UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the quarterly period ended March 31, 2025
OR
| TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | |||||
For the transition period from __________ to __________
Commission File Number: 001-37388
(Exact name of registrant as specified in its charter)
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | ||||
(Address of principal executive offices) (Zip Code)
(888 ) 211-6011
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☒ | ☐ | Accelerated filer | ☐ | Non-accelerated filer | Smaller reporting company | Emerging growth company | |||||||||||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐ No ☒
As of May 8, 2025, the registrant had 45,509,780 shares outstanding of common stock, par value $0.001 per share (“common stock”).
TALEN ENERGY CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
TABLE OF CONTENTS
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CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report (this “Report”) contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, and (or) future performance or other events, as well as underlying assumptions and other statements, that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would,” or similar expressions. Although we believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, there can be no assurance that these expectations and assumptions will prove to be correct. Forward-looking statements are subject to many risks and uncertainties. The results, events, or circumstances reflected in forward-looking statements may not be achieved or occur, and actual results, events, or circumstances may differ materially from those discussed in forward-looking statements.
The risks, uncertainties, and other factors that could cause actual results to differ materially from the forward-looking statements made by us include those discussed in this Report, as well as the items discussed in the sections entitled “Item 1A. Risk Factors” in this Report and our most recent Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on the forward-looking statements contained in this Report.
You should not rely on forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Report primarily on our current expectations and assumptions about future events. Furthermore, statements such as “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based on information available to us as of the date of this Report. While we believe such information provides a reasonable basis for these statements, such information may be limited or incomplete, and there can be no assurance that any expectations, assumptions, beliefs, or opinions will prove to be correct. Our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all relevant information. These statements are inherently uncertain, and readers are cautioned not to unduly rely on these statements.
The forward-looking statements made in this Report relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this Report to reflect events or circumstances after the date of this Report or to reflect new information, actual results, revised expectations, or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions, or expectations described in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures, or investments.
MARKET AND INDUSTRY DATA
This Report includes estimates regarding market and industry data. Unless otherwise indicated, information concerning our industry and the markets in which we operate, including our general expectations, market position, market opportunity, and market size, are based on our management’s knowledge and experience in the markets in which we operate, together with currently available information obtained from various sources, including publicly available information, industry reports and publications, surveys, our customers, trade and business organizations, and other contacts in the markets in which we operate. Certain information is based on management estimates, which have been derived from third-party sources, as well as data from our internal research.
In presenting this information, we have made certain assumptions that we believe to be reasonable based on such data and other similar sources and on our knowledge of, and our experience to date in, the markets in which we operate. While we believe the estimated market and industry data included in this Report is generally reliable, such information is inherently uncertain and imprecise. Market and industry data is subject to change and may be limited by the availability of raw data, the voluntary nature of the data gathering process, and other limitations inherent in any statistical survey of such data. In addition, projections, assumptions, and estimates of the future performance of the markets in which we operate are necessarily subject to uncertainty and risk due to a variety of factors, including those described in “Cautionary Note Regarding Forward-Looking Information” as well as the items discussed in the sections entitled “Item 1A. Risk Factors” in this Report and our most recent Annual Report on Form 10-K. 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.
1
PART 1. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
| Three Months Ended March 31, | ||||||||||||||
| (Millions of Dollars, except share data) | 2025 | 2024 | ||||||||||||
| Capacity revenues | $ | $ | ||||||||||||
| Energy and other revenues | ||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 3) | ( | ( | ||||||||||||
| Operating Revenues (Note 4) | ||||||||||||||
| Fuel and energy purchases | ( | ( | ||||||||||||
| Nuclear fuel amortization | ( | ( | ||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 3) | ( | |||||||||||||
| Energy Expenses | ( | ( | ||||||||||||
| Operating Expenses | ||||||||||||||
| Operation, maintenance and development | ( | ( | ||||||||||||
| General and administrative | ( | ( | ||||||||||||
| Depreciation, amortization and accretion (Note 8) | ( | ( | ||||||||||||
| Other operating income (expense), net | ( | |||||||||||||
| Operating Income (Loss) | ( | |||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 7) | ( | |||||||||||||
| Interest expense and other finance charges (Note 11) | ( | ( | ||||||||||||
| Gain (loss) on sale of assets, net (Note 18) | ||||||||||||||
| Other non-operating income (expense), net | ||||||||||||||
| Income (Loss) Before Income Taxes | ( | |||||||||||||
| Income tax benefit (expense) (Note 5) | ( | |||||||||||||
| Net Income (Loss) | ( | |||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | ||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | ( | $ | |||||||||||
| Per Common Share | ||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | ( | $ | |||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | $ | ( | $ | |||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | ||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | ||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
2
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
| Three Months Ended March 31, | ||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||
| Other Comprehensive Income (Loss) | ||||||||||||||
| Available-for-sale securities unrealized gain (loss), net (Note 7) | ||||||||||||||
| Income tax benefit (expense) | ( | |||||||||||||
| Gains (losses) arising during the period, net of tax | ||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net (Note 7) | ( | ( | ||||||||||||
| Postretirement benefit prior service (credits) costs, net (Note 13) | ( | |||||||||||||
| Income tax (benefit) expense | ||||||||||||||
| Reclassifications from AOCI, net of tax | ( | ( | ||||||||||||
| Total Other Comprehensive Income (Loss) | ( | |||||||||||||
| Comprehensive Income (Loss) | ( | |||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | ||||||||||||||
| Comprehensive Income (Loss) Attributable to Stockholders | $ | ( | $ | |||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
3
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| (Millions of Dollars, except share data) | March 31, 2025 | December 31, 2024 | ||||||||||||
| Assets | ||||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Restricted cash and cash equivalents (Note 17) | ||||||||||||||
| Accounts receivable (Note 4) | ||||||||||||||
| Inventory, net (Note 6) | ||||||||||||||
| Derivative instruments (Notes 3 and 12) | ||||||||||||||
| Other current assets | ||||||||||||||
| Total current assets | ||||||||||||||
| Property, plant and equipment, net (Note 8) | ||||||||||||||
| Nuclear decommissioning trust funds (Notes 7 and 12) | ||||||||||||||
| Derivative instruments (Notes 3 and 12) | ||||||||||||||
| Other noncurrent assets | ||||||||||||||
| Total Assets | $ | $ | ||||||||||||
| Liabilities and Equity | ||||||||||||||
| Long-term debt, due within one year (Notes 11 and 12) | $ | $ | ||||||||||||
| Accrued interest | ||||||||||||||
| Accounts payable and other accrued liabilities | ||||||||||||||
| Derivative instruments (Notes 3 and 12) | ||||||||||||||
| Other current liabilities | ||||||||||||||
| Total current liabilities | ||||||||||||||
| Long-term debt (Notes 11 and 12) | ||||||||||||||
| Derivative instruments (Notes 3 and 12) | ||||||||||||||
| Postretirement benefit obligations | ||||||||||||||
| Asset retirement obligations and accrued environmental costs (Note 9) | ||||||||||||||
| Deferred income taxes | ||||||||||||||
| Other noncurrent liabilities | ||||||||||||||
| Total Liabilities | $ | $ | ||||||||||||
| Commitments and Contingencies (Note 10) | ||||||||||||||
| Stockholders' Equity (Note 16) | ||||||||||||||
Common stock ($ | $ | $ | ||||||||||||
| Additional paid-in capital | ||||||||||||||
| Accumulated retained earnings (deficit) | ( | ( | ||||||||||||
| Accumulated other comprehensive income (loss) | ( | ( | ||||||||||||
| Total Stockholders' Equity | ||||||||||||||
| Total Liabilities and Stockholders' Equity | $ | $ | ||||||||||||
__________________
(a)45,509,780 45,961,910
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
4
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| Three Months Ended March 31, | ||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Operating Activities | ||||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||
| Non-cash reconciliation adjustments: | ||||||||||||||
| Unrealized (gains) losses on derivative instruments (Note 3) | ||||||||||||||
| Depreciation, amortization and accretion (Note 17) | ||||||||||||||
| Deferred income taxes | ( | |||||||||||||
| Nuclear fuel amortization (Note 8) | ||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) (Note 7) | ( | |||||||||||||
| (Gain) loss on AWS Data Campus Sale (Note 18) | ( | |||||||||||||
| Other (Note 17) | ( | |||||||||||||
| Changes in assets and liabilities: | ||||||||||||||
| Accounts receivable | ||||||||||||||
| Inventory, net | ||||||||||||||
| Other assets | ( | |||||||||||||
| Accounts payable and accrued liabilities | ( | ( | ||||||||||||
| Accrued interest | ||||||||||||||
| Collateral received (posted), net | ( | |||||||||||||
| Other liabilities | ( | |||||||||||||
| Net cash provided by (used in) operating activities | ||||||||||||||
| Investing Activities | ||||||||||||||
| Nuclear decommissioning trust funds investment purchases (Note 7) | ( | ( | ||||||||||||
| Nuclear decommissioning trust funds investment sale proceeds (Note 7) | ||||||||||||||
| Nuclear fuel expenditures (Note 8) | ( | ( | ||||||||||||
| Property, plant and equipment expenditures (Note 8) | ( | ( | ||||||||||||
| Proceeds from AWS Data Campus Sale (Note 18) | ||||||||||||||
| Other | ||||||||||||||
| Net cash provided by (used in) investing activities | ( | |||||||||||||
| Financing Activities | ||||||||||||||
| Share repurchases (Note 16) | ( | ( | ||||||||||||
| Deferred financing costs | ( | |||||||||||||
| Debt repayments (Note 11) | ( | ( | ||||||||||||
| Cumulus Digital TLF repayment | ( | |||||||||||||
| Repurchase of noncontrolling interest | ( | |||||||||||||
| Other | ( | |||||||||||||
| Net cash provided by (used in) financing activities | ( | ( | ||||||||||||
| Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents | ( | |||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | ||||||||||||||
| End of period cash and cash equivalents and restricted cash and cash equivalents | $ | $ | ||||||||||||
See Note 17 for supplemental cash flow information.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
5
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Treasury Stock | Non controlling Interest | Total Equity | |||||||||||||||||||||||||||||||||||||
| December 31, 2024 | $ | $ | ( | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | ( | — | — | — | ( | |||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||
| Retirement of treasury stock | — | ( | ( | — | — | |||||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| March 31, 2025 | $ | $ | ( | $ | ( | $ | $ | $ | ||||||||||||||||||||||||||||||||||||
| December 31, 2023 | $ | $ | $ | ( | $ | — | $ | $ | ||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | ( | — | — | ( | |||||||||||||||||||||||||||||||||||||
| Share repurchases | ( | — | — | — | ( | — | ( | |||||||||||||||||||||||||||||||||||||
Purchase of noncontrolling interest (b) | — | ( | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||
| Cash distributions | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||
Non-cash distributions (c) | — | — | — | — | — | ( | ( | |||||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||
| March 31, 2024 | $ | $ | $ | ( | $ | ( | $ | $ | ||||||||||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Relates to the purchase of remaining equity in Cumulus Digital held by Orion Energy Partners and two former member of Talen senior management.
(c)Relates to distributions of Bitcoin to TeraWulf.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
6
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.
“TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. The terms “Talen, the “Company,” “we,” “us,” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary.
1. Organization and Operations
Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 10.7 gigawatts of power infrastructure in the United States, including 2.2 gigawatts of nuclear power and a significant dispatchable generation fleet. We produce and sell electricity, capacity, and ancillary services into wholesale U.S. power markets, with our generation fleet principally located in the Mid-Atlantic and Montana. Talen is headquartered in Houston, Texas.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
These Interim Financial Statements, which are prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q, include: (i) the accounts of all controlled subsidiaries; (ii) elimination adjustments for intercompany transactions between controlled subsidiaries; (iii) any undivided interests in jointly owned facilities consolidated on a proportionate basis; and (iv) all adjustments considered necessary for a fair presentation of the information set forth. All adjustments are of a normal recurring nature except as otherwise disclosed. Certain information and note disclosures have been condensed or omitted from the Interim Financial Statements in accordance with GAAP. The Interim Financial Statements and Notes thereto should be read in conjunction with the Annual Financial Statements and Notes thereto. The results of operations presented in our Interim Financial Statements are not necessarily indicative of the results to be expected for the full year or for other future periods because interim period results can be disproportionately influenced by operational developments, seasonality, and various other factors.
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.
See Note 2 to the Annual Financial Statements for additional information on significant accounting policies.
3. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk, and interest rate risk. The hedging strategies deployed by our commercial and treasury organizations manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors, including the risk committee, and management have established procedures to monitor, measure, and manage hedging activities and credit risk in accordance with the risk policy.
7
Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk, and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future earnings and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products, and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: (i) seasonal changes in demand; (ii) weather conditions; (iii) available regional load-serving supply; (iv) regional transportation and (or) transmission availability; (v) market liquidity; and (vi) federal, regional, and state regulations.
Within the parameters of our risk policy, we generally utilize exchange-traded and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives range in maturity through 2027. The net notional volumes of open commodity derivatives were:
March 31, 2025 (a) | December 31, 2024 (a) | |||||||||||||
| Power (MWh) | ( | ( | ||||||||||||
| Natural gas (MMBtu) | ||||||||||||||
| Emission allowances (tons) | ||||||||||||||
__________________
(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 mature in 2026 and 2029. The net notional volumes of open interest rate derivatives were:
| March 31, 2025 | December 31, 2024 | |||||||||||||
Interest rate (in millions) | $ | $ | ||||||||||||
Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty, or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, accounts receivable, and derivative instruments. The maximum amount of credit exposure associated with financial assets is equal to the carrying value of such assets. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default, and executing master netting arrangements that permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, LCs, and credit insurance may be employed to mitigate credit risk.
Cash and cash equivalents are placed in depository accounts or high-quality, short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity, and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of March 31, 2025 and December 31, 2024.
As of March 31, 2025, Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $453 million and its credit exposure including such netting effects was $53 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements and congestion products are subject to applicable market controls, the ten largest single net credit exposures account for 90 % of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
8
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, LCs, or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in Talen’s credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of March 31, 2025 and December 31, 2024.
Derivative Instrument Presentation
Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | |||||||||||||||||||||||
| Commodity contracts | $ | $ | $ | $ | ||||||||||||||||||||||
| Interest rate contracts | ||||||||||||||||||||||||||
| Total current derivative instruments | ||||||||||||||||||||||||||
| Commodity contracts | ||||||||||||||||||||||||||
| Interest rate contracts | ||||||||||||||||||||||||||
| Total non-current derivative instruments | $ | $ | $ | $ | ||||||||||||||||||||||
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy and other revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. See Note 12 for additional information on fair value. Changes in the fair value and realized settlements on interest rate derivative instruments are presented as “Interest expense and other finance charges” on the Consolidated Statements of Operations.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of March 31, 2025 and December 31, 2024.
The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:
| Gross Derivative Instruments | Eligible for Offset | Net Derivative Instruments | Collateral (Posted) Received | Net Amounts | ||||||||||||||||||||||||||||
| March 31, 2025 | ||||||||||||||||||||||||||||||||
| Assets | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||
| Liabilities | ( | ( | ||||||||||||||||||||||||||||||
| December 31, 2024 | ||||||||||||||||||||||||||||||||
| Assets | $ | $ | ( | $ | $ | ( | $ | |||||||||||||||||||||||||
| Liabilities | ( | ( | ||||||||||||||||||||||||||||||
Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Realized gain (loss) on commodity contracts | ||||||||||||||
Energy revenues (a) | $ | ( | $ | |||||||||||
Fuel and energy purchases (a) | ||||||||||||||
| Unrealized gain (loss) on commodity contracts | ||||||||||||||
Operating revenues (b) | ( | ( | ||||||||||||
Energy expenses (b) | ( | |||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | ||||||||||||||
| Interest expense and other finance charges | ( | |||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.
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4. Revenue
The components of operating revenues for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Capacity revenues | $ | $ | ||||||||||||
| Electricity sales and ancillary services, ISO/RTO | ||||||||||||||
| Physical electricity sales, bilateral contracts, other | ||||||||||||||
| Other revenue from customers | ||||||||||||||
| Total revenue from contracts with customers | ||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | ( | |||||||||||||
| Nuclear PTC | ||||||||||||||
| Other revenue | ||||||||||||||
| Operating revenues | $ | $ | ||||||||||||
Accounts Receivable
“Accounts receivable” presented on the Consolidated Balance Sheets were:
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Customer accounts receivable | $ | $ | ||||||||||||
| Other accounts receivable | ||||||||||||||
| Accounts receivable | $ | $ | ||||||||||||
During the three months ended March 31, 2025 and 2024, there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 3 for additional information on Talen’s credit risk on the carrying value of its receivables.
Future Performance Obligations
In the normal course of business, Talen has future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements.
As of March 31, 2025, the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
2025 (a) | 2026 (b) | 2027 | 2028 | 2029 | ||||||||||||||||||||||||||||
| Expected capacity revenues | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||
__________________
(a)Estimated for the period from April 1, 2025 through December 31, 2025.
No PJM BRAs have been held since the 2025/2026 PJM BRA. The 2026/2027 PJM BRA has been postponed to July 2025. See Note 10 for additional information on the PJM BRAs.
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5. Income Taxes
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Income (loss) before income taxes | $ | ( | $ | |||||||||||
| Income tax benefit (expense) | ( | |||||||||||||
| Effective tax rate | % | % | ||||||||||||
| Federal income tax statutory tax rate | % | % | ||||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | $ | $ | ( | |||||||||||
| Income tax increase (decrease) due to: | ||||||||||||||
| Other permanent differences | ||||||||||||||
| State income taxes, net of federal benefit | ( | |||||||||||||
| NDT taxes | ( | |||||||||||||
| Change in valuation allowance | ||||||||||||||
| Nuclear PTC | ||||||||||||||
| Income tax benefit (expense) | $ | $ | ( | |||||||||||
6. Inventory
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Coal | $ | $ | ||||||||||||
| Oil products | ||||||||||||||
| Fuel inventory for electric generation | ||||||||||||||
| Materials and supplies, net | ||||||||||||||
| Environmental products | ||||||||||||||
| Inventory, net | $ | $ | ||||||||||||
7. Nuclear Decommissioning Trust Funds
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | |||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | — | $ | — | $ | $ | $ | — | $ | — | $ | ||||||||||||||||||||||||||||||||||||||
| Equity securities | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Debt securities | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
| NDT Funds | $ | $ | $ | ( | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||
See Note 12 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of March 31, 2025 and December 31, 2024.
As of March 31, 2025, there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate fair value of available-for-sale debt securities with unrealized losses as of March 31, 2025 were:
| Fair Value | Unrealized Losses | |||||||||||||
| Corporate debt securities | $ | $ | ( | |||||||||||
| Municipal debt securities | ( | |||||||||||||
| U.S. Government debt securities | ( | |||||||||||||
| Debt securities in unrealized loss position | $ | $ | ( | |||||||||||
As of March 31, 2025, the aggregate fair value of debt securities in a loss position for a duration of one year or longer were $42 million and the unrealized losses were non-material.
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The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Maturities within one year | $ | $ | ||||||||||||
| Maturities within two to five years | ||||||||||||||
| Maturities thereafter | ||||||||||||||
| Debt securities, fair value | $ | $ | ||||||||||||
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
Sales proceeds of NDT funds investments (a) | $ | $ | ||||||||||||
| Gross realized gains | ||||||||||||||
| Gross realized losses | ( | ( | ||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.
8. Property, Plant and Equipment
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (years) | Gross Value | Accumulated Depreciation | Carrying Value | Gross Value | Accumulated Depreciation | Carrying Value | ||||||||||||||||||||||||||||||||||||||
| Electric generation | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
| Nuclear fuel | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Other property and equipment | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Capitalized software | ( | ( | ||||||||||||||||||||||||||||||||||||||||||
| Construction work in progress | — | — | ||||||||||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | $ | ( | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||
The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
Depreciation expense (a) | $ | $ | ||||||||||||
Amortization expense (b) | ||||||||||||||
Accretion expense (c) | ||||||||||||||
| Depreciation, amortization and accretion | $ | $ | ||||||||||||
__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 9 for additional information.
The cost of nuclear fuel and the amortization of nuclear fuel intangible assets are presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Reliability Impact Assessments
Brandon Shores and H.A. Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A. Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules (the “CORS”). On May 1, 2025, the FERC approved the terms under which Talen will operate these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. Beginning June 1, 2025, the CORS will provide an annual fixed-cost payment of $145 million ($312 /MWd) for Brandon Shores and $35 million ($137 /MWd) for H.A. Wagner, which includes a performance “hold back” of $5 million per year for Brandon Shores and $2 million per year for H.A. Wagner, each to be paid out based on unit performance. We will also receive separate reimbursement for variable costs and approved project investments.
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9. Asset Retirement Obligations and Accrued Environmental Costs
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Asset retirement obligations | $ | $ | ||||||||||||
| Accrued environmental costs | ||||||||||||||
| Total asset retirement obligations and accrued environmental costs | ||||||||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | ||||||||||||||
| Asset retirement obligations and accrued environmental costs due after one year | $ | $ | ||||||||||||
__________________
(a)Presented as “” on the Consolidated Balance Sheets.
Asset Retirement Obligations
Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation, 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 (which the NDT is expected to fund) and coal ash disposal units associated with legacy coal-fired generation facilities (for which the Company has posted surety bonds and letters of credit 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 carrying value of AROs associated with legacy coal-fired generation facilities may be impacted by current or future EPA rulemaking. Additionally, as of March 31, 2025, the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined. See Note 10 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work.
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 period were:
| December 31, 2024 | $ | |||||||
| Obligations settled | ( | |||||||
| Accretion expense | ||||||||
| March 31, 2025 | $ | |||||||
Supplemental information for the ARO:
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Supplemental Information | ||||||||||||||
Nuclear (a) | $ | $ | ||||||||||||
Non-Nuclear (b) | ||||||||||||||
| Carrying value | $ | $ | ||||||||||||
__________________
(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 12 for additional information on the NDT.
(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.
As a result of environmental regulations issued by the EPA or other rule-making entities, the Company may be required to revise and (or) recognize new AROs. See “Environmental Matters” in Note 10 for additional information. See “Talen Montana Financial Assurance” in Note 10 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip.
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10. Commitments and Contingencies
Legal, Regulatory, and Environmental Matters
We are regularly subject to various legal, regulatory, and environmental matters in connection with our business. While we believe we have meritorious positions and will continue to vigorously defend our positions in these matters, we may not be successful in our efforts, and we cannot predict the effect of an adverse outcome of any such matter. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal, regulatory, and environmental matters and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding any matter specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial. Unless otherwise disclosed below, we are unable to predict the outcome of any matter discussed below or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that the outcome of any such matter, including market modifications, could materially impact our business, financial condition, results of operations, cash flows, and (or) liquidity.
Legal Matters
We are involved in various legal and administrative proceedings, investigations, claims, and litigation from time to time in the course of our business. Such matters may include, but are not limited to, those relating to employment and benefits, commercial disputes, personal injury, property damage, regulatory matters, environmental matters, and various other claims for injuries and (or) damages. While we believe we have meritorious positions and will continue to appropriately respond to all legal matters, because of the inherently unpredictable nature of legal proceedings, there is a wide range of potential outcomes for any such matter.
Brunner Island CCR Litigation. On April 2, 2025, the Center for Biological Diversity (the “CBD”) filed a citizen suit in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, have failed to comply with groundwater monitoring and corrective action requirements at Brunner Island’s Ash Basin 5 and have therefore violated the Resource Conservation and Recovery Act (“RCRA”) and the EPA CCR Rule. The complaint seeks declaratory and injunctive relief. Talen believes the alleged claims are without merit and that the CBD’s factual and legal conclusions are incorrect. At this time, no assurance can be provided as to the outcome of the litigation or its impacts on Talen’s operations.
ERCOT Weather Event (Winter Storm Uri) Lawsuits. In connection with the ERCOT Sale, the Company retained certain potential liabilities relating to claims filed from 2021 onward against its former Texas subsidiaries seeking unspecified damages for alleged losses caused by the defendants’ failure to provide sufficient power to the grid during Winter Storm Uri. The claims also allege similar liability against numerous other ERCOT power market participants. In December 2023, five multi-district litigation (“MDL”) bellwether lawsuits, which were selected by the MDL court as representative of all 58 cases filed in the Uri litigation, were dismissed by the MDL court, a ruling subsequently upheld by the Texas First Court of Appeals. In January and February 2025, the plaintiffs (in two
Regulatory Matters
We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to FERC; the Department of Energy; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. Accordingly, we are subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules.
14
PJM Capacity Market Reform. In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order for PJM to propose market reforms. PJM filed its market reform proposals with FERC in October 2023. In early 2024, FERC accepted portions of PJM’s proposed market changes. PJM held the PJM BRA for the 2025/2026 PJM Capacity Year in July 2024 which incorporated the FERC accepted changes. The PJM BRAs for the 2026/2027, 2027/2028, and 2028/2029 PJM Capacity Years were previously scheduled for December 2024, June 2025 (later changed to July 2025), and December 2025, respectively; however in September 2024, the Sierra Club and other organizations filed a complaint at FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by RMR resources and seeking to delay the 2026/2027 PJM BRA pending resolution of its complaint. In October 2024, PJM announced it had concerns about FERC considering the Sierra Club’s complaints about RMR resources in isolation and therefore intended to file a Section 205 proceeding under the Federal Power Act seeking FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatment of RMR resources. As a result, in October 2024 PJM formally requested that FERC approve six-month delays in the PJM BRAs for the 2026/2027, 2027/2028, 2028/2029, and 2029/2030 PJM Capacity Years and in November 2024, FERC approved the auction delays. The planning parameters for the 2026/2027 PJM BRA were issued in March 2025. Talen can provide no assurance that the four scheduled auctions will be held as scheduled or at all.
A series of filings aimed at reforming the PJM capacity market were filed at FERC. In November 2024, the Joint Consumer Advocates, comprised of consumer advocacy groups and government entities from Illinois, Maryland, New Jersey, Ohio, and the District of Columbia filed a complaint against PJM asking FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and issue an order requiring certain short-term and longer-term changes to PJM’s capacity market rules.
In response, PJM made two FERC filings in December 2024 to address what they perceive as capacity market design issues (the “PJM Capacity Market 205 Proceeding”). PJM proposed to retain the dual fuel combustion turbine as the reference resource and to implement a uniform non-performance charge throughout the RTO for the 2026/2027 and 2027/2028 delivery years, and to administratively include RMR units that meet certain criteria as price takers in the capacity auctions for the next delivery years and will not assess penalties or pay bonuses to these RMR units. PJM’s filing also clarifies that being excused from being required to offer into the capacity market is no defense to exercising market power by electing not to offer. Further, PJM proposed to make changes to the capacity market mitigation rules. This proposal will eliminate the must-offer exception for intermittent and limited duration resources that are eligible to participate in the capacity market and will allow market sellers to incorporate a risk component in their capacity market offers. In February 2025, FERC accepted PJM’s proposals in the PJM Capacity Market 205 Proceeding and as a result, the changes to the PJM BRA parameters described above as part of that proceeding will be adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.
Following the above filings, in December 2024, the Pennsylvania Governor filed a complaint against PJM at FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 delivery years. Among other things, the Governor’s complaint proposed to lower the capacity price cap and reopen the closed interconnection queue to get new projects online. In January 2025, the Governor filed a motion to consolidate his complaint with the Joint Consumer Advocates complaint and two PJM filings referenced above. On January 28, 2025, the Governor and PJM announced they had reached an agreement to resolve the Governor’s complaint. That agreement would impose a collar on the capacity prices in the 2026/2027 and 2027/2028 PJM BRAs, with a minimum capacity price of $175 /MWd and a maximum price of $325 /MWd. On February 14, 2025, the Pennsylvania Governor withdrew the complaint at FERC as a result of the agreement with PJM. In April 2025, FERC accepted PJM’s proposals on a new PJM Capacity Market 205 Proceeding and, as a result, the changes to the PJM BRA parameters imposing the collar will be adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.
On February 20, 2025, FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings to take place on June 4 and 5, 2025. The Company has intervened in the new technical conference docket and intends to participate in those proceedings.
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 substances and solid waste management. From time to time, in the ordinary course of our business, Talen may be: (i) subject to environmental remediation work at its facilities; (ii) involved in other environmental matters; or (iii) become subject to other, new or revised environmental statutes, regulations, or requirements. It may be necessary for us to modify, curtail, replace, or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations, and other requirements imposed by regulatory bodies, courts, or environmental groups. We may incur significant costs to comply with these requirements, including increased capital expenditures or operation and maintenance expenses, monetary fines, remediation costs, penalties, or other restrictions. Legal challenges to environmental rules or permits add to the uncertainty of estimating future compliance costs. In addition, in January 2025, President Trump issued executive orders directing the heads of all federal agencies to identify and begin the processes to suspend, revise, or rescind all agency actions, including existing regulations, that are unduly burdensome on the identification, development, or use of domestic energy resources. Consequently, in March 2025, the EPA announced that it will reconsider and potentially roll back 31 regulations and policies, many of which directly impact Talen, and various executive actions were taken in April 2025 to further encourage deregulation. However, future provisions, implementation, and enforcement of these executive actions and the environmental rules remains uncertain at this time. Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed in other ways.
15
EPA CSAPR and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA revised the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”). This action triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (the “Good Neighbor Plan”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey were subject to the new rule; however, the entire rule was challenged by multiple parties, and subsequently the Good Neighbor Plan was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the D.C. Circuit Court of Appeals. In November 2024, the EPA issued an interim final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive Revised CSAPR Update Rule until the Good Neighbor Plan matter is resolved. After initially denying EPA’s request in February 2025, on April 14, 2025 the D.C. Circuit Court of Appeals granted the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance pending the EPA’s review of the stayed rule and further orders by the court. As a result, future implementation and enforcement of the Good Neighbor Plan remains uncertain at this time.
EPA MATS Rule. In May 2024, the EPA published a rule that requires coal-fired generation facilities to reduce particulate matter emissions by the middle of 2027 (or 2028, if an extension is approved). Colstrip is not expected to meet the new particulate matter standard without substantial upgrades to its control equipment. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility. Such decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA GHG Rule due to timing and costs. Challenges to the EPA MATS Rule have been filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. After motions to stay the EPA MATS Rule during the pendency of the litigation were denied by the D.C. Circuit Court of Appeals, Talen and other parties filed emergency stay request applications with the U.S. Supreme Court in September 2024, which were denied in October 2024. The appeal on the merits of the new rule remains pending in the D.C. Circuit Court of Appeals. In February 2025, the D.C. Circuit Court of Appeals granted the EPA’s unopposed motion to hold the MATS litigation in abeyance for 90 days. No assurance can be provided as to when the challenges to the EPA MATS Rule will be resolved or whether such challenges will be resolved in the Company’s favor.
In March 2025, the EPA announced that it was reconsidering the EPA MATS Rule as part of its deregulation agenda. Concurrently, the Trump administration announced it was considering a two-year exemption from compliance obligations via Section 112(i)(4) of the Clean Air Act for affected power plants while the EPA reconsiders the rule. Talen applied for the exemption and received official notification that the request had been granted on April 14, 2025. This authorization affords more time for the Colstrip owners to consider the operational future of Colstrip. Anticipating the authorization will be the subject of legal challenges, and the EPA’s regulatory reconsideration will take time and could also be challenged in court, the Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on related litigation outcomes. In May 2025, the EPA submitted an EPA MATS Rule repeal proposal to the White House Office of Management and Budget.
EPA GHG Rule. In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and GHG guidelines for certain existing EGUs. Under the guidelines, if existing coal-fired EGUs operate beyond 2031, GHG reductions, such as those achieved by the addition of carbon capture and sequestration (“CCS”), are required to be implemented by the end of 2031. Colstrip is not expected to meet the new rules without substantial technology upgrades and pipeline infrastructure build-out. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive controls (e.g., CCS technology) or retire the Colstrip facility by the end of 2031. Such a decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule. Petitions have been filed in the D.C. Circuit Court of Appeals, including by coalitions representing 27 states and an ad hoc coalition of power producers of which Talen is a member, requesting a review of the EPA GHG Rule. Stay motions were denied by the D.C. Circuit Court of Appeals in July 2024 and the U.S. Supreme Court in October 2024. Appeals of the EPA GHG Rule remain pending in the D.C. Circuit Court of Appeals.
In February 2025, the D.C. Circuit Court of Appeals granted the EPA’s unopposed motion to hold the litigation in abeyance for 60 days, and the EPA filed another unopposed motion in April 2025 to extend the litigation abeyance while it reconsiders the rule, which the court granted. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. Additionally, the EPA has formally announced it will reconsider the EPA GHG Rule. According to the EPA’s website, the EPA intends to issue a proposed reconsideration rule in the Spring of 2025 and a final rule by December 2025. In May 2025, the EPA sent a proposal to the White House Office of Management and Budget to repeal the EPA GHG Rule.The EPA has also in the past stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed and no recent statements have been made. Operating decisions about the future of Colstrip are highly dependent on the fate of the EPA GHG Rule as well as the EPA MATS Rule. Given the legal and regulatory uncertainties with both rules, it is possible the Company will be required to make decisions about Colstrip’s future before it has clarity about the outcome of litigation and (or) the EPA’s regulatory reconsideration.
16
Pennsylvania RGGI. In October 2019, the then-Governor of Pennsylvania signed an executive order directing the Pennsylvania Department of Environmental Protection (the “PADEP”) to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, in November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PADEP appealed this decision to the Pennsylvania Supreme Court and filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups to intervene in the case. The litigation is ongoing.
EPA ELG Rule. In November 2015, the EPA revised the effluent limitation guidelines for certain power generation facilities, which imposed more stringent standards for wastewater streams as facility discharge permits are renewed. In 2020, the EPA issued changes that would exempt coal generation facility operators from meeting certain wastewater standards if the facility would commit to cease coal-fired generation by the end of 2028, which Talen elected for its wholly owned coal operations. In May 2024, the EPA published revisions to the EPA ELG Rule, which imposed additional requirements for legacy wastewater and combustion residual leachate. These revisions impact Talen’s active generation facilities that have both CCR units and hold National Pollutant Discharge Elimination System (“NPDES”) discharge permits. These sites include Brandon Shores, Brunner Island, Montour, and potentially Martins Creek. Talen is evaluating what: (i) potential discharge limits may apply; (ii) treatment may be required; and (iii) the implementation timeline may be. Obligations for installing any new wastewater treatment equipment, if necessary, will not be known until each applicable state where the active generation facilities operate makes its own determination with respect to NPDES permit renewals with new limits and associated timing. As a result of the future permit conditions, additional capital expenditures and (or) AROs may be required, which may have a material impact on Talen’s operations and (or) financial condition.
Multiple challenges, including stay requests, to the EPA ELG Rule have been filed in various U.S. Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group, of which Talen is a member. The appeals have been consolidated in the U.S. Court of Appeals for the Eighth Circuit, which denied requests to stay the rule in October 2024. In February 2025, the Eighth Circuit granted the EPA’s motion to hold the consolidated challenges in abeyance for 60 days while it reconsiders the rule. In March 2025, the EPA announced that it will revise the EPA ELG Rule as part of its deregulation agenda while considering immediate relief from some of the existing leachate requirements. No assurance can be provided as to what changes will come from the EPA’s regulatory reconsideration of the rule, when the challenges to the EPA ELG Rule merits will be resolved, or whether such changes and challenges will be resolved in the Company’s favor.
EPA CCR Rule. In April 2015, the EPA established regulations under the RCRA to identify CCRs as nonhazardous solid waste and provided CCR management and siting requirements. The 2015 rule was modified in 2020 after a 2018 D.C. Circuit Court of Appeals ruling found that, among other things, the EPA did not adequately regulate unlined impoundments. In its 2020 rulemaking, the EPA specified procedures for owners to extend the operating timeline of certain unlined impoundments. Talen submitted an extension request under this process for an unlined impoundment at Montour, which was withdrawn in December 2024, following the end of basin operations and the initiation of basin closure. The 2018 D.C. Circuit Court of Appeals ruling also found that the EPA did not properly address legacy surface impoundments in the 2015 CCR rule. As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations effective in November 2024 (the “Legacy CCR Rule”), which provided new requirements for legacy CCR surface impoundments and new requirements for other CCR disposal and management areas at active power plants (“CCR Management Units” or “CCRMUs”). This rule has been challenged in the D.C. Circuit Court of Appeals by multiple parties, including two industry groups of which Talen is a member. In December 2024, the U.S. Supreme Court denied a requested stay of the Legacy CCR Rule. In February 2025, the D.C Circuit Court of Appeals granted the EPA’s unopposed motion to hold the litigation in abeyance for 120 days. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs. In March 2025, the EPA announced that it will prioritize the coal ash program by expediting state permit reviews and complete a rule change within a year. No assurance can be provided at this time as to when and how the regulations will change, when the legal challenges to the Legacy CCR Rule and the EPA’s interpretations will be resolved, or whether such challenges will be decided in the Company’s favor.
Talen continues to review the new Legacy CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional information and guidance from the EPA concerning the rule’s requirements. Pursuant to the regulations, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are due in February 2026. Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2027. The Company has initiated reviews under the facility evaluation report requirements at locations with ash impoundments that have long since ceased coal operations as well as at locations with current coal operations. No assurance can be provided as to whether any specific ash impoundments owned by the Company may or may not be within scope of the updated Legacy CCR Rule until the Company completes its assessments within the regulatory timeframe.
17
As of March 31, 2025, the Company has identified required cost estimates in order to comply with the Legacy CCR Rule’s initial compliance requirements and deadlines, including the initial groundwater monitoring requirements. The Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on Talen’s operations and (or) financial condition.
In April 2025, a citizen suit was filed in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, are in violation of RCRA and the EPA CCR Rule. See the “Legal Matters” section above for additional information.
Certain Resolved Matters
See Note 12 to the Annual Financial Statements for certain legal matters previously resolved.
Guarantees and Other Assurances
In the normal course of business, the Company enters into agreements to provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the stand-alone creditworthiness attributed to a subsidiary or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs, and (or) surety bonds. Additionally, they may include customary indemnifications to third parties related to asset sales and other transactions. The probability of expected material payment and (or) performance for these assurance agreements is believed to be remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain Company subsidiaries for obligations including but not limited to environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any particular surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers. As of March 31, 2025 and December 31, 2024, the aggregate amount of surety bonds outstanding was $238 million and $234 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below.
Talen Montana Financial Assurance. Pursuant to the Colstrip Administrative Order on Consent (the “Colstrip AOC”), Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (the “MDEQ”) on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities was $114 million and $125 million as of March 31, 2025 and December 31, 2024, respectively. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions, and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements are expected to decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed. See Note 9 for additional information on Colstrip AROs.
Other Commitments and Contingencies
Talen Montana Fuel Supply. Talen Montana purchases coal from a mine owned by Westmoreland Rosebud Mining, LLC (the “Rosebud Mine”) for its interest in Colstrip Units 3 and 4 under a full requirements contract with the mine operator. Two lawsuits have been brought against the Rosebud Mine challenging permits issued to it by the State of Montana. Talen Montana is not party to either lawsuit but is monitoring the progress of each to assess the impact to its operations. In the first lawsuit, the Montana Supreme Court affirmed a lower court’s ruling to vacate a mining permit and require the Montana Board of Environmental Review to perform an additional review of the permit. In the second lawsuit, the Montana Federal District Court ordered a branch of the U.S. Department of the Interior to complete an updated Environmental Impact Statement (“EIS”). In December 2024, the Montana Federal District Court granted an extension to the EIS completion date to October 7, 2025. At this time, Talen cannot predict the effect that an adverse outcome of these lawsuits to Rosebud Mine would have on: (i) Talen Montana’s ability to source fuel for its share of Colstrip operations; or (ii) Talen Montana’s operations, results of operations, or liquidity.
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11. Long-Term Debt and Other Credit Facilities
TES is the borrower/issuer under all the Company’s debt and credit facilities. As of March 31, 2025, TES was not in default under any of its debt or credit agreements.
Long-Term Debt
Interest Rate (a) | March 31, 2025 | December 31, 2024 | ||||||||||||||||||
TLB-1 | $ | $ | ||||||||||||||||||
| TLB-2 | ||||||||||||||||||||
| Secured Notes | ||||||||||||||||||||
PEDFA 2009B Bonds | ||||||||||||||||||||
PEDFA 2009C Bonds | ||||||||||||||||||||
| Total principal | ||||||||||||||||||||
| Unamortized deferred financing costs and original issuance discounts | ( | ( | ||||||||||||||||||
| Total carrying value | ||||||||||||||||||||
| Less: long-term debt, due within one year | ||||||||||||||||||||
| Long-term debt | $ | $ | ||||||||||||||||||
__________________
(a)Computed interest rate as of March 31, 2025.
Long-term debt maturities as of March 31, 2025 were:
2025 (a) | 2026 | 2027 | 2028 | 2029 | Thereafter | Total | ||||||||||||||||||||||||||||||||||||||
| Principal debt maturities | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||
__________________
(a)For the period from April 1 through December 31, 2025.
Revolving Credit and Other Facilities
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Maturity | Committed Capacity (a) | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | |||||||||||||||||||||||||||||||||||||||||||
RCF | December 2029 | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||
| LCF | December 2026 | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs. Direct cash borrowings are not permitted under the LCF, which can only be used for LCs.
In December 2024, the TLC LCF and Bilateral LCF were terminated. However, as certain LCs remained outstanding under these facilities pending their transition to the LCF, corresponding backstop LCs were issued under the LCF. As of March 31, 2025 and December 31, 2024, the amounts of such backstop LCs issued under the LCF were $81 million and $297 million, respectively (which are included in the totals above).
Recent Transactions
Secured Notes. In January 2025, the Indenture governing the Secured Notes was amended to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in the December 2024 transactions discussed in Note 13 to the Annual Financial Statements; and (ii) waive TES’s right to optionally redeem up to 10 % of the Secured Notes at a price of 103 % of par prior to June 1, 2025.
Other Material Terms; Security Interests
See Note 13 to the Annual Financial Statements for a description of the other material terms of the obligations outlined above and for additional information on the security interests and guarantees supporting these obligations. In addition to the obligations outlined under “Long-Term Debt” and “Revolving Credit and Other Facilities” above, secured obligations included approximately $119 million under Secured ISDAs as of March 31, 2025.
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12. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT.
•Level 1 derivative assets and liabilities primarily represent exchange-traded futures and options that are valued using unadjusted prices available from the underlying exchange. Level 1 financial assets also include investments in equity securities and available-for-sale U.S. government debt securities, which are valued using exchange prices.
•Level 2 derivative assets and liabilities primarily represent over-the-counter swaps, options, and forward purchase and sale contracts that are valued using adjusted exchange prices, prices provided by brokers, or pricing service companies that are all corroborated by market data. Level 2 financial assets also include investments in available-for-sale debt securities, including investments in corporate and municipal bonds, that are valued using pricing provided by brokers or pricing service companies and corroborated with market data.
The classifications of recurring fair value measurements within the fair value hierarchy were:
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Netting (a) | Total | Level 1 | Level 2 | NAV | Netting (a) | Total | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | $ | $ | $ | — | $ | $ | $ | $ | $ | — | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
Equity securities (b) | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. government debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||
| NDT funds | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Liabilities | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | $ | $ | $ | ( | $ | $ | $ | $ | $ | ( | $ | ||||||||||||||||||||||||||||||||||||||||||||||||||
(a)Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b)Includes fixed income funds and real estate investment trusts.
(c)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
There were no recurring fair value measurements classified as Level 3 as of March 31, 2025 and December 31, 2024.
Nonrecurring Fair Value Measurements
There were no nonrecurring fair value measurements related to impairments of long-lived assets during the three months ended March 31, 2025 and 2024.
Reported Fair Value
The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents,” “Restricted cash and cash equivalents,” “Accounts receivable,” and “Accounts payable and other accrued liabilities” approximate fair value.
The 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.
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The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| March 31, 2025 | December 31, 2024 | |||||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||||||||||||||
Long-term debt (a) | $ | $ | $ | $ | ||||||||||||||||||||||
__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
13. Postretirement Benefit Obligations
TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and a defined contribution plan.
The components of net periodic benefit costs for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
Postretirement benefits service cost (a) | $ | $ | ||||||||||||
Postretirement benefit (gain) loss | ||||||||||||||
| Interest cost | $ | $ | ||||||||||||
| Expected return on plan assets | ( | ( | ||||||||||||
| Amortization of: | ||||||||||||||
| Postretirement prior service cost (credit) | ( | |||||||||||||
Postretirement benefit (gain) loss, net (b) | $ | ( | $ | |||||||||||
| Net periodic defined benefit cost (credit) | $ | ( | $ | |||||||||||
_____________
(a)Activity presented as “Operation, maintenance and development” on the Consolidated Statements of Operations.
(b)Activity presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
During the three months ended March 31, 2025, the Company made a contribution of $13 million to the Talen Energy Retirement Plan (Talen’s principal defined-benefit pension plan) that is presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets as of March 31, 2025.
14. Stock-Based Compensation
In June 2023, TEC began granting performance stock units (“PSUs”) and Restricted stock units (“RSUs”) to certain employees and non-employee directors under the Company’s 2023 Equity Incentive Plan (the “Equity Plan”). The aggregate number of shares authorized for issuance under the Equity Plan is 7,083,461 shares.
Stock-based Compensation Expense
Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations for the periods was:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Stock-based compensation expense | $ | $ | ||||||||||||
| Income tax benefit | ( | ( | ||||||||||||
| After-tax stock-based compensation expense | $ | $ | ||||||||||||
Performance Stock Units
PSUs have three-year ratable or a two-year cliff vesting schedules or vest upon consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs. The following table summarizes the Company’s non-vested PSUs and changes during the period:
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| Units | Weighted-Average Grant Date Fair Value per Unit | |||||||||||||
| Non-vested as of December 31, 2024 | $ | |||||||||||||
| Granted | ||||||||||||||
| Non-vested as of March 31, 2025 | $ | |||||||||||||
As of March 31, 2025, $64 million of unrecognized compensation cost related to unvested PSUs granted are expected to be recognized over a weighted average period of approximately 1.2 years.
| Three Months Ended March 31, 2025 | ||||||||
Volatility (a) | % | |||||||
| Expected term (in years) | ||||||||
Risk-free rate (b) | % | |||||||
(a) Derived from an option pricing method based on the average asset volatility of peer companies and the Company’s leverage ratio.
(b) Based on the U.S. constant maturity treasury rate with a term matching the expected time to the end of the performance measurement period.
Restricted Stock Units
RSUs have three-year ratable or two-year cliff vesting schedules beginning on the grant date, with restrictions on transferring settled shares prior to the final scheduled vesting date for each award. The fair value of the RSUs granted is derived from the closing price of TEC common stock on the grant date. The following table summarizes the Company’s non-vested RSUs and changes during the year:
| Units | Weighted-Average Grant Date Fair Value per Unit | |||||||||||||
| Non-vested as of December 31, 2024 | $ | |||||||||||||
| Granted | ||||||||||||||
| Non-vested as of March 31, 2025 | $ | |||||||||||||
As of March 31, 2025, $28 million of unrecognized compensation cost related to unvested RSUs granted are expected to be recognized over a weighted average period of approximately 1.2 years.
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15. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Numerator: (Millions of Dollars) | ||||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||
| Less: | ||||||||||||||
| Net income (loss) attributable to noncontrolling interest | ||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | ( | $ | |||||||||||
| Denominator: (Thousands) | ||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic | ||||||||||||||
| Warrants | ||||||||||||||
| Restricted stock units | ||||||||||||||
| Performance stock units | ||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted | ||||||||||||||
| Earnings per Share - Basic | $ | ( | $ | |||||||||||
| Earnings per Share - Diluted | ( | |||||||||||||
16. Stockholders’ Equity
Common Stock Transactions
Share Repurchases and Retirements. Summary of activity under the SRP:
| Three Months Ended March 31, 2025 | ||||||||||||||||||||
| Number of Shares | Share Price (a) | Total Amount | ||||||||||||||||||
| Share repurchases | $ | $ | ||||||||||||||||||
| Share retirements | ( | ( | ||||||||||||||||||
(a)Weighted average price per share, including transaction costs and excise taxes.
As of May 8, 2025, TEC had 45,509,780 shares of common stock outstanding.
Share Repurchase Program
As of March 31, 2025, the Company had repurchased approximately 23 % of its outstanding shares of common stock for a total of approximately $2.0 billion, exclusive of transaction costs and excise taxes. The Board of Directors approved an $850 million portion of the share repurchases executed with Rubric in December 2024 outside of the existing authorization in the SRP. The remaining capacity of the SRP as of March 31, 2025 is $995 million. See Note 18 to the Annual Financial Statements for additional information relating to the SRP.
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Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Beginning balance | $ | ( | $ | ( | ||||||||||
Gains (losses) arising during the period | ||||||||||||||
Reclassifications to Consolidated Statements of Operations | ( | ( | ||||||||||||
| Income tax benefit (expense) | ( | |||||||||||||
| Other comprehensive income (loss) | ( | |||||||||||||
| Accumulated other comprehensive income (loss) | $ | ( | $ | ( | ||||||||||
The components of AOCI, net of tax, as of March 31, were:
| 2025 | 2024 | |||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | $ | ||||||||||||
| Postretirement benefit prior service credits (costs), net | ||||||||||||||
| Postretirement benefit actuarial gain (loss), net | ( | ( | ||||||||||||
| Accumulated other comprehensive income (loss) | $ | ( | $ | ( | ||||||||||
Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the three months ended March 31, 2025 and 2024.
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 13 for additional information.
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17. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Cash paid during the period | ||||||||||||||
Interest and other finance charges, net of capitalized interest (a) | $ | $ | ||||||||||||
Income taxes, net (b) | ||||||||||||||
| Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows | ||||||||||||||
| Commodity contracts | $ | $ | ||||||||||||
| Interest rate swap contracts (interest expense) | ( | |||||||||||||
| Unrealized (gain) loss on derivative instruments | $ | $ | ||||||||||||
| Depreciation, amortization and accretion included on the Statements of Cash Flows | ||||||||||||||
| Depreciation, amortization and accretion | $ | $ | ||||||||||||
| Other | ( | ( | ||||||||||||
| Depreciation, amortization and accretion | $ | $ | ||||||||||||
| Reconciliation of other non-cash operating activities | ||||||||||||||
| Derivative option premium amortization | $ | $ | ||||||||||||
| Stock-based compensation | ||||||||||||||
| Bitcoin revenue | ( | |||||||||||||
| Other | ( | ( | ||||||||||||
Total | $ | $ | ( | |||||||||||
| Non-cash investing activities | ||||||||||||||
| Capital expenditure accrual increase (decrease) | $ | $ | ( | |||||||||||
(a)Capitalized interest was $1 million and $3 million for the three months ended March 31, 2025 and 2024, respectively.
(b)During the three months ended March 31, 2025, $9 million of estimated Nuclear PTCs were utilized as a credit against our federal income tax payable.
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:
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Cash and cash equivalents | $ | $ | ||||||||||||
| Restricted cash and cash equivalents: | ||||||||||||||
| Commodity exchange margin deposits | ||||||||||||||
| Restricted cash and cash equivalents | ||||||||||||||
Total | $ | $ | ||||||||||||
18. Acquisitions and Divestitures
AWS Data Campus Sale. In March 2024, AWS purchased substantially all the assets related to the AWS Data Campus and certain other assets for gross proceeds of $650 million, of which $350 million were received at closing with the remaining $300 million held in escrow until August 2024. For the three months ended March 31, 2024, a $324 million gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. In connection with the AWS Data Campus Sale, the Company entered into the AWS PPA.
19. Segments
Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our Chief Executive Officer, who is the chief operating decision maker, reviews results and allocate resources. Adjusted EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker.
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“PJM” is engaged in electricity generation, marketing activities, and commodity risk and fuel management within the PJM RTO market and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities in PJM.
“Other” represents an operating segment that includes the operating and marketing activities of Talen Montana’s proportionate share of Colstrip in the WECC market and other non-material operating and development activities. “Other” also includes the operating activities of Nautilus until Bitcoin mining operations were suspended in October 2024 and the operating activities of our Texas power generation facilities in the ERCOT market prior to their disposition in May 2024. We have determined it appropriate to aggregate results of Talen’s remaining non-reportable segments and other operating activities.
“Corporate and Eliminations” represents a non-reportable segment that includes: (i) general and administrative expenses incurred by our corporate function; (ii) interest expense and other corporate activities not allocated to our operating segments; and (iii) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
| PJM | Other | Corporate and Eliminations | Total | |||||||||||||||||||||||
| Three Months Ended March 31, 2025 | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
| Operation, maintenance and development expenses | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
| Other segment items | ||||||||||||||||||||||||||
| Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
| Three Months Ended March 31, 2024 | ||||||||||||||||||||||||||
| Operating revenues | $ | $ | $ | ( | $ | |||||||||||||||||||||
| Operation, maintenance and development expenses | ||||||||||||||||||||||||||
| Interest expense and other finance charges | ||||||||||||||||||||||||||
| Other segment items | ||||||||||||||||||||||||||
| Adjusted EBITDA | ||||||||||||||||||||||||||
| Capital expenditures | ||||||||||||||||||||||||||
Reconciliation of segment Adjusted EBITDA to Net Income (Loss):
| Three Months Ended March 31, | ||||||||||||||
| 2025 | 2024 | |||||||||||||
| Adjusted EBITDA: | ||||||||||||||
| PJM | $ | $ | ||||||||||||
| Total Segment Adjusted EBITDA | $ | $ | ||||||||||||
| Reconciling Items: | ||||||||||||||
| Interest expense and other finance charges | ( | ( | ||||||||||||
| Income tax benefit (expense) | ( | |||||||||||||
| Depreciation, amortization and accretion | ( | ( | ||||||||||||
| Nuclear fuel amortization | ( | ( | ||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | ( | ( | ||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | ( | |||||||||||||
| Stock-based and other long-term incentive compensation expense | ( | ( | ||||||||||||
| Gain (loss) on asset sales, net | ||||||||||||||
| Operational and other restructuring activities | ( | ( | ||||||||||||
| "Other" operating segment | ||||||||||||||
| Noncontrolling interest | ||||||||||||||
| Corporate and Eliminations | ( | ( | ||||||||||||
| Other items | ||||||||||||||
| Net Income (Loss) | $ | ( | $ | |||||||||||
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ITEM 2. 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 the Interim Financial Statements, the Annual Financial Statements, and the Notes thereto. The discussion contains forward-looking statements as well as estimates regarding market and industry data, which involve risks, uncertainties, and assumptions. See “Cautionary Note Regarding Forward-Looking Information” and “Market and Industry Data” for additional information. Dollars are in millions, unless otherwise noted.
Recent Developments
Common Stock Transactions
Share Repurchases. During the three months ended March 31, 2025, we repurchased and retired 452,130 shares of TEC’s outstanding common stock under the SRP. The aggregate purchase price after transaction fees and excise tax was $85 million at a weighted average price of $186.24 per share. As of March 31, 2025, the remaining capacity under the SRP is $995 million through 2026. See Note 16 to the Interim Financial Statements for additional information on the SRP.
Financing Transactions
Secured Notes Consent. In January 2025, we received consents from noteholders representing a majority in principal amount of the Secured Notes to adopt certain amendments to the Indenture to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in December 2024; and (ii) waive TES’s right to optionally redeem up to 10% of the Secured Notes at a price of 103% of par prior to June 1, 2025.
See Note 11 to the Interim Financial Statements for additional information on long-term debt, other credit facilities, and recent financing activities.
Hedging Transactions
Interest Rate Swaps. To reduce the risk of unpredictable future cash flows associated with changes in variable rate indebtedness, in the first quarter 2025 we entered into interest rate swaps with a notional value of $550 million and a four-year maturity. In April 2025 we entered into additional interest rate swaps with notional value of $150 million and a four-year maturity.
RMR Arrangements
On May 1, 2025, the FERC approved the terms under which Talen will operate its Brandon Shores and H.A. Wagner power plants until May 31, 2029, beyond their scheduled May 31, 2025 retirement dates. Talen, PJM, and a broad coalition of the Maryland Public Service Commission, Maryland customers, and electric utilities reached agreement in January 2025 on the RMR agreement. Under the RMR agreement, Brandon Shores Units 1 and 2 and H.A. Wagner Units 3 and 4 will remain in service and provide power necessary to maintain grid and transmission reliability in and around the City of Baltimore until transmission upgrades to provide reliable power to the area from other sources are complete. Beginning June 1, 2025, we expect to receive $145 million annually for Brandon Shores and $35 million for H.A. Wagner with some performance incentives.
Factors Affecting Our Financial Condition and Results of Operations
Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” the sections entitled “Item 1A. Risk Factors” in this Report and our most recent Annual Report on Form 10-K, and Notes 3 and 10 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the first quarter 2025, natural gas prices for Texas Eastern M-3 settled above their ten-year average as natural gas storage levels fell below the five-year average. In PJM, below average temperatures during the first quarter 2025 contributed to increased load demand that resulted in higher settled on-peak power prices compared with the prior year.
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended March 31, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 60.50 | $ | 36.03 | ||||||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 53.87 | 29.68 | ||||||||||||
| Texas Eastern M-3 - $/MMBtu | 6.42 | 2.90 | ||||||||||||
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The weighted average forward market prices for the periods from April 1 through December 31 as of March 31, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub ATC - $/MWh | $ | 53.87 | $ | 40.60 | ||||||||||
| Texas Eastern M-3 - $/MMBtu | 3.80 | 1.97 | ||||||||||||
PJM West Hub ATC Spark Spreads - $/MWh (a) | 27.30 | 26.81 | ||||||||||||
__________________
(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Capacity Markets
Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.
PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.
Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2025/2026 Capacity Year, which was the most recent auction, was held in July 2024. The PJM BRA for the 2026/2027 Capacity Year is currently delayed until July 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 10 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.
Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:
| 2025/2026 | 2024/2025 | 2023/2024 | 2022/2023 | |||||||||||||||||||||||
PJM Capacity Performance ($/MW-day) (a) | ||||||||||||||||||||||||||
| MAAC | $ | 269.92 | $ | 49.49 | $ | 49.49 | $ | 95.79 | ||||||||||||||||||
| PPL | 269.92 | 49.49 | 49.49 | 95.79 | ||||||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
For the 2025/2026 Capacity Year, we cleared a total of 6,820 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas.
Nuclear Production Tax Credit
The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. See Note 4 to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized.
Seasonality/Scheduled Maintenance
The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.
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On March 25, 2025, Susquehanna commenced its planned refueling outage on Unit 2. During the outage, we identified incremental maintenance in the non-nuclear portion of the Unit which we expect will lead to operational efficiency. As a prudent operator, we have elected to complete this scope of work while Unit 2 is already in outage and market prices and demand are relatively low. The incremental maintenance investment is expected to add roughly $20 million of additional spend and extend the outage into mid-May. We anticipate the resulting improvements in operational efficiency of Unit 2 will be long-term in nature and pay back the additional costs and lost margin in approximately one-and-a-half years.
Results of Operations
The results of operations presented below for the three months ended March 31, 2025 and 2024, should be reviewed in conjunction with the Interim Financial Statements and Notes thereto. Our results of operations as reported in the Interim Financial Statements are prepared in accordance with GAAP.
In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. “Energy and other revenues” relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedges, Bitcoin revenue, and Nuclear PTC revenue. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
Unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy Expenses.” We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.
Results for the Three Months Ended March 31, 2025 and 2024
The following table and subsequent section display the results of operations:
| Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Capacity revenues | $ | 49 | $ | 45 | $ | 4 | ||||||||||||||
| Energy and other revenues | 582 | 572 | 10 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 3) | (241) | (108) | (133) | |||||||||||||||||
| Operating Revenues (Note 4) | 390 | 509 | (119) | |||||||||||||||||
| Fuel and energy purchases | (268) | (150) | (118) | |||||||||||||||||
| Nuclear fuel amortization | (26) | (35) | 9 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 3) | 59 | (27) | 86 | |||||||||||||||||
| Energy Expenses | (235) | (212) | (23) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (146) | (154) | 8 | |||||||||||||||||
| General and administrative | (34) | (43) | 9 | |||||||||||||||||
| Depreciation, amortization and accretion (Note 8) | (74) | (75) | 1 | |||||||||||||||||
| Other operating income (expense), net | (7) | — | (7) | |||||||||||||||||
| Operating Income (Loss) | (106) | 25 | (131) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 7) | (12) | 75 | (87) | |||||||||||||||||
| Interest expense and other finance charges (Note 11) | (74) | (59) | (15) | |||||||||||||||||
| Gain (loss) on sale of assets, net | 2 | 324 | (322) | |||||||||||||||||
| Other non-operating income (expense), net | 3 | 23 | (20) | |||||||||||||||||
| Income (Loss) Before Income Taxes | (187) | 388 | (575) | |||||||||||||||||
| Income tax benefit (expense) (Note 5) | 52 | (69) | 121 | |||||||||||||||||
| Net Income (Loss) | (135) | 319 | (454) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | — | 25 | (25) | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | (135) | $ | 294 | $ | (429) | ||||||||||||||
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Three Months Ended March 31, 2025 compared to March 31, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(429) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $(142) million unfavorable decrease, primarily due to the following:
Energy and Other Revenues, net of Fuel and Energy Purchases. $(108) million unfavorable decrease. This is primarily related to the combined effect of: (i) $(170) million decrease in realized hedges; and (ii) $(77) million decrease in digital revenue and Nuclear PTC revenue. Such amounts are partially offset by $137 million favorable increase in margin associated with electric generation and ancillary revenue resulting from higher realized prices at Susquehanna and higher generation volumes and realized prices associated with our PJM fossil fleet.
Unrealized Gain (Loss) on Derivative Instruments, net. $(47) million unfavorable decrease. This is primarily related to the combined effect of: (i) $(95) million from higher forward power prices relative to the Company’s hedge positions during the first quarter 2025 as compared to the first quarter 2024; and (ii) $(41) million associated with lower volume of hedge positions executed in the first quarter 2025 as compared to hedge positions executed in the first quarter 2024. Such amounts are partially offset by $89 million unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
•Nuclear Decommissioning Trust Funds Gain (Loss), net. $(87) million unfavorable decrease. This is primarily due to the combined effect of: (i) $(24) million decrease in the unrealized value of equity securities in the first quarter 2025 compared with a $41 million increase in the first quarter 2024; and (ii) $(23) million decrease in realized activity due to asset portfolio rebalancing activities that occurred in the first quarter 2024. See Notes 7 and 12 to the Interim Financial Statements for additional information.
•Gain (Loss) on Sale of Assets, net. $(322) million unfavorable decrease. This is primarily related to the gain from the AWS Data Campus Sale in March 2024. See Note 18 to the Interim Financial Statements for additional information.
•Income Tax Benefit (Expense). $121 million favorable increase. This is due to the change of the estimated income tax effect resulting from income before taxes in the first quarter 2024 and a loss before taxes in the first quarter 2025.
•Net Income (Loss) Attributable to Noncontrolling Interest. $(25) million favorable decrease. This is due to the acquisition of the remaining noncontrolling interest in Cumulus Digital in March 2024 and the subsequent acquisition of the remaining noncontrolling interest in Nautilus in October 2024.
Liquidity and Capital Resources
Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our hedging activities including cash collateral and other forms of credit support; (v) the settlement of, or forms of credit in support of, legacy asset retirement and (or) environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.
Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.
Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, we now have lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) and significantly reduced debt service requirements following our emergence from bankruptcy in 2023 and subsequent refinancing transactions.
We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.
See the following Notes to the Interim Financial Statements for additional information on liquidity topics discussed below: Note 3 for derivatives and hedging, Note 9 for AROs and environmental obligations, Note 11 for long-term debt and credit facilities, and Note 17 for supplemental cash flow information.
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Liquidity and Letter of Credit Capacity
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Cash and cash equivalents, unrestricted | $ | 295 | $ | 328 | ||||||||||
Unutilized RCF capacity (a) | 700 | 700 | ||||||||||||
Total available liquidity | $ | 995 | $ | 1,028 | ||||||||||
Additional unutilized LC capacity (b) | $ | 475 | $ | 526 | ||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
(b)Excludes LC capacity available under the RCF and includes LC capacity under the LCF.
Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 11 to the Interim Financial Statements for additional information on the RCF and LCF.
Financial Performance Assurances
TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including but not limited to environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.
| March 31, 2025 | December 31, 2024 | |||||||||||||
| Outstanding surety bonds | $ | 238 | $ | 234 | ||||||||||
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
| Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Operating activities | $ | 119 | $ | 173 | $ | (54) | ||||||||||||||
| Investing activities | (68) | 265 | (333) | |||||||||||||||||
| Financing activities | (96) | (259) | 163 | |||||||||||||||||
Operating activities
A change of $(54) million in net cash provided by (used in) operating activities is generally aligned with results from operations combined with working capital changes in the normal course of business. See “Results of Operations” for additional information.
Investing activities
A change of $(333) million in net cash provided by (used in) investing activities was primarily due to $339 million in proceeds from the AWS Data Campus Sale in the first quarter 2024.
Financing activities
A change of $163 million in net cash provided by (used in) financing activities is primarily the result of the combined effect of the: (i) $182 million repayment of the Cumulus Digital TLF and (ii) $39 million purchase of noncontrolling interest in Cumulus Digital, both in the first quarter 2024. Such amounts were partially offset by an increase in share repurchases of $(53) million in the first quarter 2025.
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 “Guarantees and Other Assurances” in Note 10 to the Interim Financial Statements for additional information regarding guarantees.
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Non-GAAP Financial Measure
Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
Adjusted EBITDA
We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.
Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.
The following table presents a reconciliation of the GAAP financial measure of “Net Income (Loss)” presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:
| Three Months Ended March 31, | ||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | ||||||||||||
| Net Income (Loss) | $ | (135) | $ | 319 | ||||||||||
| Adjustments | ||||||||||||||
| Interest expense and other finance charges | 74 | 59 | ||||||||||||
| Income tax (benefit) expense | (52) | 69 | ||||||||||||
Depreciation, amortization and accretion | 74 | 75 | ||||||||||||
| Nuclear fuel amortization | 26 | 35 | ||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 182 | 134 | ||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | 12 | (75) | ||||||||||||
| Stock-based and other long-term incentive compensation expense | 13 | 18 | ||||||||||||
(Gain) loss on asset sales, net (a) | (2) | (324) | ||||||||||||
| Operational and other restructuring activities | 9 | 2 | ||||||||||||
| Noncontrolling interest | — | (11) | ||||||||||||
| Other | (1) | (12) | ||||||||||||
| Total Adjusted EBITDA | $ | 200 | $ | 289 | ||||||||||
__________________
(a)See Note 18 to the Interim Financial Statements for additional information.
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Critical Accounting Policies and Estimates
The Company’s financial statements are prepared in conformity with GAAP, which requires the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i) the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. See the Annual Financial Statements for a description of our significant accounting policies and estimates.
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Note 3 to the Interim Financial Statements for a description of our market risk.
ITEM 4. CONTROLS AND PROCEDURES
Evaluation of Disclosure Controls and Procedures
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2025, the end of the period covered by this Report.
Changes in Internal Control Over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the three months ended March 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II
ITEM 1. LEGAL PROCEEDINGS
Susquehanna ISA Amendment. Under a prior, FERC-accepted ISA between PJM, Susquehanna, and a subsidiary of PPL Corporation (“PPL”) (collectively, the “ISA Parties”), Susquehanna is permitted to decrease by up to 300 MW the amount of power supply that it would otherwise provide to the power grid within PPL’s service area. Susquehanna currently provides that power to load via load-owned transmission directly connected to Susquehanna rather than supplying load from the power grid. In June 2024, PJM filed at FERC an Amended Interconnection Service Agreement (the “Susquehanna ISA Amendment”) executed between the ISA Parties permitting Susquehanna to decrease by up to 480 MW the amount of power supply that it would otherwise provide to the power grid and now intends to sell to AWS instead. PJM previously concluded such increase in the amount of withheld power would have no reliability impacts on the grid. In June 2024, despite the Susquehanna ISA Amendment being applicable solely to the PPL service area, Exelon Corporation (“Exelon”) and AEP filed a protest to the Susquehanna ISA Amendment at FERC and raised generic issues involving the direct connection of load service to generators. FERC responded by issuing a deficiency letter in August 2024 seeking more information about the arrangement described in the Susquehanna ISA Amendment and separately setting a Technical Conference for November 2024 to discuss broader issues related to (i) co-located load connected directly to generation; and (ii) emerging reliability issues resulting from the dramatic rise in data center demand for power. In September 2024, PJM provided a response to FERC’s August 2024 deficiency letter on the Susquehanna ISA Amendment and filed a Construction Service Agreement between the ISA Parties and Mid-Atlantic Interstate Transmission, LLC to facilitate certain network upgrades to ultimately accommodate a 960 MW decrease of power supply to the grid. Talen filed its own comments in September 2024 and written testimony in the FERC Technical Conference proceeding in October 2024. Shortly after the conclusion of the FERC Technical Conference in November 2024, FERC issued a 2-1 decision rejecting the Susquehanna ISA Amendment and Talen filed a motion for a rehearing of the FERC order within the 30-day deadline for such motions. In December, FERC issued an order stating that it would address the request for rehearing in a future order, which FERC issued on April 10, 2025, reaffirming its original order. Talen has filed an appeal in the U.S. Court of Appeals for the Fifth Circuit, which had been temporarily stayed awaiting FERC’s substantive rehearing order. Now that the FERC order has been issued, Talen is actively pursuing its appeal.
The prior FERC-accepted ISA between the ISA Parties permitting Susquehanna to decrease 300 MW of its current power supply from the power grid remains in place and facilitates the initial sale of power to AWS under the AWS PPA. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.”
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We are evaluating our commercial and legal options to provide the most efficient path to full development of the AWS Data Campus. Such options include, but are not limited to, potential submission of a revised form of Susquehanna ISA Amendment or alternative contract structures with AWS. If the Company is unable commercially or legally to resolve the Susquehanna ISA Amendment approval impediments and realize the full development of the AWS Data Campus, there may be a material impact on our future results of operations, and (or) financial condition.
Separate and apart from the Susquehanna ISA proceeding, there are three other pending proceedings before FERC that could shape policy around co-located load, and thus impact the result of the Susquehanna ISA proceeding. First, in August 2024, Exelon made a series of filings on behalf of each of its electric utility subsidiaries to amend portions of the PJM tariff that would clarify that co-located load arrangements must be categorized as either network load or point-to-point service (the “Exelon 205 proceeding”). In effect, the proposed amendments intended to clarify that co-located load arrangements would be treated as either needing network or point-to-point service, making them subject to the same transmission charges and fees for transmission-related services that would be applicable if the same load had located at other points on the PJM grid. Exelon requested a December 2, 2024 effective date, but in November 2024, FERC issued a deficiency letter stating that FERC required more information to make a determination. Second, in November 2024, FERC held a technical conference on co-located load to discuss, among other things, the impacts of various co-location agreements, whether and how large co-located loads receive wholesale market services or benefits from the transmission system, the cost and impact of back-up services for large co-located load and state regulatory and policy issues (the “Co-Location Technical Conference proceeding”). Following the technical conference, FERC requested comments be filed by December 9, 2024. Talen both participated in the technical conference and filed comments. Third, in November 2024, Constellation filed a complaint at FERC alleging that PJM’s tariff is unjust and unreasonable because it is silent on how to treat fully isolated co-located load (the “Constellation 206 proceeding”). The complaint suggests that FERC import into the tariff certain terms and conditions from a non-binding guidance document PJM shared with stakeholders or set the proceeding for settlement discussions on an expedited basis with a mediator.
On February 20, 2025, FERC denied relief in the Exelon 205 proceeding and initiated a new Section 206 proceeding directing PJM to show cause within 30 days why its tariff is just and reasonable in light of potential discrimination around the treatment of co-located load or, in the alternative, to propose changes to its tariff to address the treatment of co-located load (the “Co-Located Load PJM Tariff proceeding”). The order initiating the Co-Located Load PJM Tariff proceeding consolidated the records and proceedings from the Co-Location Technical Conference and Constellation 206 proceedings into the Co-Located Load PJM Tariff proceeding, which will all be considered together by FERC. Talen submitted comments in support of PJM’s filing and requested that FERC act quickly and require PJM to implement its proposal into its tariff. Talen intends to continue to be an active participant in the PJM and FERC process to revise PJM’s tariff.
See Note 10 to the Interim Financial Statements for information about other material legal proceedings to which we are subject.
ITEM 1A. RISK FACTORS
Changes to, and uncertainty surrounding, United States and international trade tariffs, treaties, policies, and regulations may adversely affect our business.
United States and international laws, rules, and practices pertaining to trade are currently undergoing frequent changes, including the imposition of new or expanded tariffs on international trade by the U.S. and foreign governments. In addition, President Trump has directed various federal agencies to further evaluate key aspects of U.S. trade policy, and discussion is ongoing regarding other potentially significant changes to U.S. and international trade policies, treaties, and tariffs. Accordingly, there continues to exist significant uncertainty about the future relationship between the U.S. and international trade partners. We cannot predict the timing or scope of any potential changes to, or the volatility of governmental decisions around, tariffs or other trade policies. Any new or increased trade tariffs, restrictions, or controls, as well as any resulting delays or disruptions in global supply chains or shipping channels, could materially increase the prices we pay for, or negatively impact our ability to obtain, on a timely basis or at all, fuel, materials, supplies, equipment, parts, and other products critical to our operations. Furthermore, any of these developments, or the perception that any of them could occur, may have a material negative impact on the macro-level U.S. and global economy, which could negatively impact our interest rates, stock price, and ability to access capital markets.
For additional information related to the Company’s risk factors, see ”Item 1A. Risk Factors” in the Company’s most recent Annual Report on Form 10-K.
ITEM 2. UNREGISTERED SALES OF EQUITY AND USE OF PROCEEDS
Issuer Purchases of Equity Securities
In October 2023, we announced the Board of Directors approved the SRP, initially authorizing the Company to repurchase up to $300 million of TEC’s outstanding common stock. In May 2024, the Board of Directors approved an increase in the then-remaining SRP capacity to $1 billion through the end of 2025. In September 2024, the Board of Directors again approved an increase in the then-remaining SRP capacity to $1.25 billion through December 31, 2026. See “Item 5. Market for Registrant’s Common Equity, Related Shareholder Matters and Issuer Purchases of Equity Securities” in the Company’s most recent Annual Report on Form 10-K for additional information related to the SRP and shares repurchased under the SRP.
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The following table contains information regarding our purchases of TEC common stock during the three months ended March 31, 2025:
| Monthly Period | Total number of shares purchased | Average price paid per share (a) | Total number of shares purchased as part of publicly announced plan (b) | Approximate dollar value that may yet be purchased under the plan (c) | ||||||||||||||||||||||
| January | — | $ | — | — | $ | 1,079 | ||||||||||||||||||||
| February | — | — | — | 1,079 | ||||||||||||||||||||||
| March | 452,130 | 184.38 | 452,130 | 995 | ||||||||||||||||||||||
| Total | 452,130 | $ | 184.38 | 452,130 | $ | — | ||||||||||||||||||||
__________________
(a)Excludes transaction costs and excise taxes.
(b)Represents shares repurchased under the SRP. See above for a description of the SRP.
(c)Dollars in millions.
For a description of limitations on the payment of our dividends, see Note 2 to the Annual Financial Statements.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
During the three months ended March 31, 2025, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted terminated
ITEM 6. EXHIBITS
Incorporated by Reference | ||||||||||||||||||||||||||||||||
| Exhibit No. | Description | Form | File Number | Date of Filing | Exhibit Number | |||||||||||||||||||||||||||
| 3.1 | S-1 | 333-280341 | June 20, 2024 | 3.1 | ||||||||||||||||||||||||||||
| 3.2 | S-1 | 333-280341 | June 20, 2024 | 3.2 | ||||||||||||||||||||||||||||
10.1*† | — | — | — | — | ||||||||||||||||||||||||||||
10.2*† | — | — | — | — | ||||||||||||||||||||||||||||
10.3*† | — | — | — | — | ||||||||||||||||||||||||||||
10.4*† | — | — | — | — | ||||||||||||||||||||||||||||
| 31.1* | — | — | — | — | ||||||||||||||||||||||||||||
| 31.2* | — | — | — | — | ||||||||||||||||||||||||||||
| 32.1** | — | — | — | — | ||||||||||||||||||||||||||||
| 101.INS* | Inline XBRL Instance Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | — | — | — | — | |||||||||||||||||||||||||||
| 104* | Cover Page Interactive Data File (embedded within the Inline XBRL document). | — | — | — | — | |||||||||||||||||||||||||||
________________
* Filed herewith.
** Furnished herewith.
† Management contract or compensatory plan or arrangement.
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GLOSSARY OF TERMS AND ABBREVIATIONS
Adjusted EBITDA. Net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Annual Financial Statements. The audited consolidated balance sheets of TEC as of December 31, 2024 (Successor) and December 31, 2023 (Successor); the related audited consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the year ended December 31, 2024 (Successor), for the period from May 18, 2023 through December 31, 2023 (Successor), and for the period from January 1, 2023 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor); and the related notes.
AOCI. Accumulated other comprehensive income or loss, which is a component of stockholders’ equity on the Consolidated Balance Sheets.
ARO. Asset retirement obligation.
AWS. Amazon Web Services, Inc. and its affiliates.
AWS Data Campus. The zero-carbon data center campus initially developed by a subsidiary of Cumulus Digital adjacent to Susquehanna. See Note 18 to the Interim Financial Statements for information on the AWS Data Campus Sale.
AWS Data Campus Sale. The Company’s sale of the AWS Data Campus to AWS in March 2024 to AWS for gross proceeds of $650 million. See Note 18 to the Interim Financial Statements for additional information.
AWS PPA. The March 2024 power purchase agreement between the Company and AWS pursuant to which (i) the Company agreed to supply up to 960 MW of long-term, carbon-free power to the AWS Data Campus from Susquehanna; (ii) the parties agreed to fixed-price power commitments that increase in 120 MW increments over several years; and (iii) AWS, under certain conditions, has the option to cap their commitments at 480 MW.
Bilateral LCF. The $75 million senior secured bilateral LC facility provided by Barclays Bank PLC. The Bilateral LCF was terminated in December 2024.
Board of Directors. The board of directors of Talen Energy Corporation.
Brandon Shores. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Brunner Island. A Talen-owned and operated generation facility in York Haven, Pennsylvania.
CCR. Coal Combustion Residuals, including but not limited to fly ash, bottom ash, and gypsum, that are produced from coal-fired electric generation facilities.
Colstrip. A generation facility comprised of four coal-fired generation units located in Colstrip, Montana. Talen Montana operates Colstrip, owns an undivided interest in Colstrip Unit 3, and has an economic interest in Colstrip Unit 4. Colstrip Units 1 and 2 were permanently retired in January 2020. See Note 10 to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in Colstrip.
Credit Agreement. The Credit Agreement, dated as of May 17, 2023, by and among TES, as borrower, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and the joint lead arrangers and joint bookrunners parties thereto, which governs the RCF, TLB-1, TLB-2, and LCF, as the same may be amended, amended and restated, supplemented, or otherwise modified from time-to-time.
Cumulus Digital. Cumulus Digital Holdings LLC, a subsidiary of TES that, through its subsidiaries, (i) initially developed the AWS Data Campus; and (ii) holds the Company’s interest in Nautilus.
Cumulus Digital TLF. The term loan facility under which a subsidiary of Cumulus Digital borrowed $175 million to support the development of Nautilus and the AWS Data Campus. The Cumulus Digital TLF was repaid in full and terminated in March 2024.
EPA. U.S. Environmental Protection Agency.
EPA CCR Rule. The national regulatory standards required by the EPA for the management of CCRs in landfills and surface impoundments.
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EPA CSAPR. The Cross-State Air Pollution Rule, a federal program that aims to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. A cap-and-trade system for both annual and ozone season periods is used to reduce the target pollutants—sulfur dioxide and nitrogen oxides. CSAPR regulations have been changed over time, and different versions of the regulations have been referred to as the “CSAPR Update,” the “Revised CSAPR Update,” and the “Good Neighbor Plan.”
EPA ELG Rule. The effluent limitation guidelines, which are national regulatory standards required by the EPA for wastewater discharged from specific industrial categories, including but not limited to coal-fired electric generation facilities, to surface waters and municipal sewage treatment plants.
EPA GHG Rule. An EPA rule that establishes carbon dioxide limits for new electric generating units and GHG guidelines for certain existing electric generating units.
EPA MATS Rule. The Mercury and Air Toxics Standards, EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 MWs.
EPS. Earnings per share.
ERCOT. The Electric Reliability Council of Texas, operator of the electricity transmission network and electricity energy market in most of Texas.
ERCOT Sale. The sale of our Texas fleet to CPS Energy in May 2024.
Exchange Act. The Securities Exchange Act of 1934, as amended.
FERC. U.S. Federal Energy Regulatory Commission.
GAAP. Generally Accepted Accounting Principles in the United States.
H.A. Wagner. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Indenture. The Indenture, dated as of May 12, 2023, as supplemented by the First Supplemental Indenture, dated as of May 17, 2023, the Second Supplemental Indenture, dated as of October 6, 2023, the Third Supplemental Indenture, dated as of June 22, 2024, and the Fourth Supplemental Indenture, dated as of January 13, 2025, each between TES, the Subsidiary Guarantors and Wilmington Savings Fund Society, FSB, as trustee, which governs the Secured Notes, as the same may be further amended, amended and restated, supplemented or otherwise modified from time-to-time.
Inflation Reduction Act. 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 Internal Revenue Code of 1986 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. The consolidated balance sheets of TEC as of March 31, 2025 and December 31, 2024; the related consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the three months ended March 31, 2025 and March 31, 2024; and the related notes.
ISA. Interconnection Service Agreement.
ISO. Independent System Operator.
LC. Letter of credit.
LCF. The $900 million stand-alone letter of credit facility established under the Credit Agreement.
Martins Creek. A Talen-owned and operated generation facility in Bangor, Pennsylvania.
MMBtu. One million British Thermal Units.
Montour. A Talen-owned and operated generation facility in Washingtonville, Pennsylvania.
MW. Megawatt.
MWh. Megawatt-hour.
MWd. Megawatt-day.
Nautilus. Nautilus Cryptomine LLC, a cryptocurrency project that was previously a joint venture between the Company and TeraWulf. The Company purchased TeraWulf’s interest in October 2024 and now owns 100% of Nautilus.
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NAV. Net asset value.
NDT. Nuclear facility decommissioning trust that is expected to fund Talen’s proportional costs associated with the future decommissioning activities of Susquehanna.
NERC. North American Electric Reliability Corporation.
NRC. U.S. Nuclear Regulatory Commission.
Nuclear PTC. The nuclear production tax credit under the Inflation Reduction Act.
PEDFA Bonds. The following series of Pennsylvania Economic Development Financing Authority (“PEDFA”) Exempt Facilities Revenue Refunding Bonds: Series 2009A, due December 2038 (“PEDFA 2009A Bonds”); Series 2009B, due December 2038 (“PEDFA 2009B Bonds”); and Series 2009C, due December 2037 (“PEDFA 2009C Bonds”). The PEDFA 2009A Bonds were extinguished at emergence from bankruptcy in 2023; the PEDFA 2009B Bonds and PEDFA 2009C Bonds remain outstanding and are guaranteed by certain of the Subsidiary Guarantors.
PJM. PJM Interconnection, L.L.C., the RTO that coordinates the movement of wholesale electricity in all or parts of Pennsylvania, New Jersey, Maryland, 10 other states, and the District of Columbia.
PJM BRA. PJM Base Residual Auction, a component of PJM’s capacity market intended to secure power supply resources from market participants in advance of the PJM Capacity Year. It is usually held during the month of May three years prior to the start of the PJM Capacity Year. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.
PJM Capacity Year. PJM capacity revenues for each delivery year covering the period from June 1 to May 31.
Plan of Reorganization. The Joint Chapter 11 Plan of Reorganization of Talen Energy Supply, LLC and Its Affiliated Debtors (Docket No. 1206), as subsequently amended, supplemented, or otherwise modified, and any exhibits or schedules thereto.
PP&E. Property, plant and equipment.
RCF. The senior secured revolving credit facility that provides $700 million in aggregate revolving loan and LC commitments under the Credit Agreement.
RGGI. The Regional Greenhouse Gas Initiative, a mandatory market-based program among certain states, including Maryland, New Jersey and Massachusetts, to cap and reduce carbon dioxide emissions from the power sector. RGGI requires certain electric power generators to hold allowances equal to their carbon dioxide emissions over a three-year control period. Pennsylvania has proposed joining this program.
RMR. A generation unit that is otherwise slated to be retired but agrees with PJM to remain operational beyond its requested deactivation date as a reliability-must-run resource to mitigate reliability concerns until necessary upgrades can be established.
RTO. Regional Transmission Organization.
Secured ISDAs. Certain bilateral secured International Swaps and Derivatives Association (“ISDA”) agreements and Base Contracts for Sale and Purchase of Natural Gas as published by the North American Energy Standards Board (“NAESB”) of Talen Energy Marketing.
Secured Notes. The 8.625% Senior Secured Notes, due 2030, issued by Talen Energy Supply.
SRP. The share repurchase program, under which the Board of Directors has authorized the Company to repurchase shares of TEC’s outstanding common stock.
Subsidiary Guarantors. The subsidiaries of TES that guarantee: (i) the obligations of TES under the Credit Facilities and the Secured Notes; and (ii) the obligations of Talen Energy Marketing under the Secured ISDAs.
Susquehanna. A nuclear-powered generation facility located near Berwick, Pennsylvania. A subsidiary of Talen Energy Supply operates and owns a 90% undivided interest in Susquehanna.
Talen (or the “Company,” “we,” “us,” or “our”). (i) for periods after May 17, 2023, Talen Energy Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise; and (ii) for periods on or before May 17, 2023, Talen Energy Supply and its consolidated subsidiaries, unless the context clearly indicates otherwise.
Talen Energy Corporation (or “TEC”). Talen Energy Corporation, the parent company of Talen Energy Supply and its consolidated subsidiaries.
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Talen Energy Marketing. Talen Energy Marketing, LLC, a direct subsidiary of Talen Energy Supply that provides energy management services to Talen-owned and operated generation facilities and engages in wholesale commodity marketing activities.
Talen Energy Supply (or “TES”). Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation that, thorough subsidiaries, indirectly holds all of Talen’s assets and operations.
Talen Montana. Talen Montana, LLC, a Talen subsidiary that operates Colstrip, owns an undivided interest in Colstrip Unit 3, and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
TeraWulf. TeraWulf (Thales) LLC, a wholly owned subsidiary of TeraWulf Inc. and an unaffiliated third party.
TLB-1. The $580 million (subsequently increased to $870) million senior secured term loan B facility, due May 2030, under the Credit Agreement.
TLB-2. The $850 million senior secured term loan B facility, due December 2031, under the Credit Agreement.
TLC LCF. The $470 million cash collateralized LC facility under the Credit Agreement. The TLC LCF was terminated in December 2024.
WECC. The Western Electricity Coordinating Council, a non-profit corporation that assures a reliable and secure bulk electric system in the Western Interconnection, covering all or parts of Montana, 13 other U.S. States, Canada, and Mexico.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: | May 8, 2025 | By: | /s/ Terry L. Nutt | |||||||||||
Name: | Terry L. Nutt | |||||||||||||
Title: | Chief Financial Officer | |||||||||||||
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