation of subsidiary gain (loss), net | (170) | — | 71 | ||||||||||||||
| Corporate, development, and other | (123) | (104) | (110) | ||||||||||||||
Net income (loss) | $ | (1,293) | $ | (977) | $ | (664) | |||||||||||
27. Subsequent Events
Talen Energy Supply originally evaluated subsequent events through April 3, 2023, the date the financial statements were initially issued. We further evaluated subsequent events for disclosure from the initial issuance date until the date these financial statements were issued on September 8, 2023. All significant subsequent events are included in their respective notes to the financial statements, with the exception of the agreements described below.
Riverstone Warrant Cancellation
On August 10, 2023, TEC, TES and Riverstone entered into an agreement pursuant to which (i) Riverstone agreed to surrender all of its warrants to purchase TEC common stock to TEC for cancellation and to waive all future rights to the Retail PPA Incentive Equity; and (ii) TEC, TES and Riverstone agreed to terminate and cancel a tax indemnity agreement executed by them in connection with the TEC Global Settlement. TEC agreed to pay Riverstone $40 million in exchange for these cancellations and waivers. The cancellations and waivers were consummated concurrently with the consummation of the Riverstone Buyout described below.
Riverstone Buyout
On August 10, 2023, Riverstone and TES entered into a purchase and sale agreement pursuant to which TES agreed to purchase 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”). Under the terms of the Cumulus Digital Holdings limited liability company agreement, the other members of Cumulus Digital Holdings had a right to participate in the Riverstone Buyout on a pro rata basis based on their and TES’s respective ownership of Cumulus Digital Holdings common units. The transaction closed in the third quarter of 2023. Upon closing, TES’s ownership interest in Cumulus Digital Holdings increased to approximately 95%. Affiliates of Orion also elected to participate in the Riverstone Buyout and acquired an additional 1% interest. TES has sole control of the Cumulus Digital Holdings board of managers following the closing of the Riverstone Buyout.
F-151
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Gains on Completed Divestitures
Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to transportation of natural gas in the southwestern United States and recognized a gain of $15 million. See Note 21 in Notes to the Interim Financial Statements regarding the gain from the divestiture of certain contracts relating to transportation of natural gas in the Southwestern United States.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania and recognized a gain of $29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. See Note 21 in Notes to the Interim Financial Statements regarding the Pennsylvania Minerals Divestiture gain.
F-152
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
GLOSSARY
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) Cumulus Digital activities and noncontrolling interest; and (xv) other adjustments.
“American Nuclear Insurers” means joint underwriting association that acts on behalf of member companies that writes nuclear liability insurance policies.
“American Rescue Plan Act” means a federal stimulus bill passed in 2021 to accelerate recovery from the economic and health effects of the COVID-19 pandemic.
“Annual Financial Statements” means the audited consolidated balance sheets of Talen Energy Supply as of December 31, 2022 and 2021, the related consolidated statements of operations, statements of comprehensive income, statements of cash flows and statements of equity for the fiscal years ended December 31, 2022, 2021 and 2020, 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.
“ASAs” means affiliate services agreements executed in May 2022 between Talen Energy Supply and each of Cumulus Battery Storage Holdings, Cumulus Compute Holdings, Cumulus Real Estate Holdings and Cumulus Renewables Holdings. See Note 12 in Notes to the Annual Financial Statements for additional information.
“ASC” means Accounting Standards Codification.
“ASU” means Accounting Standards Update.
“Athens” means New Athens Generating Company, LLC, a direct subsidiary of NorthEast Gas Gen that owns a generation facility in Athens, New York. Athens was deconsolidated by Talen in April 2020. Ownership of Athens was transferred from Talen to a third party in December 2020 in connection with NorthEast Gas Gen’s emergence from bankruptcy.
“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.
G-1
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Bankruptcy Court” means the United States Bankruptcy Court for the Southern District of Texas, Houston Division.
“Barney Davis” means Barney Davis, LLC, a direct subsidiary of Talen Texas that owns and operates a generation facility in Corpus Christi, Texas.
“Beowulf E&D” means Beowulf Electricity & Data Inc., an affiliate of TeraWulf, an unaffiliated third party.
“Beowulf FOA” means the Facility Operations Agreement executed in May 2021 between Nautilus and Beowulf E&D 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’ ongoing business at the facility at an annual rate of $750 thousand and reimbursement of direct costs. The Beowulf FOA was terminated in December 2022.
“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 Talen Energy Supply and the Subsidiary Guarantors.
“Bitcoin” means a virtual digital currency, with no central issuing authority, used in peer-to-peer online transactions.
“Black Lung Act” means the Federal Black Lung Benefits Act of 1972.
“Board of Directors” means the board of directors of Talen Energy Corporation.
“BQ Energy” means BQ Energy Development, LLC, an unaffiliated third party.
“Brandon Shores” means Brandon Shores LLC, an indirect subsidiary of Talen Generation that owns and operates a generation facility in Curtis Bay, Maryland.
“Brunner Island” means Brunner Island, LLC, a direct subsidiary of Talen Generation that owns and operates a generation facility in York Haven, Pennsylvania.
“CAA” means the Clean Air Act of 1963. The CAA established a federal program within the U.S. Public Health Service and authorized research into techniques for monitoring and controlling air pollution.
“Camden” means Camden Plant Holding, LLC, an indirect subsidiary of Talen Generation that owns and operates a 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.
G-2
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Coal Act” means the Coal Industry Retiree Health Benefit Act of 1992.
“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 Interim Financial Statements and Note 14 in Notes to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in the Colstrip Units. See Note 21 in Notes to the Interim Financial Statements and Note 25 in Notes to the Annual Financial Statements for information on a pending acquisition by Talen Montana of additional interests in Colstrip Units 3 and 4.
“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 Interim Financial Statements and Note 14 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 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 Real Estate Holdings, Cumulus Battery Storage Holdings, Cumulus Renewables Holdings, Cumulus Compute Holdings, Cumulus PT Energy Transitions Holdings, Cumulus Digital Holdings and their respective subsidiaries.
“Cumulus Battery Storage Holdings” means Cumulus Battery Storage Holdings LLC, a direct subsidiary of Cumulus Growth. Prior to September 2023, Talen Energy Supply held voting, convertible preferred equity units in this entity that provided Talen Energy Supply with a majority equity interest on an as-converted basis. Accordingly, although Cumulus Growth was not a subsidiary of Talen Energy Supply, Talen Energy Supply consolidated Cumulus Battery Storage Holdings and its subsidiaries for financial reporting purposes in accordance with accounting rules. In September 2023, Cumulus Growth became a subsidiary of Talen Energy Supply, and Talen Energy Supply transferred 100% of its preferred equity interests in Cumulus Battery Storage Holdings to Cumulus Growth. Following such transfer, the preferred equity interests were cancelled.
“Cumulus Coin” means Cumulus Coin LLC, a direct subsidiary of Cumulus Coin Holdings that owns a 75% equity interest in Nautilus at June 30, 2023.
“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.
G-3
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Cumulus Compute Holdings” means Cumulus Compute Holdings LLC, a direct subsidiary of Cumulus Growth. Prior to September 2023, Talen Energy Supply held voting, convertible preferred equity units in this entity that provided Talen Energy Supply with a majority equity interest on an as-converted basis. Accordingly, although Cumulus Growth was not a subsidiary of Talen Energy Supply, Talen Energy Supply consolidated Cumulus Compute Holdings and its subsidiaries for financial reporting purposes in accordance with accounting rules. In September 2023, Cumulus Growth became a subsidiary of Talen Energy Supply, and Talen Energy Supply transferred 100% of its preferred equity interests in Cumulus Compute Holdings to Cumulus Growth. Following such transfer, the preferred equity interests were cancelled.
“Cumulus Data” means Cumulus Data LLC, formerly Susquehanna Data LLC, a direct subsidiary of Cumulus Data Holdings that is developing the Cumulus Data Center Campus.
“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 ASA” means the affiliate services agreement executed in May 2022 between Talen Energy Supply and Cumulus Digital and certain of its subsidiaries. This agreement was terminated in September 2022 in connection with the amendment and restatement of the Cumulus Digital COSA. See Note 12 in Notes to the Annual Financial Statements for additional information.
“Cumulus Digital COSA” means the Corporate and Operational Services Agreement, dated as of September 20, 2021, between Talen Energy Supply and Cumulus Digital, pursuant to which Talen Energy Supply provides corporate, administrative and operational services to Cumulus Digital and its subsidiaries. This agreement was amended and restated in September 2022.
“Cumulus Digital Credit Agreement” means the Credit Agreement, dated as of September 20, 2021, by and among Cumulus Digital and its subsidiaries, Cumulus Digital Holdings and affiliates of Orion, establishing the Cumulus Digital TLF, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time.
“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 Talen Energy Supply 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, Cumulus Digital Holdings became majority-owned by Talen Energy Supply, with minority interests held by Riverstone and Orion. Accordingly, Talen Energy Supply consolidates this entity and its subsidiaries in accordance with accounting rules. At June 30, 2023, Talen Energy Supply owned an 81% equity interest in Cumulus Digital Holdings. Following the closing of the Riverstone Buyout, Talen Energy Supply owns an approximate 95% equity interest in Cumulus Digital Holdings.
“Cumulus Digital TLF” means the Cumulus Digital term loan facility, due September 2027, 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.
G-4
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Cumulus Growth” means Cumulus Growth Holdings LLC, a direct subsidiary of Talen Energy Corporation as of June 30, 2023 that became a direct subsidiary of Talen Energy Supply in September 2023. Prior to September 2022, Cumulus Growth owned common equity interests in Cumulus Digital Holdings. As of June 30, 2023, Cumulus Growth owned 100% of the issued and outstanding common equity interests in Cumulus Renewables Holdings, Cumulus Battery Storage Holdings, Cumulus Compute Holdings, Cumulus Real Estate Holdings and Cumulus PT Energy Transitions Holdings. While Cumulus Growth owned the issued and outstanding common equity in these entities, Talen Energy Supply held voting, convertible preferred equity interests in these entities that, on an as-converted basis, entitled Talen Energy Supply to majority control. In September 2023, Talen Energy Corporation contributed 100% of its common equity interests in Cumulus Growth to Talen Energy Supply, and Talen Energy Supply contributed 100% of its preferred equity interests in the above entities to Cumulus Growth.
“Cumulus PT Energy Transitions Holdings” means Cumulus PT Energy Transitions Holdings LLC, a direct subsidiary of Cumulus Growth. Cumulus PT Energy Transitions Holdings owns a 50% interest in a joint venture entity with Pattern Energy that is intended to hold early-stage development assets prior to the formation of project-specific joint venture entity. Prior to September 2023, Talen Energy Supply held voting, convertible preferred equity units in this entity that provided Talen Energy Supply with a majority equity interest on an as-converted basis. Accordingly, although Cumulus Growth was not a subsidiary of Talen Energy Supply, Talen Energy Supply consolidated Cumulus PT Energy Transitions Holdings and its subsidiaries for financial reporting purposes in accordance with accounting rules. In September 2023, Cumulus Growth became a subsidiary of Talen Energy Supply, and Talen Energy Supply transferred 100% of its preferred equity interests in Cumulus PT Energy Transitions Holdings to Cumulus Growth. Following such transfer, the preferred equity interests were cancelled.
“Cumulus Real Estate Holdings” means Cumulus Real Estate Holdings LLC, a direct subsidiary of Cumulus Growth. Prior to September 2023, Talen Energy Supply held voting, convertible preferred equity units in this entity that provided Talen Energy Supply with a majority equity interest on an as-converted basis. Accordingly, although Cumulus Growth was not a subsidiary of Talen Energy Supply, Talen Energy Supply consolidated Cumulus Real Estate Holdings and its subsidiaries for financial reporting purposes in accordance with accounting rules. In September 2023, Cumulus Growth became a subsidiary of Talen Energy Supply, and Talen Energy Supply transferred 100% of its preferred equity interests in Cumulus Real Estate Holdings to Cumulus Growth. Following such transfer, the preferred equity interests were cancelled.
“Cumulus Renewables Holdings” means Cumulus Renewables Holdings LLC, a direct subsidiary of Cumulus Growth. Prior to September 2023, Talen Energy Supply held voting, convertible preferred equity units in this entity that provided Talen Energy Supply with a majority equity interest on an as-converted basis. Accordingly, although Cumulus Growth was not a subsidiary of Talen Energy Supply, Talen Energy Supply consolidated Cumulus Renewables Holdings and its subsidiaries for financial reporting purposes in accordance with accounting rules. In September 2023, Cumulus Growth became a subsidiary of Talen Energy Supply, and Talen Energy Supply transferred 100% of its preferred equity interests in Cumulus Renewables Holdings to Cumulus Growth. Following such transfer, the preferred equity interests were cancelled.
“Dartmouth” means Dartmouth Power Associates Limited Partnership, an indirect subsidiary of Talen NE LLC that owns and operates a 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 each of Notes to the Interim Financial Statements and 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.
G-5
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“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 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.
“EBITDA” means net income (loss) before interest expense and other finance charges, income taxes, depreciation and certain amortization.
“EGU” means Electric Generating Unit.
“EIS” means the Environmental Impact Statement related to mining permits.
“Emergence” or “Emergence Date” 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 2008 Ozone Standard” means the EPA’s 2008 revision to the 8-hour ozone EPA NAAQS from 84 parts per billion to 75 parts per billion; however, the EPA did not finalize the designations under this new standard until 2012.
“EPA ACE Rule” means the Affordable Clean Energy rule, an EPA emissions guideline that directs states to develop plans that establish standards of performance for carbon dioxide (CO2) emissions from existing coal-fired electricity generating units.
“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 FIPS” means the EPA’s Federal Implementation Plans, which are air quality plans developed by the EPA under certain circumstances to help states or tribes attain and (or) maintain the EPA NAAQS criteria for air pollutants and fulfill other requirements of the Clean Air Act.
“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.
“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.
G-6
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“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 CAA after the application of maximum achievable control technology standards.
“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 ORDC” means ERCOT’s Operating Reserve Demand Curve, which is a market-based construct to value operating reserves in the wholesale electric market based on the scarcity of the resources and reflect that value in wholesale energy prices.
“ERCOT QSE” means the ERCOT Qualified Scheduling Entity, which is responsible for offering and bidding energy in the ERCOT day-ahead and real-time market and settling financially with ERCOT.
“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 H.A. Wagner LLC, an indirect subsidiary of Talen Generation that owns and operates a generation facility in Curtis Bay, Maryland.
“IBEW” means International Brotherhood of Electrical Workers, a labor union.
“IEC” means Interstate Energy Company LLC, a former direct subsidiary of Talen Generation that owned and operated an 84-mile pipeline in Pennsylvania. IEC was sold and merged into an unaffiliated third party in January 2020.
“Indenture” means the Indenture, dated as of May 12, 2023, as supplemented by the First Supplemental Indenture, dated as of May 17, 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 June 30, 2023, the related condensed consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the period from January 1, 2023 through May 17, 2023 (Predecessor) and for the period from May 18, 2023 through June 30, 2023 (Successor), and for the period ended
G-7
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
June 30, 2022, and of cash flows for the Predecessor period, the Successor period, and six-month period ended June 30, 2022, and the related notes.
“ISO” means Independent System Operator.
“Key Capture Energy” means Key Capture Energy, LLC, an unaffiliated third party.
“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 Interim Financial Statements and Note 14 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.
“Kinder Morgan” means Kinder Morgan Tejas Pipeline LLC, an unaffiliated third party.
“KW” means kilowatt, one thousand watts of electric power.
“KWh” means kilowatts of electric power per hour.
“Laredo” means Laredo, LLC, a direct subsidiary of Talen Texas that owns and operates a generation facility in Laredo, Texas.
“LC” means letter of credit.
“LIBOR” means London Interbank Offered Rate.
“LMBE-MC” means LMBE-MC HoldCo II LLC, a direct subsidiary of LMBE-MC Holdco that, through its subsidiaries, owns generation facility operations in Pennsylvania and was the borrower under the LMBE-MC TLB and LMBE-MC RCF.
“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 direct subsidiary of Talen Generation and the parent of LMBE-MC that, through its subsidiaries, owns generation facility operations in Pennsylvania.
“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 Interim 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 Interim Financial Statements for additional information.
“Lower Mt. Bethel” means LMBE Project Company LLC, a direct subsidiary of LMBE-MC that owns and operates a generation facility in Bangor, Pennsylvania.
G-8
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Martins Creek” means MC Project Company LLC, a direct subsidiary of LMBE-MC that owns and operates a 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 Montour, LLC, a direct subsidiary of Talen Generation that owns and operates a generation facility in Washingtonville, Pennsylvania.
“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 June 30, 2023, 75% by Cumulus Coin and 25% by TeraWulf, which owns and operates a cryptomining project on land leased from Cumulus Data at the Cumulus Data Center Campus.
“Nautilus CSA” means the Corporate Services Agreement between Talen Energy Supply and Nautilus, whereby Talen Energy Supply agreed to provide corporate and administrative services to Nautilus. In September 2021, Talen Energy Supply assigned this agreement to Cumulus Digital to provide these services, which are in turn provided to Cumulus Digital by Talen Energy Supply pursuant to the Cumulus Digital COSA.
“Nautilus FOA” means the Facilities Operation Agreement between Nautilus and Talen Energy Supply, whereby Talen Energy Supply 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 to support Nautilus’ ongoing business at the Nautilus facility. Talen Energy Supply 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.
“Nautilus Ground Lease Agreement” means the agreement pursuant to which Nautilus leases land from Cumulus Data on which the Nautilus facility is located, and which also provides for submetering of electricity by Cumulus Data to Nautilus.
“NAV” means net asset value.
“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.
“Newark Bay” means Newark Bay Cogeneration Partnership, L.P., an indirect subsidiary of Talen Generation that owned and operated a generation facility in Newark, New Jersey that was retired in 2022.
G-9
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“NOL” means net operating loss.
“NorthEast Gas Gen” means NorthEast Gas Generation, LLC, a former direct subsidiary of NorthEast Gas Gen Holdco that, through its subsidiaries, owned and operated generation facilities in Massachusetts and New York and held outstanding indebtedness that was non-recourse to Talen. NorthEast Gas Gen and its subsidiaries were deconsolidated by Talen in April 2020. Ownership of NorthEast Gas Gen was transferred from Talen to a third party in December 2020 in connection with NorthEast Gas Gen’s emergence from bankruptcy.
“NorthEast Gas Gen Holdco” means NorthEast Gas Generation Holdings, LLC, a direct subsidiary of Talen NE LLC and the former parent of NorthEast Gas Gen.
“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 Nueces Bay, LLC, a direct subsidiary of Talen Texas that owns and operates a generation facility in Corpus Christi, Texas.
“OCI” means other comprehensive income or loss.
“Orion” means Orion Energy Partners, whose affiliates are 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 CAA 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.
“PA Mines” means Pennsylvania Mines, LLC, a direct subsidiary of Talen Generation.
“PA Mines UMWA Plan VEBA” means a VEBA holding assets for a health plan sponsored by PA Mines for the benefit of retired employees who were members of the UMWA to meet certain requirements under the Coal Act of 1992.
“PA RACT” means Reasonably Available Control Technology, a Pennsylvania pollution control standard created by the PA DEP used to determine what air pollution control technology will be used to control a specific pollutant to a specified limit in order for Pennsylvania to satisfy the EPA NAAQS. PA RACT applies to existing sources in areas that are not meeting national ambient air quality standards on controlled air pollutants and is required on all sources that meet these criteria.
“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
G-10
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
(“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.
“Pedricktown” means Pedricktown Cogeneration Company, LP, an indirect subsidiary of Talen Generation that owned and operated a generation facility in Pedricktown, New Jersey that was retired in 2022.
“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 Maximum Generation Emergency Action” means an action to increase the PJM RTO generation above the maximum economic level. It is implemented whenever generation is needed over what can be economically procured. Following issuance of a PJM Maximum Generation Emergency Action, PJM may purchase available generation from any PJM member (as an emergency) that is available up to the amount required or until available generation is depleted.
“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.
“PPL” means PPL Corporation, the former indirect parent holding company of Talen Energy Supply and Talen Energy Corporation until the Talen Formation Transactions in 2015.
“Predecessor” relates to the financial position or results of operations of Talen Energy Supply for periods prior to Emergence, or May 17, 2023. Recurring references to this period in this document includes the period from January 1, 2023 through May 17, 2023, the six months ended June 30, 2022, December 31, 2022 and June 30, 2022.
“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
G-11
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 Interim Financial Statements and Note 9 in Notes to the Annual Financial Statements for additional information.
“Prepetition LCF-1” means Talen Energy Supply’s prepetition unsecured, bilateral LC facility with Credit Suisse International. Obligations under the Prepetition LCF-1 were guaranteed by the Prepetition Guarantors. The Prepetition LCF-1 expired in June 2023.
“Prepetition LCF-2” means Talen Energy Supply’s prepetition unsecured, bilateral LC facility with Goldman Sachs Bank USA. Obligations under the Prepetition LCF-2 were guaranteed by the Prepetition Guarantors. The Prepetition LCF-2 was terminated in May 2023.
“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 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. 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.
G-12
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
“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.
“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.
“RECs” means Renewable Energy Credits. RECs represent energy produced from renewable energy sources and are purchased to meet renewable energy compliance requirements set by certain state legislatures.
“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.
“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 23 in Notes to the Interim Financial Statements and Note 27 in Notes to the Annual Financial Statements for more 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 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.
G-13
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“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 agreements 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.
“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. Recurring references to this period in this document include the period from May 18, 2023 through June 30, 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.
“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.
G-14
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“Talen Energy Supply” or “TES” means Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation and the parent company of Talen Generation, Susquehanna Nuclear, Talen Montana Holdings, LLC, Talen Energy Marketing, Talen Texas, Talen NE and Cumulus Growth.
“Talen Formation Transactions” means the 2015 spin-off of Talen Energy Corporation from PPL and, simultaneously, the contribution of certain entities by Riverstone creating, at that time, an independent, publicly traded company.
“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 Growth” means Talen II Growth Holdings LLC, an indirect subsidiary of Talen Energy Supply as of June 30, 2023 that was merged into TES in September 2023. Talen Growth owned common equity interests in Cumulus Digital Holdings and, through subsidiaries, previously owned other interests in proposed digital infrastructure, renewable energy and battery storage projects that are currently in the development stage but sold its interests in the proposed projects to subsidiaries of Cumulus Growth in September 2021.
“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.
“Talen NE” means Talen NE LLC, a direct subsidiary of Talen Energy Supply that, through subsidiaries, owns and operates a generation facility in Massachusetts.
“Talen Texas” means Talen Texas, LLC, a direct subsidiary of Talen Energy Supply that, through its subsidiaries, owns and operates generation facilities in Texas.
“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 (Thales) LLC, a Beowulf Energy LLC subsidiary and an unaffiliated third party.
“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 Talen Energy Supply 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 Talen Energy Supply 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.
G-15
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
“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.
“Winter Storm Elliott” means an extra-tropical cyclone occurring in December 2022 that created a storm of snow, rain and wind across the country and had widespread impacts across the United States, which included PJM declaring a PJM Maximum Generation Emergency Action.
“Winter Storm Uri” means a major winter and ice storm occurring in February 2021 that had widespread impacts across the United States, including systemic energy market disruptions and price volatility throughout ERCOT.
G-16
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 and the exchange listing fee.
| Amount | |||||
SEC registration fee | $ | ||||
Exchange listing fee | * | ||||
Printing fees and expenses | * | ||||
Legal fees and expenses | * | ||||
Accounting fees and expenses | * | ||||
Custodian, transfer agent and registrar fees | * | ||||
Other advisors’ fees | * | ||||
Miscellaneous fees and expenses | * | ||||
Total | $ | ||||
__________________
*Estimated expenses of any offerings under this registration statement are not presently known. To the extent required, any applicable prospectus supplement will set forth the estimated aggregate amount of expenses payable in respect of any offering of securities under the registration statement.
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.
II-1
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
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, the Company issued 54,271,201 shares of common stock at a purchase price of $32.00 per share to participating holders for an aggregate purchase price of approximately $1.74 billion, of which (i) 10,378,313 shares of common stock were issued in reliance on the exemption from registration provided in Section 1145 of the Bankruptcy Code and (ii) 43,892,888 shares of common stock were issued in reliance on the exemption from registration provided by Section 4(a)(2) of the Securities Act.
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 three 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.
II-2
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
Item 16. Exhibits and Financial Statement Schedules.
(a)Exhibits.
| Exhibit Number | Description of Exhibit | |||||||
| 3.1* | Third Amended and Restated Certificate of Incorporation of Talen Energy Corporation. | |||||||
| 3.2* | Second Amended and Restated Bylaws of Talen Energy Corporation. | |||||||
| 4.1* | Registration Rights Agreement, dated as of May 17, 2023, by and among Talen Energy Corporation and the undersigned holders party thereto. | |||||||
| 4.2* | Stockholders Agreement, dated as of May 17, 2023, by and among Talen Energy Corporation and the parties identified therein. | |||||||
| 4.3* | Warrant Certificate No. L-1, dated May 17, 2023, issued by Talen Energy Corporation to Leonard LoBiondo. | |||||||
| 5.1* | Opinion of Kirkland & Ellis LLP. | |||||||
| 10.1†* | Credit Agreement, dated May 17, 2023, by and among Talen Energy Supply, LLC, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and Citibank, N.A., BMO Capital Markets Corp., Deutsche Bank Securities Inc., Goldman Sachs Bank USA, RBC Capital Markets, LLC, MUFG Bank, Ltd., Credit Suisse Loan Funding LLC and Morgan Stanley Senior Funding, Inc., as joint lead arrangers and joint bookrunners. | |||||||
| 10.2* | Amendment No. 1 to Credit Agreement, dated as of August 9, 2023, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the persons identified on the signature pages thereto as a 2023-1 Incremental Term B Lender and Citibank N.A., as administrative agent and as collateral agent. | |||||||
| 10.3†* | Letter of Credit Facility Agreement, dated May 17, 2023, by and among Talen Energy Supply, LLC, Barclays Bank PLC, as L/C Issuer and Citibank, N.A., as Collateral Agent. | |||||||
| 10.4* | Indenture, dated May 12, 2023, between Talen Energy Supply, LLC and Wilmington Savings Fund Society, FSB, as trustee. | |||||||
| 10.5* | First Supplemental Indenture, dated as of May 17, 2023, by and among the subsidiary guarantors listed therein, Talen Energy Supply, LLC, the other subsidiary guarantors and Wilmington Savings Fund Society, FSB, as trustee under the Indenture. | |||||||
| 10.6* | Second Supplemental Indenture, dated as of October 6, 2023, by and among the subsidiary guarantors listed therein, Talen Energy Supply, LLC and Wilmington Savings Fund Society, FSB, as trustee under the Indenture. | |||||||
| 10.7†* | Credit Agreement, dated as of September 20, 2021, by and among Cumulus Digital LLC, Cumulus Digital Holdings LLC, the subsidiary guarantors party thereto, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent. | |||||||
| 10.8* | Amendment No. 1 and Waiver No. 1 to Credit Agreement, dated December 30, 2021, by and among Cumulus Digital LLC, Cumulus Digital Holdings LLC, the subsidiary guarantors party thereto, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent. | |||||||
| 10.9* | Amendment No. 2 to Credit Agreement, dated February 11, 2022, by and among Cumulus Digital LLC, Cumulus Digital Holdings LLC, the subsidiary guarantors party thereto, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent. | |||||||
| 10.10†* | Amendment No. 3 and Waiver to Credit Agreement and Amendment No. 1 to Depositary Agreement, dated May 9, 2022, by and among Cumulus Digital LLC, Cumulus Digital Holdings LLC, the subsidiary guarantors party thereto, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent, and MUFG Union Bank, N.A., as depositary bank. | |||||||
| 10.11†* | Omnibus Amendment Agreement, dated September 29, 2022, by and among Cumulus Digital and its subsidiaries, Cumulus Digital Holdings, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent. | |||||||
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
| 10.12†* | Amendment No. 5 to Credit Agreement and Amendment No. 4 to Depositary Agreement, dated May 26, 2023, by and among Cumulus Digital LLC, Cumulus Digital Holdings LLC, the subsidiary guarantors party thereto, the lenders from time to time party thereto, and Orion Energy Partners Investment Agent, LLC, as administrative agent and collateral agent, and U.S. Bank National Association, as depositary bank. | |||||||
| 10.13* | Form of Indemnification Agreement between the Registrant and each of its directors and executive officers. | |||||||
| 10.14+* | 2023 Equity Incentive Plan of Talen Energy Corporation, effective as of May 17, 2023. | |||||||
| 10.15+* | Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement, dated June 16, 2023, by and between Talen Energy Corporation and Mark A. McFarland. | |||||||
| 10.16+* | Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement, dated June 16, 2023, by and between Talen Energy Corporation and Mark A. McFarland. | |||||||
| 10.17+* | Form of Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement (Executive Form). | |||||||
| 10.18+* | Form of Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement (Executive Form). | |||||||
| 10.19+* | Form of Talen Energy Corporation Performance-Based Restricted Stock Unit Award Notice and Award Agreement (Non-Executive Chair Form). | |||||||
| 10.20+* | Form of Talen Energy Corporation Restricted Stock Unit Award Notice and Award Agreement (Non-Employee Director Form). | |||||||
| 10.21#+* | Employment Agreement, dated May 17, 2023, by and between Talen Energy Corporation and Mark A. McFarland. | |||||||
| 10.22#+* | Employment Agreement, effective as of July 10, 2023, by and between Talen Energy Corporation and Terry Nutt. | |||||||
| 10.23#+* | Employment Agreement, dated June 19, 2023, by and between Talen Energy Corporation and John Wander. | |||||||
| 10.24#+* | Employment Agreement, dated June 19, 2023, by and between Talen Energy Corporation and Andrew Wright. | |||||||
| 10.25#+* | Employment Agreement, dated June 26, 2023, by and between Talen Energy Corporation and Brad Berryman. | |||||||
| 10.26#+* | Employment Agreement, dated June 26, 2023, by and between Talen Energy Corporation and Dale Lebsack. | |||||||
| 10.27#+* | Separation Agreement and General Release of Claims, effective as of May 17, 2023, by and between Talen Energy Corporation and Alejandro Hernandez. | |||||||
| 10.28#+* | Separation Agreement and General Release of Claims, effective as of July 7, 2023, by and between Talen Energy Corporation and John Chesser. | |||||||
| 21.1* | List of subsidiaries of Talen Energy Corporation. | |||||||
| 23.1* | Consent of PricewaterhouseCoopers LLC, independent registered public accounting firm. | |||||||
| 23.2* | Consent of Kirkland & Ellis LLP (included in Exhibit 5.1). | |||||||
| 24.1* | Power of Attorney (included on signature page). | |||||||
| 107* | Filing Fee Table | |||||||
__________________
* To be filed by amendment.
†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 private and immaterial portions of the agreement have been redacted pursuant to Item 601(b)(10)(iv) 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.
II-4
Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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.
(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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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 , 2023.
| TALEN ENERGY CORPORATION | |||||
| By: | |||||
| Mark A. McFarland | |||||
| Chief Executive Officer | |||||
POWER OF ATTORNEY
KNOW ALL BY THESE PRESENTS, that each person whose signature appears below hereby constitutes and appoints Mark A. McFarland and Terry L. Nutt and each of them, as his or her true and lawful agents, proxies and attorneys-in-fact, with full power of substitution and re-substitution, for him or her and in his or her name, place and stead, in any and all capacities, to (i) act on, sign and file with the Securities and Exchange Commission any and all amendments (including post-effective amendments) to this registration statement together with all schedules and exhibits thereto and any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, together with all schedules and exhibits thereto, (ii) act on, sign and file such certificates, instruments, agreements and other documents as may be necessary or appropriate in connection therewith, (iii) act on and file any supplement to any prospectus included in this registration statement or any such amendment or any subsequent registration statement filed pursuant to Rule 462(b) under the Securities Act of 1933, as amended, and (iv) take any and all actions which may be necessary or appropriate to be done, as fully for all intents and purposes as he might or could do in person, hereby approving, ratifying and confirming all that such agent, proxy and attorney-in-fact or any of his substitutes may lawfully do or cause to be done by virtue thereof.
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Confidential Treatment Requested by Talen Energy Corporation
Pursuant to 17 C.F.R. Section 200.83
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 | ||||||||||||
Chief Executive Officer and Director (Principal Executive Officer) | ||||||||||||||
| Mark A. McFarland | ||||||||||||||
Chief Financial Officer (Principal Financial Officer) | ||||||||||||||
| Terry Nutt | ||||||||||||||
Chief Accounting Officer (Principal Accounting Officer) | ||||||||||||||
| Tony Plagens | ||||||||||||||
| Chairman of the Board of Directors and Director | ||||||||||||||
| Stephen Schaefer | ||||||||||||||
| Director | ||||||||||||||
| Gizman Abbas | ||||||||||||||
| Director | ||||||||||||||
| Anthony Horton | ||||||||||||||
| Director | ||||||||||||||
| Karen Hyde | ||||||||||||||
| Director | ||||||||||||||
| Joseph Nigro | ||||||||||||||
| Director | ||||||||||||||
| Christine Benson Schwartzstein | ||||||||||||||
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