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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 June 30, 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

Talen Energy Corporation
(Exact name of registrant as specified in its charter)

Delaware | 47-1197305
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.)

2929 Allen Pkwy, Suite 2200, Houston, TX 77019
(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
Common stock, par value $0.001 per share |  | TLN |  | The Nasdaq Global Select Market

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.

☒ | Large accelerated filer | ☐ | Accelerated filer | ☐ | Non-accelerated filer | ☐ | Smaller reporting company | ☐ | Emerging growth company

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 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 August 7, 2025, the registrant had 45,685,316 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

| Page
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION | 1
M ARKET AND INDUSTRY DATA | 1
PART I. FINANCIAL INFORMATION |
| I TEM 1. FINANCIAL STATEME NTS |
|  | Condensed Consolidated Statements of Operations (Unaudited) | 2
|  | Condensed Consolidated Statements of Comprehensive Income (Loss) (Unaudited) | 3
|  | Condensed Consolidated Balance Sheets (Unaudited) | 4
|  | Condensed Consolidated Statements of Cash Flows (Unaudited) | 5
|  | Condensed Consolidated Statements of Equity (Unaudited) | 6
|  | Notes to the Interim Financial Statements (Unaudited) |
|  | 1. Business, Basis of Presentation, and Summary of Significant Accounting Policies | 8
|  | 2. Risk Management, Derivative Instruments and Hedging Activities | 8
|  | 3. Revenue | 11
|  | 4. Income Taxes | 12
|  | 5. Inventory | 12
|  | 6. Nuclear Decommissioning Trust Funds | 12
|  | 7. Property, Plant and Equipment | 13
|  | 8. Asset Retirement Obligations and Accrued Environmental Costs | 14
|  | 9. Commitments and Contingencies | 15
|  | 10. Long-Term Debt and Other Credit Facilities | 21
|  | 11. Fair Value | 21
|  | 12. Postretirement Benefit Obligations | 23
|  | 13. Stock-Based Compensation | 23
|  | 14. Earnings Per Share | 24
|  | 15. Stockholders' Equity | 25
|  | 16. Supplemental Cash Flow Information | 26
|  | 17. Acquisitions and Divestitures | 26
|  | 18. Seg ments | 27
| I TEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIO N A ND RESULTS OF OPERATION S |
|  | R ece nt Deve lopment s | 29
|  | Factors Affecting Our Financial Condition and Results of Operations | 30
|  | Results of Operations | 31
|  | Liquidity and Capital Resources | 34
|  | Cash Flow Activities | 35
|  | Contractual Obligations and Commitments | 35
|  | Non-GAAP Financial Measure | 35
|  | Critical Accounting Policies and Estimates | 36
| ITEM 3. QUA NTITATIVE AND QUALITATIVE DISCLO SURES ABOUT MARKET RISK | 36
| ITEM 4. CONTROLS AND PROCEDURES | 37
P ART II. OTHER INFORMATION |
| IT EM 1. L EGAL PROCEEDINGS | 37
| I TEM 1A. R ISK FACTORS | 37
| ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 39
| ITEM 3. D EF AULTS UPON SENIOR SECURITI ES | 39
| I TEM 4. MINE S AF ET Y DISCLOSURES | 39
| I TEM 5. O THER IN FORMATION | 39
| I TEM 6. EXHIBITS | 40
G LOSSAR Y OF TERMS AND ABBREVIA TIONS | 41
SIGN ATURES | 45

Table o f Contents
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q (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 for the year ended December 31, 2024 (our “2024 Annual Report”), as updated by our Quarterly Report on Form 10-Q for the three months ended March 31, 2025 (our “March 31, 2025 Quarterly Report”). 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 2024 Annual Report, as updated by our March 31, 2025 Quarterly Report. These and other factors could cause results to differ materially from those expressed in the estimates made by third parties and by us. Accordingly, you are cautioned not to place undue reliance on such market and industry data or any other such estimates.
1

Table o f Contents
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |
(Millions of Dollars, except share data) |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Capacity revenues |  | $ | 88 |  |  | $ | 46 |  |  | $ | 137 |  |  | $ | 91 |  |  |  |  |  |
Energy and other revenues |  | 366 |  |  | 367 |  |  | 948 |  |  | 939 |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  | 176 |  |  | 76 |  |  | (65) |  |  | (32) |  |  |  |  |  |
Operating Revenues (Note 3) |  | 630 |  |  | 489 |  |  | 1,020 |  |  | 998 |  |  |  |  |  |
Fuel and energy purchases |  | (150) |  |  | (163) |  |  | (418) |  |  | (313) |  |  |  |  |  |
Nuclear fuel amortization |  | (18) |  |  | (28) |  |  | (44) |  |  | (63) |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  | (84) |  |  | 15 |  |  | (25) |  |  | (12) |  |  |  |  |  |
Energy Expenses |  | (252) |  |  | (176) |  |  | (487) |  |  | (388) |  |  |  |  |  |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |  |
Operation, maintenance and development |  | (192) |  |  | (164) |  |  | (338) |  |  | (318) |  |  |  |  |  |
General and administrative |  | (41) |  |  | (40) |  |  | (75) |  |  | (83) |  |  |  |  |  |
Depreciation, amortization and accretion (Note 7) |  | (70) |  |  | (75) |  |  | (144) |  |  | (150) |  |  |  |  |  |
Other operating income (expense), net |  | (9) |  |  | (7) |  |  | (16) |  |  | (7) |  |  |  |  |  |
Operating Income (Loss) |  | 66 |  |  | 27 |  |  | (40) |  |  | 52 |  |  |  |  |  |
Nuclear decommissioning trust funds gain (loss), net (Note 6) |  | 80 |  |  | 27 |  |  | 68 |  |  | 102 |  |  |  |  |  |
Interest expense and other finance charges (Note 10) |  | (62) |  |  | (62) |  |  | (136) |  |  | (121) |  |  |  |  |  |
Gain (loss) on sale of assets, net (Note 17) |  | 9 |  |  | 561 |  |  | 11 |  |  | 885 |  |  |  |  |  |
Other non-operating income (expense), net |  | 4 |  |  | 17 |  |  | 7 |  |  | 40 |  |  |  |  |  |
Income (Loss) Before Income Taxes |  | 97 |  |  | 570 |  |  | (90) |  |  | 958 |  |  |  |  |  |
Income tax benefit (expense) (Note 4) |  | (25) |  |  | (112) |  |  | 27 |  |  | (181) |  |  |  |  |  |
Net Income (Loss) |  | 72 |  |  | 458 |  |  | (63) |  |  | 777 |  |  |  |  |  |
Less: Net income (loss) attributable to noncontrolling interest |  | — |  |  | 4 |  |  | — |  |  | 29 |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders |  | $ | 72 |  |  | $ | 454 |  |  | $ | (63) |  |  | $ | 748 |  |  |  |  |  |
Per Common Share |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders - Basic |  | $ | 1.58 |  |  | $ | 7.90 |  |  | $ | (1.38) |  |  | $ | 12.87 |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders - Diluted |  | $ | 1.50 |  |  | $ | 7.60 |  |  | $ | (1.38) |  |  | $ | 12.41 |  |  |  |  |  |
Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) |  | 45,554 |  |  | 57,434 |  |  | 45,699 |  |  | 58,119 |  |  |  |  |  |
Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) |  | 47,905 |  |  | 59,775 |  |  | 45,699 |  |  | 60,269 |  |  |  |  |  |

The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
2

Table o f Contents
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |
(Millions of Dollars) |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Net Income (Loss) |  | $ | 72 |  |  | $ | 458 |  |  | $ | (63) |  |  | $ | 777 |  |  |  |  |  |
Other Comprehensive Income (Loss) |  |  |  |  |  |  |  |  |  |  |  |  |
Available-for-sale securities unrealized gain (loss), net (Note 6) |  | 2 |  |  | 2 |  |  | 8 |  |  | 1 |  |  |  |  |  |
Income tax benefit (expense) |  | (1) |  |  | (1) |  |  | (3) |  |  | — |  |  |  |  |  |
Gains (losses) arising during the period, net of tax |  | 1 |  |  | 1 |  |  | 5 |  |  | 1 |  |  |  |  |  |
Available-for-sale securities unrealized (gain) loss, net (Note 6) |  | (1) |  |  | (5) |  |  | (2) |  |  | (12) |  |  |  |  |  |
Postretirement benefit prior service (credits) costs, net (Note 12) |  | (1) |  |  | — |  |  | (2) |  |  | — |  |  |  |  |  |
Income tax (benefit) expense |  | 2 |  |  | 2 |  |  | 2 |  |  | 5 |  |  |  |  |  |
Reclassifications from AOCI, net of tax |  | — |  |  | (3) |  |  | (2) |  |  | (7) |  |  |  |  |  |
Total Other Comprehensive Income (Loss) |  | 1 |  |  | (2) |  |  | 3 |  |  | (6) |  |  |  |  |  |
Comprehensive Income (Loss) |  | 73 |  |  | 456 |  |  | (60) |  |  | 771 |  |  |  |  |  |
Less: Comprehensive income (loss) attributable to noncontrolling interest |  | — |  |  | 4 |  |  | — |  |  | 29 |  |  |  |  |  |
Comprehensive Income (Loss) Attributable to Stockholders |  | $ | 73 |  |  | $ | 452 |  |  | $ | (60) |  |  | $ | 742 |  |  |  |  |  |

The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
3

Table o f Contents
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)

(Millions of Dollars, except share data) |  | June 30, 2025 |  | December 31, 2024
Assets |  |  |  |
Cash and cash equivalents |  | $ | 122 |  |  | $ | 328 |
Restricted cash and cash equivalents (Note 16) |  | 13 |  |  | 37 |
Accounts receivable (Note 3) |  | 226 |  |  | 123 |
Inventory, net (Note 5) |  | 224 |  |  | 302 |
Derivative instruments (Notes 2 and 11) |  | 80 |  |  | 66 |
Other current assets |  | 165 |  |  | 184 |
Total current assets |  | 830 |  |  | 1,040 |
Property, plant and equipment, net (Note 7) |  | 3,089 |  |  | 3,154 |
Nuclear decommissioning trust funds (Notes 6 and 11) |  | 1,790 |  |  | 1,724 |
Derivative instruments (Notes 2 and 11) |  | — |  |  | 5 |
Other noncurrent assets |  | 118 |  |  | 183 |
Total Assets |  | $ | 5,827 |  |  | $ | 6,106 |
Liabilities and Equity |  |  |  |
Revolving credit facilities (Notes 10 and 11) |  | $ | 70 |  |  | $ | — |
Long-term debt, due within one year (Notes 10 and 11) |  | 17 |  |  | 17 |
Accrued interest |  | 30 |  |  | 18 |
Accounts payable and other accrued liabilities |  | 226 |  |  | 266 |
Derivative instruments (Notes 2 and 11) |  | 32 |  |  | — |
Other current liabilities |  | 77 |  |  | 154 |
Total current liabilities |  | 452 |  |  | 455 |
Long-term debt (Notes 10 and 11) |  | 2,972 |  |  | 2,987 |
Derivative instruments (Notes 2 and 11) |  | 62 |  |  | 7 |
Postretirement benefit obligations |  | 282 |  |  | 305 |
Asset retirement obligations and accrued environmental costs (Note 8) |  | 478 |  |  | 468 |
Deferred income taxes |  | 297 |  |  | 362 |
Other noncurrent liabilities |  | 38 |  |  | 135 |
Total Liabilities |  | $ | 4,581 |  |  | $ | 4,719 |
Commitments and Contingencies (Note 9) |  |  |  |
Stockholders' Equity (Note 15) |  |  |  |
Common stock ($0.001 par value, 350,000,000 shares authorized) (a) |  | $ | — |  |  | $ | — |
Additional paid-in capital |  | 1,711 |  |  | 1,725 |
Accumulated retained earnings (deficit) |  | (456) |  |  | (326) |
Accumulated other comprehensive income (loss) |  | (9) |  |  | (12) |
Total Stockholders' Equity |  | $ | 1,246 |  |  | $ | 1,387 |
Total Liabilities and Stockholders' Equity |  | $ | 5,827 |  |  | $ | 6,106 |

__________________
(a)45,659,227 and 45,961,910 shares issued and outstanding as of June 30, 2025 and December 31, 2024, respectively.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
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TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)

|  | Six Months Ended June 30, |  |  |  |  |
(Millions of Dollars) |  | 2025 |  | 2024 |  |  |  |  |
Operating Activities |  |  |  |  |  |  |  |  |
Net Income (Loss) |  | $ | (63) |  |  | $ | 777 |  |  |  |  |  |
Non-cash reconciliation adjustments: |  |  |  |  |  |  |  |  |
Depreciation, amortization and accretion (Note 16) |  | 141 |  |  | 144 |  |  |  |  |  |
Unrealized (gains) losses on derivative instruments (Note 2) |  | 103 |  |  | 36 |  |  |  |  |  |
Deferred income taxes |  | (66) |  |  | 94 |  |  |  |  |  |
Nuclear fuel amortization (Note 7) |  | 44 |  |  | 63 |  |  |  |  |  |
Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) (Note 6) |  | (44) |  |  | (80) |  |  |  |  |  |
(Gain) loss on AWS Data Campus Sale and ERCOT Sale (Note 17) |  | — |  |  | (886) |  |  |  |  |  |
Other (Note 16) |  | 34 |  |  | (58) |  |  |  |  |  |
Changes in assets and liabilities: |  |  |  |  |  |  |  |  |
Accounts receivable |  | (103) |  |  | (14) |  |  |  |  |  |
Inventory, net |  | 78 |  |  | 90 |  |  |  |  |  |
Other assets |  | 15 |  |  | 34 |  |  |  |  |  |
Accounts payable and accrued liabilities |  | (57) |  |  | (114) |  |  |  |  |  |
Accrued interest |  | 12 |  |  | (1) |  |  |  |  |  |
Collateral received (posted), net |  | (58) |  |  | 35 |  |  |  |  |  |
Other liabilities |  | (101) |  |  | 30 |  |  |  |  |  |
Net cash provided by (used in) operating activities |  | (65) |  |  | 150 |  |  |  |  |  |
Investing Activities |  |  |  |  |  |  |  |  |
Nuclear decommissioning trust funds investment purchases (Note 6) |  | (1,201) |  |  | (1,110) |  |  |  |  |  |
Nuclear decommissioning trust funds investment sale proceeds (Note 6) |  | 1,186 |  |  | 1,095 |  |  |  |  |  |
Property, plant and equipment expenditures (Note 7) |  | (51) |  |  | (45) |  |  |  |  |  |
Nuclear fuel expenditures (Note 7) |  | (50) |  |  | (44) |  |  |  |  |  |
Proceeds from AWS Data Campus Sale and ERCOT Sale (Note 17) |  | — |  |  | 1,089 |  |  |  |  |  |
Other |  | 2 |  |  | (6) |  |  |  |  |  |
Net cash provided by (used in) investing activities |  | (114) |  |  | 979 |  |  |  |  |  |
Financing Activities |  |  |  |  |  |  |  |  |
Share repurchases (Note 15) |  | (103) |  |  | (654) |  |  |  |  |  |
Revolving credit facility borrowings (Note 10) |  | 75 |  |  | — |  |  |  |  |  |
Revolving credit facility repayments (Note 10) |  | (5) |  |  | — |  |  |  |  |  |
Debt repayments (Note 10) |  | (9) |  |  | — |  |  |  |  |  |
Deferred financing costs |  | (9) |  |  | — |  |  |  |  |  |
Cumulus Digital TLF repayment |  | — |  |  | (182) |  |  |  |  |  |
Repurchase of noncontrolling interest |  | — |  |  | (39) |  |  |  |  |  |
Cash settlement of restricted stock units |  | — |  |  | (28) |  |  |  |  |  |
Other |  | — |  |  | (12) |  |  |  |  |  |
Net cash provided by (used in) financing activities |  | (51) |  |  | (915) |  |  |  |  |  |
Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents |  | (230) |  |  | 214 |  |  |  |  |  |
Beginning of period cash and cash equivalents and restricted cash and cash equivalents |  | 365 |  |  | 901 |  |  |  |  |  |
End of period cash and cash equivalents and restricted cash and cash equivalents |  | $ | 135 |  |  | $ | 1,115 |  |  |  |  |  |

See Note 16 for supplemental cash flow information.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
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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 |  | 45,962 |  |  | $ | 1,725 |  |  | $ | (326) |  |  | $ | (12) |  |  | $ | — |  |  |  |  | $ | — |  |  | $ | 1,387 |
Net income (loss) |  | — |  |  | — |  |  | (135) |  |  | — |  |  | — |  |  |  |  | — |  |  | (135) |
Other comprehensive income (loss) |  | — |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  |  |  | — |  |  | 2 |
Share repurchases |  | (452) |  |  | — |  |  | — |  |  | — |  |  | (85) |  |  |  |  | — |  |  | (85) |
Retirement of treasury stock |  | — |  |  | (18) |  |  | (67) |  |  | — |  |  | 85 |  |  |  |  | — |  |  | — |
Stock-based compensation |  | — |  |  | 11 |  |  | — |  |  | — |  |  | — |  |  |  |  | — |  |  | 11 |
March 31, 2025 |  | 45,510 |  |  | $ | 1,718 |  |  | $ | (528) |  |  | $ | (10) |  |  | $ | — |  |  |  |  | $ | — |  |  | $ | 1,180 |
Net income (loss) |  | — |  |  | — |  |  | 72 |  |  | — |  |  | — |  |  |  |  | — |  |  | 72 |
Other comprehensive income (loss) |  | — |  |  | — |  |  | — |  |  | 1 |  |  | — |  |  |  |  | — |  |  | 1 |
Stock-based compensation |  | 149 |  |  | (7) |  |  | — |  |  | — |  |  | — |  |  |  |  | — |  |  | (7) |
June 30, 2025 |  | 45,659 |  |  | $ | 1,711 |  |  | $ | (456) |  |  | $ | (9) |  |  | $ | — |  |  |  |  | $ | — |  |  | $ | 1,246 |

__________________
(a)Shares in thousands.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
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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, 2023 |  | 59,029 |  |  | $ | 2,346 |  |  | $ | 134 |  |  | $ | (23) |  |  | $ | — |  |  | $ | 77 |  |  | $ | 2,534 |
Net income (loss) |  | — |  |  | — |  |  | 294 |  |  | — |  |  | — |  |  | 25 |  |  | 319 |
Other comprehensive income (loss) |  | — |  |  | — |  |  | — |  |  | (4) |  |  | — |  |  | — |  |  | (4) |
Share repurchases |  | (493) |  |  | — |  |  | — |  |  | — |  |  | (39) |  |  | — |  |  | (39) |
Purchase of noncontrolling interest (b) |  | — |  |  | (15) |  |  | — |  |  | — |  |  | — |  |  | (24) |  |  | (39) |
Cash distributions |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (1) |  |  | (1) |
Non-cash distributions (c) |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | (12) |  |  | (12) |
Stock-based compensation |  | — |  |  | 8 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 8 |
March 31, 2024 |  | 58,536 |  |  | $ | 2,339 |  |  | $ | 428 |  |  | $ | (27) |  |  | $ | (39) |  |  | $ | 65 |  |  | $ | 2,766 |
Net income (loss) |  | — |  | — |  | 454 |  |  | — |  | — |  | 4 |  |  | 458 |
Other comprehensive income (loss) |  | — |  | — |  | — |  | (2) |  |  | — |  | — |  | (2) |
Share repurchases |  | (5,281) |  |  | — |  | — |  | — |  | (622) |  |  | — |  | (622) |
Retirement of treasury stock |  | — |  | (227) |  |  | (434) |  |  | — |  | 661 |  |  | — |  | — |
Cash settlement of restricted stock units |  | — |  | (28) |  |  | — |  | — |  | — |  | — |  | (28) |
Non-cash distributions (c) |  | — |  | — |  | — |  | — |  | — |  | (8) |  |  | (8) |
Stock-based compensation |  | — |  | 8 |  |  | — |  | — |  | — |  | — |  | 8 |
June 30, 2024 |  | 53,255 |  |  | $ | 2,092 |  |  | $ | 448 |  |  | $ | (29) |  |  | $ | — |  |  | $ | 61 |  |  | $ | 2,572 |

__________________
(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.
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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. Business, Basis of Presentation, and Summary of Significant Accounting Policies
Organization and Operations
Talen is a leading independent power producer and energy infrastructure company dedicated to powering the future. We own and operate approximately 10.5 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.
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 U.S. Securities and Exchange Commission (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 statement 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.
2. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including but not limited to market and commodity price risk, credit and liquidity risk, and interest rate risk. The hedging strategies deployed by our commercial and treasury organizations manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors, including the risk committee, and management have established procedures to monitor, measure, and manage hedging activities and credit risk in accordance with the risk policy.
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Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk, and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future earnings and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products, and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: (i) seasonal changes in demand; (ii) weather conditions; (iii) available regional load-serving supply; (iv) regional transportation and (or) transmission availability; (v) market liquidity; and (vi) federal, regional, and state regulations.
Within the parameters of our risk policy, we generally utilize exchange-traded and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
Open commodity purchase (sales) derivatives range in maturity through 2027. The net notional volumes of commodity derivatives were:

|  | June 30, 2025 (a) |  | December 31, 2024 (a)
Power (MWh) |  | (54,076,474) |  |  | (38,615,192) |
Natural gas (MMBtu) |  | 119,609,740 |  |  | 32,405,460 |
Emission allowances (tons) |  | — |  |  | 100,000 |

__________________
(a)The volumes may be different than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
Open interest rate derivatives mature in 2026 and 2029. The net notional volumes of open interest rate derivatives were:

|  | June 30, 2025 |  | December 31, 2024
Interest rate (in millions) |  | $ | 990 |  |  | $ | 290 |

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 June 30, 2025 and December 31, 2024.
As of June 30, 2025, Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $696 million and its credit exposure including such netting effects was $75 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 97% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
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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 June 30, 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:

|  | June 30, 2025 |  | December 31, 2024
|  | Assets |  | Liabilities |  | Assets |  | Liabilities
Commodity contracts |  | $ | 78 |  |  | $ | 30 |  |  | $ | 65 |  |  | $ | — |
Interest rate contracts |  | 2 |  |  | 2 |  |  | 1 |  |  | — |
Total current derivative instruments |  | 80 |  |  | 32 |  |  | 66 |  |  | — |
Commodity contracts |  | — |  |  | 51 |  |  | 4 |  |  | 7 |
Interest rate contracts |  | — |  |  | 11 |  |  | 1 |  |  | — |
Total non-current derivative instruments |  | $ | — |  |  | $ | 62 |  |  | $ | 5 |  |  | $ | 7 |

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 11 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 June 30, 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
June 30, 2025 |  |  |  |  |  |  |  |  |  |  |  |
Assets |  | $ | 469 |  |  | $ | (381) |  |  |  |  | $ | 88 |  |  | $ | (8) |  |  | $ | 80 |
Liabilities |  | 552 |  |  | (381) |  |  |  |  | 171 |  |  | (77) |  |  | 94 |
December 31, 2024 |  |  |  |  |  |  |  |  |  |  |  |
Assets |  | $ | 227 |  |  | $ | (154) |  |  |  |  | $ | 73 |  |  | $ | (2) |  |  | $ | 71 |
Liabilities |  | 173 |  |  | (154) |  |  |  |  | 19 |  |  | (12) |  |  | 7 |

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 June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Realized gain (loss) on commodity contracts |  |  |  |  |  |  |  |  |  |  |  |  |
Energy revenues (a) |  | $ | 43 |  |  | $ | 38 |  |  | $ | 16 |  |  | $ | 196 |  |  |  |  |  |
Fuel and energy purchases (a) |  | (5) |  |  | (8) |  |  | 19 |  |  | (7) |  |  |  |  |  |
Unrealized gain (loss) on commodity contracts |  |  |  |  |  |  |  |  |  |  |  |  |
Operating revenues (b) |  | 176 |  |  | 76 |  |  | (65) |  |  | (32) |  |  |  |  |  |
Energy expenses (b) |  | (84) |  |  | 15 |  |  | (25) |  |  | (12) |  |  |  |  |  |
Realized and unrealized gain (loss) on interest rate contracts |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense and other finance charges |  | — |  |  | 1 |  |  | (13) |  |  | 9 |  |  |  |  |  |

__________________
(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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3. Revenue
The components of operating revenues for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Capacity revenues |  | $ | 88 |  |  | $ | 46 |  |  | $ | 137 |  |  | $ | 91 |  |  |  |  |  |
Electricity sales and ancillary services, ISO/RTO |  | 307 |  |  | 249 |  |  | 889 |  |  | 514 |  |  |  |  |  |
Physical electricity sales, bilateral contracts, other |  | 14 |  |  | 22 |  |  | 37 |  |  | 86 |  |  |  |  |  |
Other revenue from customers |  | — |  |  | 29 |  |  | — |  |  | 71 |  |  |  |  |  |
Total revenue from contracts with customers |  | 409 |  |  | 346 |  |  | 1,063 |  |  | 762 |  |  |  |  |  |
Realized and unrealized gain (loss) on derivative instruments |  | 218 |  |  | 100 |  |  | (50) |  |  | 157 |  |  |  |  |  |
Nuclear PTC |  | — |  |  | 39 |  |  | — |  |  | 74 |  |  |  |  |  |
Other revenue |  | 3 |  |  | 4 |  |  | 7 |  |  | 5 |  |  |  |  |  |
Operating revenues |  | $ | 630 |  |  | $ | 489 |  |  | $ | 1,020 |  |  | $ | 998 |  |  |  |  |  |

Accounts Receivable
“Accounts receivable” presented on the Consolidated Balance Sheets were:

|  | June 30, 2025 |  | December 31, 2024
Customer accounts receivable |  | $ | 154 |  |  | $ | 66 |
Other accounts receivable |  | 72 |  |  | 57 |
Accounts receivable |  | $ | 226 |  |  | $ | 123 |

During the six months ended June 30, 2025 and 2024, there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 2 for additional information on Talen’s credit risk on the carrying value of its receivables.
Future Performance Obligations
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.
The expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:

|  | 2025 (a) |  | 2026 |  | 2027 |  | 2028 |  | 2029
Expected capacity revenues as of June 30, 2025 (b) |  | $ | 333 |  |  | $ | 275 |  |  | $ | 3 |  |  | $ | 1 |  |  | $ | — |
2026/2027 PJM Capacity Year (c) |  | — |  |  | 472 |  |  | 333 |  |  | — |  |  | — |
Total expected capacity revenues |  | $ | 333 |  |  | $ | 747 |  |  | $ | 336 |  |  | $ | 1 |  |  | $ | — |

__________________
(a)Estimated for the period from July 1, 2025 through December 31, 2025.
(b)PJM capacity revenues are estimated for the period from January 1, 2026 through May 31, 2026 for the remainder of the 2025/2026 PJM Capacity Year.
(c)PJM capacity revenues are estimated for the period from June 1, 2026 through May 31, 2027 based on the results of the 2026/2027 PJM BRA held in July 2025. Talen cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.
See Note 9 for additional information on the PJM BRAs.
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4. Income Taxes
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Income (loss) before income taxes |  | $ | 97 |  |  | $ | 570 |  |  | $ | (90) |  |  | $ | 958 |  |  |  |  |  |
Income tax benefit (expense) |  | (25) |  |  | (112) |  |  | 27 |  |  | (181) |  |  |  |  |  |
Effective tax rate |  | 25.8 | % |  | 19.6 | % |  | 30.0 | % |  | 18.9 | % |  |  |  |  |
Federal income tax statutory tax rate |  | 21 | % |  | 21 | % |  | 21 | % |  | 21 | % |  |  |  |  |
Income tax benefit (expense) computed at the federal income tax statutory tax rate |  | $ | (20) |  |  | $ | (120) |  |  | $ | 19 |  |  | $ | (201) |  |  |  |  |  |
Income tax increase (decrease) due to: |  |  |  |  |  |  |  |  |  |  |  |  |
NDT taxes |  | (12) |  |  | (4) |  |  | (10) |  |  | (15) |  |  |  |  |  |
State income taxes, net of federal benefit |  | (2) |  |  | (17) |  |  | 3 |  |  | (29) |  |  |  |  |  |
Other permanent differences |  | 9 |  |  | 6 |  |  | 15 |  |  | 12 |  |  |  |  |  |
Change in valuation allowance |  | — |  |  | 14 |  |  | — |  |  | 34 |  |  |  |  |  |
Nuclear PTC |  | — |  |  | 9 |  |  | — |  |  | 18 |  |  |  |  |  |
Income tax benefit (expense) |  | $ | (25) |  |  | $ | (112) |  |  | $ | 27 |  |  | $ | (181) |  |  |  |  |  |

One Big Beautiful Bill Act
On July 4, 2025, the One Big Beautiful Bill Act (the “OBBB”) was signed into law. The OBBB, among other things, makes key elements of the Tax Cuts and Jobs Act permanent, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. The Company is in the process of evaluating the financial effects of the OBBB to its income tax provision.
5. Inventory

|  | June 30, 2025 |  | December 31, 2024
Coal |  | $ | 67 |  |  | $ | 92 |
Oil products |  | 54 |  |  | 65 |
Fuel inventory for electric generation |  | 121 |  |  | 157 |
Materials and supplies, net |  | 100 |  |  | 88 |
Environmental products |  | 3 |  |  | 57 |
Inventory, net |  | $ | 224 |  |  | $ | 302 |

6. Nuclear Decommissioning Trust Funds

|  | June 30, 2025 |  | December 31, 2024
|  | Amortized Cost |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value |  | Amortized Cost |  | Unrealized Gains |  | Unrealized Losses |  | Fair Value
Cash equivalents |  | $ | 14 |  |  | $ | — |  |  | $ | — |  |  | $ | 14 |  |  | $ | 3 |  |  | $ | — |  |  | $ | — |  |  | $ | 3 |
Equity securities |  | 513 |  |  | 680 |  |  | (47) |  |  | 1,146 |  |  | 509 |  |  | 651 |  |  | (55) |  |  | 1,105 |
Debt securities |  | 615 |  |  | 7 |  |  | (5) |  |  | 617 |  |  | 615 |  |  | 3 |  |  | (7) |  |  | 611 |
Receivables (payables), net |  | 13 |  |  | — |  |  | — |  |  | 13 |  |  | 5 |  |  | — |  |  | — |  |  | 5 |
NDT Funds |  | $ | 1,155 |  |  | $ | 687 |  |  | $ | (52) |  |  | $ | 1,790 |  |  | $ | 1,132 |  |  | $ | 654 |  |  | $ | (62) |  |  | $ | 1,724 |

See Note 11 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of June 30, 2025 and December 31, 2024.
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As of June 30, 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 June 30, 2025 was:

|  | Fair Value |  | Unrealized Losses
Corporate debt securities |  | $ | 32 |  |  | $ | (1) |
Municipal debt securities |  | 71 |  | (2) |
U.S. Government debt securities |  | 48 |  | (1) |
Debt securities in unrealized loss position |  | $ | 151 |  |  | $ | (5) |

As of June 30, 2025, the aggregate fair value of debt securities in a loss position for a duration of one year or longer were $94 million and the unrealized losses were non-material.
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:

|  | June 30, 2025 |  | December 31, 2024
Maturities within one year |  | $ | 66 |  |  | $ | 82 |
Maturities within two to five years |  | 196 |  |  | 220 |
Maturities thereafter |  | 356 |  |  | 309 |
Debt securities, fair value |  | $ | 617 |  |  | $ | 611 |

The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Sales proceeds of NDT funds investments (a) |  | $ | 592 |  |  | $ | 535 |  |  | $ | 1,168 |  |  | $ | 1,034 |  |  |  |  |  |
Gross realized gains |  | 4 |  |  | 2 |  |  | 7 |  |  | 5 |  |  |  |  |  |
Gross realized losses |  | (3) |  |  | (3) |  |  | (5) |  |  | (6) |  |  |  |  |  |

__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.
7. Property, Plant and Equipment

|  |  |  | June 30, 2025 |  | December 31, 2024
|  | Estimated Useful Life (years) |  | Gross Value |  | Accumulated Depreciation |  | Carrying Value |  | Gross Value |  | Accumulated Depreciation |  | Carrying Value
Electric generation |  | 3-27 |  | $ | 3,091 |  |  | $ | (385) |  |  | $ | 2,706 |  |  | $ | 3,030 |  |  | $ | (292) |  |  | $ | 2,738 |
Nuclear fuel |  | 1-6 |  | 403 |  |  | (166) |  |  | 237 |  |  | 322 |  |  | (152) |  |  | 170 |
Other property and equipment |  | 1-26 |  | 61 |  |  | (8) |  |  | 53 |  |  | 90 |  |  | (18) |  |  | 72 |
Capitalized software |  | 1-5 |  | 8 |  |  | (4) |  |  | 4 |  |  | 8 |  |  | (3) |  |  | 5 |
Construction work in progress |  |  |  | 89 |  |  | — |  |  | 89 |  |  | 169 |  |  | — |  |  | 169 |
Property, plant and equipment, net |  |  |  | $ | 3,652 |  |  | $ | (563) |  |  | $ | 3,089 |  |  | $ | 3,619 |  |  | $ | (465) |  |  | $ | 3,154 |

The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Depreciation expense (a) |  | $ | 52 |  |  | $ | 56 |  |  | $ | 107 |  |  | $ | 116 |  |  |  |  |  |
Amortization expense (b) |  | 3 |  |  | 4 |  |  | 8 |  |  | 6 |  |  |  |  |  |
Accretion expense (c) |  | 15 |  |  | 15 |  |  | 29 |  |  | 28 |  |  |  |  |  |
Depreciation, amortization and accretion |  | $ | 70 |  |  | $ | 75 |  |  | $ | 144 |  |  | $ | 150 |  |  |  |  |  |

__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 8 for additional information.
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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.
Brandon Shores and H.A. Wagner Reliability Impact Assessments
In May 2025, the FERC approved each of the Brandon Shores and H.A. Wagner RMR agreements, under which: (i) Talen will operate the generation facilities in accordance with such arrangements from June 1, 2025 through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service; (ii) Brandon Shores will earn annual fixed-cost payments of $145 million ($312/MWd), inclusive of a $5 million per year unit performance “hold back;” (iii) H.A. Wagner will earn annual fixed-cost payments of $35 million ($137/MWd), inclusive of a $2 million per year unit performance “hold back;” and (iv) each facility will receive separate reimbursement for variable costs and approved project investments. Additionally, H.A. Wagner Unit 4 is subject to certain emission restrictions associated with its air permits that could limit the Unit’s runtime. On July 21, 2025, PJM filed a request for the DOE to issue an order, pursuant to Section 202(c) of the Federal Power Act, to allow Unit 4 to exceed its air permit emission limits while the facility operates under its FERC-approved RMR. The DOE entered the requested order on July 28, 2025, which is effective through October 26, 2025; Unit 4 will still be operated under and paid in accordance with the H.A. Wagner RMR agreement. Such order is subject to extension at the request of PJM and the discretion of the DOE.
Nautilus Derecognition
Under the transition terms associated with the AWS PPA as revised in June 2025, (i) the Company has ceased use of the Nautilus facility; (ii) AWS will demolish the Nautilus facility; and (iii) the facility lease between the Company and AWS, as well as the related submetering and supply arrangements, will be terminated. Accordingly, during the three months ended June 30, 2025, the Company derecognized from the Consolidated Balance Sheets approximately: (i) $15 million of structures and buildings presented as “Property, plant and equipment, net;” (ii) an aggregate $44 million of contract intangible assets and lease right-of-use assets presented as “Other noncurrent assets;” (iii) $10 million of lease liabilities presented as “Other current liabilities;” and (iv) an aggregate $57 million contractual obligations and lease obligations presented as “Other noncurrent liabilities.” The resulting net gain of $8 million is presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.
8. Asset Retirement Obligations and Accrued Environmental Costs

|  | June 30, 2025 |  | December 31, 2024
Asset retirement obligations |  | $ | 511 |  |  | $ | 498 |
Accrued environmental costs |  | 21 |  |  | 21 |
Total asset retirement obligations and accrued environmental costs |  | 532 |  |  | 519 |
Less: asset retirement obligations and accrued environmental costs due within one year (a) |  | 54 |  |  | 51 |
Asset retirement obligations and accrued environmental costs due after one year |  | $ | 478 |  |  | $ | 468 |

__________________
(a)Presented as “Other current liabilities” 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 Company’s most significant obligations are associated with the: (i) decommissioning of Susquehanna, which the NDT is expected to fund; and (ii) coal ash disposal units of legacy coal-fired generation facilities which, for certain obligations, the Company has posted surety bonds (some of which have been collateralized with LCs). The carrying value of these AROs include assumptions of estimated future retirement and remediation cash expenditures, cost escalation rates, probabilistic cash flow models, and discount rates.
As environmental regulations issued by the EPA or other rulemaking entities may require the Company to revise and (or) recognize new AROs, the carrying value of AROs, in particular those associated with legacy coal-fired generation facilities, may be impacted by current or future regulatory rulemaking. As of June 30, 2025, the fair values of certain AROs as a result of the EPA CCR Rule cannot be determined. See Note 9 for additional information on the EPA CCR Rule and the regulatory timeline that is expected to determine the associated scope of work.
Additionally, certain subsidiaries of the Company have legal retirement obligations associated with the removal, disposal, and (or) monitoring of asbestos-containing material at certain generation facilities. Given that the ultimate volume of asbestos-containing material is not yet known, the fair value of these obligations cannot be reasonably estimated. These obligations will be recognized upon a change in economic events or other circumstances which enables the fair value to be estimable.
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The changes of the ARO carrying value during the period were:

December 31, 2024 |  | $ | 498 |
Obligations settled |  | (12) |
Changes in estimates and (or) settlement dates |  | (3) |
Accretion expense |  | 28 |
June 30, 2025 |  | $ | 511 |

The disaggregation of ARO carrying values on the Consolidated Balance Sheets were:

|  | June 30, 2025 |  | December 31, 2024
Supplemental Information |  |  |  |
Nuclear (a) |  | $ | 257 |  |  | $ | 242 |
Non-nuclear (b) |  | 254 |  |  | 256 |
Carrying value |  | $ | 511 |  |  | $ | 498 |

__________________
(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 11 for additional information on the NDT.
(b)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with LCs; or (ii) partially prefunded under phased installment agreements.
See “Talen Montana Financial Assurance” in Note 9 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip.
9. Commitments and Contingencies
Legal, Regulatory, and Environmental Matters
We are regularly subject to various legal, regulatory, and environmental matters in connection with our business. While we believe we have meritorious positions and will continue to vigorously defend our positions in these matters, we may not be successful in our efforts, and we cannot predict the effect of an adverse outcome of any such matter. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal, regulatory, and environmental matters and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding any matter specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial. Unless otherwise disclosed below, we are unable to predict the outcome of any matter discussed below or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that the outcome of any such matter, including market modifications, could materially impact our business, financial condition, results of operations, cash flows, and (or) liquidity.
Legal Matters
We are involved in various legal and administrative proceedings, investigations, claims, and litigation from time to time in the course of our business. Such matters may include, but are not limited to, those relating to employment and benefits, commercial disputes, personal injury, property damage, regulatory matters, environmental matters, and various other claims for injuries and (or) damages. While we believe we have meritorious positions and will continue to appropriately respond to all legal matters, because of the inherently unpredictable nature of legal proceedings, there is a wide range of potential outcomes for any such matter.
Labor Market Antitrust Class Action Lawsuit Against Nuclear Power Generators. On July 11, 2025, two individuals filed a class action in the U.S. District Court for the District of Maryland against Human Resources Consultants, LLC, Accelerant Technologies, and 26 nuclear power companies, including Talen, alleging that since at least May 2003 the defendants conspired to fix and suppress employee wages and benefits in violation of federal antitrust law. The proposed class includes a wide range of nuclear power generation workers, such as nuclear operators, engineers, and technicians, who were compensated with hourly wages or annual salaries, as well as benefits and other forms of compensation. The complaint alleges that the nuclear power operators used Accelerant and HR Consultants to facilitate a conspiracy to exchange employee compensation data and held in-person meetings where the power companies aligned on wage schedules, suppressed wages, and fixed compensation. The plaintiffs are seeking treble damages, injunctive relief, a declaratory judgment that the defendants’ conduct violated Section 1 of the Sherman Antitrust Act, attorneys’ fees, and costs of suit. Talen believes the alleged claims are without merit and will vigorously defend itself.
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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. Talen filed a motion to dismiss the lawsuit on June 2, 2025, which was followed by an amicus brief from the Utility Solid Waste Activities Group in support of Talen’s motion; briefing on the motion to dismiss was completed on June 30, 2025. No assurance can be provided as to the outcome of the litigation or its impacts on Talen’s operations.
ERCOT Weather Event (Winter Storm Uri) Lawsuits. In connection with the ERCOT Sale, the Company retained certain potential liabilities relating to claims filed from 2021 onward against its former Texas subsidiaries seeking unspecified damages for alleged losses caused by the defendants’ failure to provide sufficient power to the grid during Winter Storm Uri. The claims also allege similar liability against numerous other ERCOT power market participants. In December 2023, five multi-district litigation (“MDL”) bellwether lawsuits, which were selected by the MDL court as representative of all 58 cases filed in the Uri litigation, were dismissed by the MDL court, a ruling subsequently upheld by the Texas First Court of Appeals. In January and February 2025, the plaintiffs (in two groups) filed for relief in the Texas Supreme Court, seeking to overturn the lower courts. In July 2025, the Texas Supreme Court ordered merits briefing by the parties. If the Court of Appeals decision is affirmed by the Texas Supreme Court, Talen expects the dismissal ruling to apply broadly to all Uri cases against Talen’s former subsidiaries. Pursuant to the Plan of Reorganization, Talen’s maximum potential damages on prepetition Uri claims are expressly limited to payments from Talen’s insurers. However, claims filed after Talen’s restructuring by plaintiffs who did not receive effective notice of the restructuring, if any, may not be subject to the limitations in the Plan of Reorganization.
Spent Nuclear Fuel Litigation. Federal law requires the U.S. government to provide for the permanent disposal of commercial spent nuclear fuel (“SNF”), but the government has not yet done so. Until May 2014, the DOE required nuclear generation facility operators to contribute to a fund intended to pay for the transportation and disposal of SNF, and Talen cannot predict if or when the government will reinstate any such fee in the future. In May 2023, an existing settlement agreement between Susquehanna and the U.S. government was extended through the end of 2025. The settlement agreement requires the government to reimburse Susquehanna for certain SNF storage costs through 2025 and requires Susquehanna to waive certain claims against the government relating to temporary SNF storage. In July 2025, the Company reached an agreement with the DOE for a reimbursement of $14 million (reflecting Talen’s 90% share) related to the 2023-2024 period.
Regulatory Matters
We are subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to the FERC; the DOE; the NRC; NERC; the Federal Communications Commission; and state public utility commissions. In addition, the RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. Accordingly, we are subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules.
PJM Capacity Market Reform. In June 2023, the FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order for PJM to propose market reforms. PJM filed its market reform proposals with the FERC in October 2023. In early 2024, the FERC accepted portions of PJM’s proposed market changes. 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 the 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 the FERC considering the Sierra Club’s complaints about RMR resources in isolation and therefore intended to file a Section 205 proceeding under the Federal Power Act seeking the FERC’s approval of to-be-determined market reforms, including but not limited to potential revisions to the treatment of RMR resources. As a result, in October 2024, PJM formally requested that the 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, the FERC approved the auction delays. The 2026/2027 PJM BRA was held in July 2025. Talen can provide no assurance that the remaining three scheduled auctions will be held as scheduled or at all.
A series of filings aimed at reforming the PJM capacity market were filed at the FERC. In November 2024, the Joint Consumer Advocates, comprised of consumer advocacy groups and government entities from Illinois, Maryland, New Jersey, Ohio, and the District of Columbia filed a complaint against PJM asking the FERC to find that PJM’s existing capacity market rules are unjust and unreasonable and to issue an order requiring certain short-term and longer-term changes to PJM’s capacity market rules.
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In response, PJM made two FERC filings in December 2024 to address what they perceive as capacity market design issues (the “PJM Capacity Market 205 Proceeding”). PJM proposed to retain the dual fuel combustion turbine as the reference resource and to implement a uniform non-performance charge throughout the RTO for the 2026/2027 and 2027/2028 delivery years, and to administratively include RMR units that meet certain criteria as price takers in the capacity auctions for the next two delivery years and will not assess penalties or pay bonuses to these RMR units. PJM’s filing also clarifies that being excused from being required to offer into the capacity market is no defense to exercising market power by electing not to offer. Further, PJM proposed to make changes to the capacity market mitigation rules. This proposal will eliminate the must-offer exception for intermittent and limited duration resources that are eligible to participate in the capacity market and will allow market sellers to incorporate a risk component in their capacity market offers. In February 2025, the FERC accepted PJM’s proposals in the PJM Capacity Market 205 Proceeding and as a result, the changes to the PJM BRA parameters described above as part of that proceeding will be adopted for the 2026/2027 and 2027/2028 PJM Capacity Years.
In December 2024, the Pennsylvania Governor filed a complaint against PJM at the FERC to address alleged elevated costs to consumers from the PJM capacity market in the 2026/2027 and 2027/2028 delivery years and proposed, among other things, a lower capacity price cap. As a result of a subsequent agreement between the State of Pennsylvania and PJM that resolved the Governor’s complaint, the Governor withdrew the complaint in February 2025. In April 2025, the FERC accepted PJM’s proposals reflecting its agreement with the State of Pennsylvania. As a result, the PJM BRA imposed a price collar with an approximate minimum and maximum price of $175/MWd and $325/MWd, respectively, which was effective for the 2026/2027 PJM BRA and will also be effective for the 2027/2028 PJM BRA. The 2026/2027 PJM BRA was held in July 2025. See Note 3 for additional information on the results.
In February 2025, the FERC initiated a technical conference docket to consider broad resource adequacy issues across all RTOs, with the initial proceedings taking place in June 2025. The Company has intervened in the new technical conference docket and is closely monitoring those proceedings.
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. Certain executive orders have subsequently been challenged by states and individual plaintiffs. Future provisions, implementation, and enforcement of these executive actions and the environmental rules has continued to be uncertain. Further, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed in other ways.
EPA CSAPR and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA revised the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”). This action triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (the “Good Neighbor Plan”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey were subject to the new rule; however, the entire rule was challenged by multiple parties, and subsequently the Good Neighbor Plan was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the D.C. Circuit Court of Appeals. In November 2024, the EPA issued an interim final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive Revised CSAPR Update Rule until the Good Neighbor Plan matter is resolved. After initially denying the EPA’s request in February 2025, the D.C. Circuit Court of Appeals on April 14, 2025, granted the EPA’s motion requesting the Good Neighbor Plan litigation be held in abeyance pending the EPA’s review of the stayed rule and further orders by the court. As a result, future implementation and enforcement of the Good Neighbor Plan remains has continued to be uncertain.
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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). If the rule remains in effect, 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 a 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 2024 rule remains pending in the D.C. Circuit Court of Appeals. The litigation has been held in abeyance since February 2025, while the EPA reconsiders the rule. 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 formally announced that it was reconsidering the 2024 EPA MATS Rule as part of its deregulation agenda. Concurrently, the Trump administration announced it was considering a two-year exemption from compliance obligations via Section 112(i)(4) of the Clean Air Act for affected power plants while the EPA 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. On June 11, 2025, the EPA proposed a rule to repeal certain 2024 amendments to the EPA MATS Rule and revert to standards promulgated in the 2012 EPA MATS Rule. The EPA is accepting public comments on its proposal until August 11, 2025. The day after the EPA announced its reconsideration rule, multiple environmental groups filed a lawsuit in the U.S. District Court for D.C. challenging the presidential exemptions issued to Colstrip and other fossil fuel-fired power plants. The Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on the reconsideration rule and (or) litigation.
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.
The D.C. Circuit Court of Appeals has held the litigation in abeyance since February 2025 to allow the EPA to reconsider the rule. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. On June 11, 2025, the EPA released a proposed rule to repeal all GHG emission standards for fossil fuel-fired power plants. As an alternative, the EPA is proposing a narrow repeal of GHG standards, which would eliminate all emissions guidelines and standards for existing power plants and the Phase 2 GHG emissions standards that would apply to new combustion turbines beginning in 2032. Under the alternative proposal, Phase 1 GHG emissions standards applicable to new and reconstructed baseload fossil fuel-fired stationary combustion turbines would be retained. The EPA is accepting public comments on its proposal until August 7, 2025. The EPA has also in the past stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed and no recent statements have been made. Operating decisions about the future of Colstrip are highly dependent on the fate of the EPA GHG Rule as well as the EPA MATS Rule. Given the legal and regulatory uncertainties with both rules, it is possible the Company will be required to make decisions about Colstrip’s future before it has clarity about the outcome of litigation and (or) the EPA’s regulations.
GHG Endangerment Finding. In July 2025, the EPA also issued a proposal to repeal its 2009 finding that greenhouse gases (“GHGs”) endanger public health and welfare. The EPA made the 2009 endangerment finding in order to promulgate GHG emission standards for new motor vehicles under Section 202(a) of the Clean Air Act. The EPA has subsequently relied on its 2009 endangerment finding as a basis to regulate other sources of GHGs, including power plants. If finalized, the EPA’s proposal would repeal all GHG emission standards for light-, medium-, and heavy-duty vehicles and engines. The proposed rule does not explicitly state how a repeal of the 2009 endangerment finding would impact its authority to regulate GHG emissions from stationary sources. However, the EPA states that the endangerment finding has been broadly used to justify regulation of stationary sources in a manner inconsistent with the Clean Air Act. The EPA also notes that it is currently reconsidering its authority to regulate GHGs from other sources, including stationary sources, in separate rulemakings. The EPA will accept public comment on its proposal for 45 days once it is published in the Federal Register. No assurance can be provided as to whether the rule will be finalized and whether a final rule will survive judicial challenge.
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Pennsylvania RGGI. In October 2019, the then-Governor of Pennsylvania signed an executive order directing the Pennsylvania Department of Environmental Protection (the “PADEP”) to draft regulations establishing a cap-and-trade program with the intent of enabling Pennsylvania to join the RGGI, a multi-state regional cap-and-trade program comprised of several Eastern U.S. states. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, in November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The PADEP appealed this decision to the Pennsylvania Supreme Court and filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups to intervene in the case. Oral argument in the case took place in May 2025. 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. At the EPA’s request, the Eighth Circuit has held the consolidated challenges in abeyance since February 2025 to allow the EPA to reconsider the rule. In March 2025, the EPA announced that it will revise the EPA ELG Rule as part of its deregulation agenda while considering immediate relief from some of the existing leachate requirements. In June 2025, the EPA announced that it will issue a proposal in the summer of 2025 to revise the ELGs for coal-fired power plants. The EPA stated its proposed rule would extend compliance deadlines under the 2024 EPA ELG Rule and seek information to potentially inform further rulemaking. 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. At the EPA’s request, the D.C. Circuit Court of Appeals has held the case in abeyance since February 2025 to allow the EPA to reconsider the rule. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs. In March 2025, the EPA announced that it will prioritize the coal ash program by expediting state permit reviews and complete a rule change within a year. In July 2025, the EPA issued a direct final rule and companion proposal extending compliance deadlines for elements of the Legacy CCR Rule. The rule will take effect six months after being published in the Federal Register unless the EPA receives adverse comments on the rule. If adverse comments are received, the EPA will proceed with a traditional notice-and-comment rulemaking. No assurance can be provided 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.
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As of June 30, 2025, the Company has recognized cost estimates in complying with the Legacy CCR Rule’s initial compliance requirements and deadlines, including the initial groundwater monitoring requirements. The Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on Talen’s operations and (or) financial condition.
In April 2025, a citizen suit was filed in the U.S. District Court for the Middle District of Pennsylvania alleging that the Company and its subsidiary, Brunner Island, LLC, are in violation of RCRA and the EPA CCR Rule. See the “Legal Matters” section above for additional information.
Certain Resolved Matters
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 June 30, 2025 and December 31, 2024, the aggregate amount of surety bonds outstanding was $263 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 wa s $114 million and $125 million as of June 30, 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 8 for additional information on Colstrip AROs.
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10. Long-Term Debt and Other Credit Facilities
TES is the borrower/issuer under all the Company’s debt and credit facilities. As of June 30, 2025, TES was not in default under any of its debt or credit agreements.
Long-Term Debt

|  | Interest Rate (a) |  | June 30, 2025 |  | December 31, 2024
TLB-1 |  | 6.81 % |  | $ | 853 |  |  | $ | 857 |
TLB-2 |  | 6.81 % |  | 846 |  |  | 850 |
Secured Notes |  | 8.63 % |  | 1,200 |  |  | 1,200 |
PEDFA 2009B Bonds |  | 5.25 % |  | 50 |  |  | 50 |
PEDFA 2009C Bonds |  | 5.25 % |  | 81 |  |  | 81 |
Total principal |  |  |  | 3,030 |  |  | 3,038 |
Unamortized deferred financing costs and original issuance discounts |  |  |  | (41) |  |  | (34) |
Total carrying value |  |  |  | 2,989 |  |  | 3,004 |
Less: long-term debt, due within one year |  |  |  | 17 |  |  | 17 |
Long-term debt |  |  |  | $ | 2,972 |  |  | $ | 2,987 |

__________________
(a)Computed interest rate as of June 30, 2025.
Revolving Credit and Other Facilities

|  |  |  | June 30, 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 |  | $ | 700 |  |  | $ | 70 |  |  | $ | — |  |  | $ | 630 |  |  | $ | — |  |  | $ | — |  |  | $ | 700 |  |  |  |  |  |
LCF |  | December 2026 |  | 900 |  |  | — |  |  | 413 |  |  | 487 |  |  | — |  |  | 374 |  |  | 526 |  |  |  |  |  |
Total |  |  |  | $ | 1,600 |  |  | $ | 70 |  |  | $ | 413 |  |  | $ | 1,117 |  |  | $ | — |  |  | $ | 374 |  |  | $ | 1,226 |  |  |  |  |  |

__________________
(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 June 30, 2025 and December 31, 2024, the amounts of such backstop LCs issued under the LCF were $13 million and $297 million, respectively (which are included in the totals above).
Debt Commitment Letters
In connection with the Freedom and Guernsey Acquisitions, TES entered into debt commitment letters, dated July 17, 2025, pursuant to which Citigroup Global Markets Inc. and RBC Capital Markets have agreed to provide TES with: (i) senior secured bridge facilities in an aggregate principal amount of up to $1.2 billion; and (ii) senior unsecured bridge facilities in an aggregate principal amount of up to $2.6 billion. The funding is contingent upon the satisfaction of certain conditions set forth in the debt commitment letters. See Note 17 for additional information on the Freedom and Guernsey Acquisitions.
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 $102 million under Secured ISDAs as of June 30, 2025.
11. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT.
•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.
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•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:

|  | June 30, 2025 |  | December 31, 2024
|  | Level 1 |  | Level 2 |  |  |  | NAV |  | Netting (a) |  | Total |  | Level 1 |  | Level 2 |  |  |  | NAV |  | Netting (a) |  | Total
Assets |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Cash equivalents |  | $ | — |  |  | $ | — |  |  |  |  | $ | 14 |  |  | $ | — |  |  | $ | 14 |  |  | $ | — |  |  | $ | — |  |  |  |  | $ | 3 |  |  | $ | — |  |  | $ | 3 |
Equity securities (b) |  | 786 |  | — |  |  |  |  | 360 |  |  | — |  |  | 1,146 |  |  | 758 |  |  | — |  |  |  |  | 347 |  |  | — |  |  | 1,105 |
U.S. government debt securities |  | 330 |  | — |  |  |  |  | — |  |  | — |  |  | 330 |  |  | 353 |  |  | — |  |  |  |  | — |  |  | — |  |  | 353 |
Municipal debt securities |  | — |  |  | 96 |  |  |  |  | — |  |  | — |  |  | 96 |  |  | — |  |  | 85 |  |  |  |  | — |  |  | — |  |  | 85 |
Corporate debt securities |  | — |  |  | 191 |  |  |  |  | — |  |  | — |  |  | 191 |  |  | — |  |  | 173 |  |  |  |  | — |  |  | — |  |  | 173 |
Receivables (payables), net (c) |  | — |  |  | — |  |  |  |  | — |  |  | — |  |  | 13 |  |  | — |  |  | — |  |  |  |  | — |  |  | — |  |  | 5 |
NDT funds |  | 1,116 |  |  | 287 |  |  |  |  | 374 |  |  | — |  |  | 1,790 |  |  | 1111 |  |  | 258 |  |  |  |  | 350 |  |  | — |  |  | 1,724 |
Commodity derivatives |  | 360 |  |  | 107 |  |  |  |  | — |  |  | (389) |  |  | 78 |  |  | 134 |  |  | 91 |  |  |  |  | — |  |  | (156) |  |  | 69 |
Interest rate derivatives |  | — |  |  | 2 |  |  |  |  | — |  |  | — |  |  | 2 |  |  | — |  |  | 2 |  |  |  |  | — |  |  | — |  |  | 2 |
Total assets |  | $ | 1,476 |  |  | $ | 396 |  |  |  |  | $ | 374 |  |  | $ | (389) |  |  | $ | 1,870 |  |  | $ | 1,245 |  |  | $ | 351 |  |  |  |  | $ | 350 |  |  | $ | (156) |  |  | $ | 1,795 |
Liabilities |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Commodity derivatives |  | $ | 429 |  |  | $ | 110 |  |  |  |  | $ | — |  |  | $ | (458) |  |  | $ | 81 |  |  | $ | 145 |  |  | $ | 29 |  |  |  |  | $ | — |  |  | $ | (167) |  |  | $ | 7 |
Interest rate derivatives |  | — |  |  | 13 |  |  |  |  | — |  |  | — |  |  | 13 |  |  | — |  |  | — |  |  |  |  | — |  |  | — |  |  | — |
Total liabilities |  | $ | 429 |  |  | $ | 123 |  |  |  |  | $ | — |  |  | $ | (458) |  |  | $ | 94 |  |  | $ | 145 |  |  | $ | 29 |  |  |  |  | $ | — |  |  | $ | (167) |  |  | $ | 7 |

__________________
(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 June 30, 2025 and December 31, 2024.
Nonrecurring Fair Value Measurements
See Note 7 for nonrecurring fair value measurements during the three months ended June 30, 2025 that are associated with the derecognition of certain Nautilus assets and liabilities. There were no nonrecurring fair value measurements related to impairments of long-lived assets during the three months ended June 30, 2024 and the three and six months ended June 30, 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.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:

|  | June 30, 2025 |  | December 31, 2024
|  | Carrying Value |  | Fair Value |  | Carrying Value |  | Fair Value
Revolving credit facilities |  | $ | 70 |  |  | $ | 70 |  |  | $ | — |  |  | $ | — |
Long-term debt (a) |  | 2,989 |  |  | 3,113 |  |  | 3,004 |  |  | 3,120 |

__________________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
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12. Postretirement Benefit Obligations
TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and a defined contribution plan.
The components of net periodic benefit costs for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |
Postretirement benefits service cost (a) |  | $ | — |  |  | $ | 1 |  |  | $ | 1 |  |  | $ | 2 |  |  |  |
Postretirement benefit (gain) loss |  |  |  |  |  |  |  |  |  |  |
Interest cost |  | $ | 17 |  |  | $ | 17 |  |  | 34 |  |  | 33 |  |  |  |
Expected return on plan assets |  | (18) |  |  | (17) |  |  | (37) |  |  | (35) |  |  |  |
Amortization of: |  |  |  |  |  |  |  |  |  |  |
Postretirement prior service cost (credit) |  | (1) |  |  | — |  |  | (2) |  |  | — |  |  |  |
Postretirement benefit (gain) loss, net (b) |  | $ | (2) |  |  | $ | — |  |  | (5) |  |  | (2) |  |  |  |
Net periodic defined benefit cost (credit) |  | $ | (2) |  |  | $ | 1 |  |  | $ | (4) |  |  | $ | — |  |  |  |

_____________
(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.
13. Stock-Based Compensation
In June 2023, TEC began granting performance stock units (“PSUs”) and restricted stock units (“RSUs”) to certain employees and non-employee directors under the Company’s 2023 Equity Incentive Plan (the “Equity Plan”). The aggregate number of shares authorized for issuance under the Equity Plan is 7,083,461 shares of common stock.
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 June 30, |  | Six Months Ended June 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
Stock-based compensation expense |  | $ | 16 |  |  | $ | 8 |  |  | $ | 27 |  |  | $ | 16 |
Income tax benefit |  | (4) |  |  | (2) |  |  | (7) |  |  | (4) |
After-tax stock-based compensation expense |  | $ | 12 |  |  | $ | 6 |  |  | $ | 20 |  |  | $ | 12 |

Performance Stock Units
PSUs have three-year ratable or two-year cliff vesting schedules or vest upon consummation of a change in control event based on the satisfaction of a continued employment condition and the achievement of certain market conditions over a performance period. Participants will be awarded additional PSUs if market conditions exceed targets at the time of vesting. If the Company declares any cash dividends while the PSUs are outstanding, participants will be credited a dividend, payable at the time of vesting, based on the number of shares of common stock underlying the PSUs. The following table summarizes the Company’s non-vested PSUs and changes during the year:

|  | Units (a) |  | Weighted-Average Grant Date Fair Value per Unit
Non-vested as of December 31, 2024 |  | 956,347 |  |  | $ | 54.23 |
Granted |  | 101,825 |  |  | 463.10 |
Non-vested as of June 30, 2025 (b) |  | 1,058,172 |  |  | $ | 93.58 |

_____________
(a)Represents the target number of PSUs.
(b)Subject to the PSU award agreements, the actual amount of PSUs earned by participants at vesting can range from 0% to 200% of the target number of PSUs based on the Company’s stock price performance. In addition, certain of the PSUs are eligible to earn an additional amount of Talen shares based on the incremental Company stock price performance in excess of the PSU targets. Based on the share price of the Company’s common stock as of June 30, 2025, the aggregate non-vested PSUs were 2,337,445.
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As of June 30, 2025, $54 million of unrecognized compensation cost related to unvested PSUs granted are expected to be recognized over a weighted average period of approximately 1.0 years.
The fair value of the PSUs was determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date and the significant inputs and assumptions summarized below:

|  | Six Months Ended June 30, 2025 |  |
Volatility (a) |  | 40 | % |  |
Expected term (in years) |  | 2 |  |
Risk-free rate (b) |  | 3.99 | % |  |

__________________
(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 |  | 549,405 |  |  | $ | 55.07 |
Granted |  | 52,514 |  |  | 207.95 |
Vested |  | (236,553) |  |  | (48.10) |
Non-vested as of June 30, 2025 |  | 365,366 |  |  | $ | 81.56 |

As of June 30, 2025, $23 million of unrecognized compensation cost related to unvested RSUs granted are expected to be recognized over a weighted average period of approximately 1.0 years.
14. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were:

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Numerator: (Millions of Dollars) |  |  |  |  |  |  |  |  |  |  |  |  |
Net Income (Loss) |  | $ | 72 |  |  | $ | 458 |  |  | $ | (63) |  |  | $ | 777 |  |  |  |  |  |
Less: |  |  |  |  |  |  |  |  |  |  |  |  |
Net income (loss) attributable to noncontrolling interest |  | — |  |  | 4 |  |  | — |  |  | 29 |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders |  | $ | 72 |  |  | $ | 454 |  |  | $ | (63) |  |  | $ | 748 |  |  |  |  |  |
Denominator: (Thousands) |  |  |  |  |  |  |  |  |  |  |  |  |
Weighted-Average Number of Common Shares Outstanding - Basic |  | 45,554 |  |  | 57,434 |  |  | 45,699 |  |  | 58,119 |  |  |  |  |  |
Warrants |  | — |  |  | 268 |  |  | — |  |  | 234 |  |  |  |  |  |
Restricted stock units |  | 257 |  |  | 332 |  |  | — |  |  | 262 |  |  |  |  |  |
Performance stock units |  | 2,095 |  |  | 1,741 |  |  | — |  |  | 1,654 |  |  |  |  |  |
Weighted-Average Number of Common Shares Outstanding - Diluted |  | 47,905 |  |  | 59,775 |  |  | 45,699 |  |  | 60,269 |  |  |  |  |  |
Earnings per Share - Basic |  | $ | 1.58 |  |  | $ | 7.90 |  |  | $ | (1.38) |  |  | $ | 12.87 |  |  |  |  |  |
Earnings per Share - Diluted |  | 1.50 |  |  | 7.60 |  |  | (1.38) |  |  | 12.41 |  |  |  |  |  |

Diluted EPS for the three months ended June 30, 2025 excludes 83,347 PSUs due to their anti-dilutive nature. As there is a Net Loss Attributable to Stockholders for the six months ended June 30, 2025, the computation of diluted EPS excludes 266,938 RSUs and 2,166,138 PSUs.
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15. Stockholders’ Equity
Share Repurchase Program
As of June 30, 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 June 30, 2025 is $995 million. See Note 18 to the Annual Financial Statements for additional information relating to the SRP.
Summary of activity under the SRP:

|  | Three Months Ended June 30, 2025 |  | Six Months Ended June 30, 2025
|  | Number of Shares |  | Share Price (a) |  | Total Amount |  | Number of Shares |  | Share Price (a) |  | Total Amount
Share repurchases |  | — |  |  | $ | — |  |  | $ | — |  |  | 452,130 |  |  | $ | 186.24 |  |  | $ | 85 |
Share retirements |  | — |  |  | — |  |  | — |  |  | 452,130 |  |  | 186.24 |  |  | 85 |

__________________
(a)Weighted average price per share, including transaction costs and excise taxes.
Acquisition of Noncontrolling Interests
Purchase of Equity in Cumulus Digital. In March 2024, TES acquired all of the equity of Cumulus Digital held by affiliates of Orion Energy Partners and two former members of Talen senior management in exchange for an aggregate of $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital.
Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:

|  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  |  |  |  |
Beginning balance |  | $ | (12) |  |  | $ | (23) |  |  |  |  |  |
Gains (losses) arising during the period |  | 8 |  |  | 1 |  |  |  |  |  |
Reclassifications to Consolidated Statements of Operations |  | (4) |  |  | (12) |  |  |  |  |  |
Income tax benefit (expense) |  | (1) |  |  | 5 |  |  |  |  |  |
Other comprehensive income (loss) |  | 3 |  |  | (6) |  |  |  |  |  |
Accumulated other comprehensive income (loss) |  | $ | (9) |  |  | $ | (29) |  |  |  |  |  |

The components of AOCI, net of tax, as of June 30, were:

|  | 2025 |  | 2024 |  |  |
Available-for-sale securities unrealized gain (loss), net |  | $ | 1 |  |  | $ | (1) |  |  |  |
Postretirement benefit prior service credits (costs), net |  | 13 |  |  | — |  |  |  |
Postretirement benefit actuarial gain (loss), net |  | (23) |  |  | (28) |  |  |  |
Accumulated other comprehensive income (loss) |  | $ | (9) |  |  | $ | (29) |  |  |  |

Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the six months ended June 30, 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 12 for additional information.
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16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:

|  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  |  |  |  |
Cash paid during the period |  |  |  |  |  |  |  |  |
Interest and other finance charges, net of capitalized interest (a) |  | $ | 107 |  |  | $ | 124 |  |  |  |  |  |
Income taxes, net (b) |  | 70 |  |  | 9 |  |  |  |  |  |
Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows |  |  |  |  |  |  |  |  |
Commodity contracts |  | $ | 90 |  |  | $ | 44 |  |  |  |  |  |
Interest rate swap contracts (interest expense) |  | 13 |  |  | (8) |  |  |  |  |  |
Unrealized (gain) loss on derivative instruments |  | $ | 103 |  |  | $ | 36 |  |  |  |  |  |
Depreciation, amortization and accretion included on the Statements of Cash Flows |  |  |  |  |  |  |  |  |
Depreciation, amortization and accretion |  | $ | 144 |  |  | $ | 150 |  |  |  |  |  |
Other |  | (3) |  |  | (6) |  |  |  |  |  |
Depreciation, amortization and accretion |  | $ | 141 |  |  | $ | 144 |  |  |  |  |  |
Reconciliation of other non-cash operating activities |  |  |  |  |  |  |  |  |
Derivative option premium amortization |  | $ | 33 |  |  | $ | 4 |  |  |  |  |  |
Stock-based compensation |  | 27 |  |  | 16 |  |  |  |  |  |
(Gain) loss on sale of assets, net |  | (12) |  |  | — |  |  |  |  |  |
Bitcoin revenue |  | — |  |  | (71) |  |  |  |  |  |
Other |  | (14) |  |  | (7) |  |  |  |  |  |
Total |  | $ | 34 |  |  | $ | (58) |  |  |  |  |  |
Non-cash investing activities |  |  |  |  |  |  |  |  |
Capital expenditure accrual increase (decrease) |  | $ | 4 |  |  | $ | (16) |  |  |  |  |  |

__________________
(a)Capitalized interest was $2 million and $3 million for the six months ended June 30, 2025 and 2024, respectively.
(b)During the six months ended June 30, 2025 and 2024, $20 million and $51 million of estimated Nuclear PTCs were utilized as a credit against our federal income tax payable, respectively.
Cash and Restricted Cash
“Restricted cash and cash equivalents” of $13 million and $37 million presented on the Consolidated Balance Sheets as of June 30, 2025 and December 31, 2024, respectively, were comprised of commodity exchange margin deposits.
17. Acquisitions and Divestitures
2025 Pending Acquisitions
Freedom and Guernsey Acquisitions. On July 17, 2025, the Company entered into two purchase and sale agreements (the “Purchase Agreements”) with affiliates of Caithness Energy pursuant to which it agreed to purchase (i) the Freedom Energy Center, a 1,045 MW (summer rating) natural gas fired combined cycle generation plant located in Luzerne County, Pennsylvania, for approximately $1.5 billion in cash; and (ii) the Guernsey Power Station, a 1,836 MW (summer rating) natural gas fired combined cycle generation plant located in Guernsey County, Ohio, for approximately $2.3 billion in cash, in each case as adjusted in accordance with the applicable Purchase Agreement. At closing, the Company is required under each Purchase Agreement to deposit with an escrow agent cash equal to 1% of the purchase price to secure the payment of certain customary post-closing purchase price adjustments.
Each transaction is subject to the satisfaction of customary closing conditions, including the expiration or termination of the waiting period pursuant to the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (the “HSR Act”), and regulatory approvals from the FERC and other regulatory agencies. These regulatory filings have all been made and are now pending at the agencies. The Purchase Agreements provide that either we or the sellers can terminate the applicable agreement if the respective acquisition is not completed by July 17, 2026 (which may be automatically extended to January 17, 2027 in the case of pending antitrust or regulatory approvals). Under certain circumstances, we may be required to pay the sellers a termination fee of approximately $63 million in the case of Freedom and $100 million in the case of Guernsey if the applicable acquisition is not consummated. The Freedom and Guernsey Acquisitions are both expected to close in the fourth quarter 2025.
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In connection with the Freedom and Guernsey Acquisitions, TES entered into debt commitment letters pursuant to which Citigroup Global Markets Inc. and RBC Capital Markets have agreed to provide TES with: (i) senior secured bridge facilities in an aggregate principal amount of up to $1.2 billion; and (ii) senior unsecured bridge facilities in an aggregate principal amount of up to $2.6 billion. See Note 10 for additional information.
2025 Pending Divestitures
Camden and Dartmouth Sales. In June 2025, we entered into a purchase and sale agreement to sell the Camden and Dartmouth generation facilities to Partners Group for an aggregate $32 million in cash, subject to customary working capital adjustments and an economic effective date of June 1, 2025. FERC approval for the sale was received in August 2025 and the transaction is expected to close in the second half of 2025.
2024 Divestitures
ERCOT Sale. In May 2024, we sold our 1,710 MW Texas generation portfolio to CPS Energy for $785 million, subject to customary net working capital adjustments. A gain on sale of $563 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the six months ended June 30, 2024.
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 six months ended June 30, 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 initial AWS PPA. In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of “front-of-the-meter” power through 2042. The transition to the revised AWS PPA is expected to occur in Spring 2026.
18. Segments
Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our Chief Executive Officer, who is the chief operating decision maker, 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.
“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 June 30, 2025 |  |  |  |  |  |  |  |
Operating revenues |  | $ | 638 |  |  | $ | (1) |  |  | $ | (7) |  |  | $ | 630 |
Operation, maintenance and development expenses (a) |  | 180 |  |  | 12 |  |  |  |  |
Interest expense and other finance charges |  | — |  |  | — |  |  | 62 |  |  | 62 |
Other segment items (b) |  | 343 |  |  |  |  |  |  |
Adjusted EBITDA |  | 115 |  |  |  |  |  |  |
Capital expenditures |  | 33 |  |  | 4 |  |  | — |  |  | 37 |
Three Months Ended June 30, 2024 |  |  |  |  |  |  |  |
Operating revenues |  | $ | 438 |  |  | $ | 58 |  |  | $ | (7) |  |  | $ | 489 |
Operation, maintenance and development expenses (a) |  | 141 |  |  | 23 |  |  |  |  |
Interest expense and other finance charges |  | — |  |  | — |  |  | 62 |  |  | 62 |
Other segment items (b) |  | 202 |  |  |  |  |  |  |
Adjusted EBITDA |  | 95 |  |  |  |  |  |  |
Capital expenditures |  | 14 |  |  | — |  |  | — |  |  | 14 |

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|  | PJM |  | Other |  | Corporate and Eliminations |  | Total
Six Months Ended June 30, 2025 |  |  |  |  |  |  |  |
Operating revenues |  | $ | 1,005 |  |  | $ | 41 |  |  | $ | (26) |  |  | $ | 1,020 |
Operation, maintenance and development expenses (a) |  | 318 |  |  | 20 |  |  |  |  |
Interest expense and other finance charges |  | — |  |  | — |  |  | 136 |  |  | 136 |
Other segment items (b) |  | 363 |  |  |  |  |  |  |
Adjusted EBITDA |  | 324 |  |  |  |  |  |  |
Capital expenditures |  | 95 |  |  | 5 |  |  | 1 |  |  | 101 |
Six Months Ended June 30, 2024 |  |  |  |  |  |  |  |
Operating revenues |  | $ | 871 |  |  | $ | 208 |  |  | $ | (81) |  |  | $ | 998 |
Operation, maintenance and development expenses (a) |  | 269 |  |  | 49 |  |  |  |  |
Interest expense and other finance charges |  | — |  |  | — |  |  | 121 |  |  | 121 |
Other segment items (b) |  | 227 |  |  |  |  |  |  |
Adjusted EBITDA |  | 375 |  |  |  |  |  |  |
Capital expenditures |  | 66 |  |  | 14 |  |  | — |  |  | 80 |

__________________
(a)This significant segment expense category aligns with the segment-level information that is regularly provided to the CODM.
(b)Other segment items are primarily comprised of fuel and energy purchases.
Reconciliation of segment Adjusted EBITDA to Net Income (Loss):

|  | Three Months Ended June 30, |  | Six Months Ended June 30, |  |  |
|  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Adjusted EBITDA: |  |  |  |  |  |  |  |  |  |  |  |  |
PJM |  | $ | 115 |  |  | $ | 95 |  |  | $ | 324 |  |  | $ | 375 |  |  |  |  |  |
Total Segment Adjusted EBITDA |  | $ | 115 |  |  | $ | 95 |  |  | $ | 324 |  |  | $ | 375 |  |  |  |  |  |
Reconciling Items: |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense and other finance charges |  | (62) |  |  | (62) |  |  | $ | (136) |  |  | $ | (121) |  |  |  |  |  |
Income tax benefit (expense) |  | (25) |  |  | (112) |  |  | 27 |  |  | (181) |  |  |  |  |  |
Depreciation, amortization and accretion |  | (70) |  |  | (75) |  |  | (144) |  |  | (150) |  |  |  |  |  |
Nuclear fuel amortization |  | (18) |  |  | (28) |  |  | (44) |  |  | (63) |  |  |  |  |  |
Unrealized (gain) loss on commodity derivative contracts |  | 92 |  |  | 91 |  |  | (90) |  |  | (44) |  |  |  |  |  |
Nuclear decommissioning trust funds gain (loss), net |  | 80 |  |  | 27 |  |  | 68 |  |  | 102 |  |  |  |  |  |
Stock-based and other long-term incentive compensation expense |  | (18) |  |  | (14) |  |  | (31) |  |  | (32) |  |  |  |  |  |
Gain (loss) on asset sales, net (a) |  | 9 |  |  | 561 |  |  | 11 |  |  | 885 |  |  |  |  |  |
Operational and other restructuring activities |  | — |  |  | (19) |  |  | (9) |  |  | (21) |  |  |  |  |  |
"Other" operating segment |  | (1) |  |  | 5 |  |  | 8 |  |  | 43 |  |  |  |  |  |
Noncontrolling interest |  | — |  |  | 7 |  |  | — |  |  | 18 |  |  |  |  |  |
Corporate and Eliminations |  | (24) |  |  | (13) |  |  | (42) |  |  | (42) |  |  |  |  |  |
Other items |  | (6) |  |  | (5) |  |  | (5) |  |  | 8 |  |  |  |  |  |
Net Income (Loss) |  | $ | 72 |  |  | $ | 458 |  |  | $ | (63) |  |  | $ | 777 |  |  |  |  |  |

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(a)See Note 17 for additional information.
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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
PJM 2026/2027 Base Residual Auction
In July 2025, PJM announced the results of the 2026/2027 PJM BRA. Talen cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.
See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets” for additional information.
Freedom and Guernsey Acquisitions
In July 2025, we entered into definitive agreements to acquire Caithness Energy’s 1,045 MW (summer rating) Freedom Energy Center in Pennsylvania and 1,836 MW (summer rating) Guernsey Power Station in Ohio, both gas fired combined cycle plants located within the PJM power market, for an aggregate gross purchase price of approximately $3.8 billion (subject to working capital and other customary adjustments), or $3.5 billion after adjusting for estimated tax benefits. We expect to issue approximately $3.8 billion in new debt to fund the Freedom and Guernsey Acquisitions.
The addition of these assets to Talen’s portfolio will increase our generating capacity by approximately 3 GW and is expected to enhance our ability to offer reliable, scalable, grid-supported, and regionally diverse low-carbon capacity to hyperscale data centers and other large commercial off-takers. Additionally, as these facilities have an average heat rate of 6,550 Btu/kWh, the Freedom and Guernsey Acquisitions will provide the Company with incremental baseload generation and cash flow diversification. The presence of these facilities in the PJM market complements our existing commercial and marketing capabilities, and their strategic location adjacent to the Marcellus and Utica shale formations provides ample natural gas supplies and reliable access to natural gas pipeline infrastructure and interconnects.
The transactions are subject to regulatory approvals and the satisfaction of other customary closing conditions, and are both expected to close in the fourth quarter 2025. The relevant regulatory filings have all been made and are now pending at the agencies.
See Note 17 to the Interim Financial Statements for additional information on the Freedom and Guernsey Acquisitions and “Part II, Item 1A. Risk Factors” of this Report for a discussion of the associated risks.
The foregoing description of the Purchase Agreements and the transactions contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Purchase Agreements, copies of which are attached as Exhibits 2.1 and 2.2 to this Report. The Purchase Agreements are being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Purchase Agreements, which may be subject to important limitations and qualifications, and which may change after the date of the Purchase Agreements, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.
Expanded AWS PPA
In June 2025, we entered into a new retail PPA agreement with AWS, expanding, and eventually replacing, the existing AWS PPA. The existing Susquehanna co-located load arrangement between Talen and AWS will transition to a “front-of-the-meter” arrangement after the completion of transmission reconfiguration projects expected to occur in Spring 2026, concurrent with Susquehanna’s annual refueling outage. Under the terms of the revised AWS PPA, Talen Energy Marketing will act as the retail electric generation supplier to AWS and PPL Electric Utilities will be responsible for transmission and delivery. At the full contract quantity, AWS is expected to receive 1,920 MW of power through 2042 for operations that support AI and other cloud technologies at the AWS Data Campus. The power delivery schedule will ramp over time, expecting to achieve the full volume no later than 2032. Talen and AWS will also explore building small modular reactors within Talen’s Pennsylvania footprint and pursue expanding Susquehanna’s energy output through uprates, with the intent to add net-new energy to the PJM grid.
Camden and Dartmouth Sales
In June 2025, we entered into a purchase and sale agreement to sell the Camden and Dartmouth generation facilities for an aggregate $32 million in cash, subject to customary working capital adjustments and an economic effective date of June 1, 2025. FERC approval for the sale was received in August 2025 and the transaction is expected to close in the second half of 2025.
See Note 17 to the Interim Financial Statements for additional information.
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RMR Arrangements
In May 2025, the FERC approved the terms under which Talen will operate Brandon Shores and H.A. Wagner until May 31, 2029, beyond their previously-scheduled May 31, 2025 retirement dates. 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, inclusive of some performance incentives.
See Note 7 to the Interim Financial Statements for additional information.
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 2024 Annual Report, as updated by our March 31, 2025 Quarterly Report, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the second quarter 2025, natural gas prices for Texas Eastern M-3 settled at the ten-year average as natural gas storage levels climbed above the five-year average. In PJM, above average temperatures during June 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 June 30, were:

|  | 2025 |  | 2024 |  |
PJM West Hub Day Ahead Peak - $/MWh |  | $ | 52.71 |  |  | $ | 37.67 |  |  |
PJM PPL Zone Day Ahead Peak - $/MWh |  | 40.91 |  |  | 28.34 |  |  |
Texas Eastern M-3 - $/MMBtu |  | 2.47 |  |  | 1.53 |  |  |

The weighted average forward market prices for the periods from July 1 through December 31 as of June 30, were:

|  | 2025 |  | 2024
PJM West Hub ATC - $/MWh |  | $ | 49.52 |  |  | $ | 43.64 |
Texas Eastern M-3 - $/MMBtu |  | 2.95 |  |  | 2.14 |
PJM West Hub ATC Spark Spreads - $/MWh (a) |  | 28.86 |  |  | 28.64 |

__________________
(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, Texas Eastern 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 2026/2027 PJM Capacity Year was held on July 22, 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 9 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.
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Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

|  | 2026/2027 |  | 2025/2026 |  | 2024/2025 |  | 2023/2024 |  |  |  |
PJM Capacity Performance ($/MWd) (a) |  |  |  |  |  |  |  |  |  |  |  |
MAAC |  | $ | 329.17 |  |  | $ | 269.92 |  |  | $ | 49.49 |  |  | $ | 49.49 |  |  |  |  |
PPL |  | 329.17 |  |  | 269.92 |  |  | 49.49 |  |  | 49.49 |  |  |  |  |

__________________
(a)Displayed prices are from the applicable market publications.
For the 2026/2027 PJM Capacity Year, the Company cleared 6,702 MWs at a price of $329.17/MWd 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 3 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.
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. As a prudent operator, we elected to complete this scope of work while Unit 2 was already in outage and market prices and demand were relatively low. The outage was completed on June 4, 2025. The incremental maintenance investment during the extended outage was comprised of approxima tely $25 million in operations and maintenance expenses and $6 million of capital expenditures. We expect similar incremental maintenance activities on Unit 1 to be performed during Susquehanna’s Spring 2026 planned outage. While the scope of work and outage schedule has not yet been finalized, we expect our planning activities with respect to the Unit 1 incremental work to result in an outage of shorter duration than the Unit 2 outage as well as for the Unit 1 incremental maintenance costs to be in line with or below the Unit 2 costs.
Results of Operations
The results of operations presented below for the three and six months ended June 30, 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.
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Results for the Three Months Ended June 30, 2025 and 2024
The following table and subsequent section display the results of operations:

|  | Three Months Ended June 30, |  | Favorable (Unfavorable) Variance |  |  |  |  |  |
|  | 2025 |  | 2024 |  |  |  |  |  |  |  |  |
Capacity revenues |  | $ | 88 |  |  | $ | 46 |  |  | $ | 42 |  |  |  |  |  |  |  |  |
Energy and other revenues |  | 366 |  |  | 367 |  |  | (1) |  |  |  |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  | 176 |  |  | 76 |  |  | 100 |  |  |  |  |  |  |  |  |
Operating Revenues (Note 3) |  | 630 |  |  | 489 |  |  | 141 |  |  |  |  |  |  |  |  |
Fuel and energy purchases |  | (150) |  |  | (163) |  |  | 13 |  |  |  |  |  |  |  |  |
Nuclear fuel amortization |  | (18) |  |  | (28) |  |  | 10 |  |  |  |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  | (84) |  |  | 15 |  |  | (99) |  |  |  |  |  |  |  |  |
Energy Expenses |  | (252) |  |  | (176) |  |  | (76) |  |  |  |  |  |  |  |  |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operation, maintenance and development |  | (192) |  |  | (164) |  |  | (28) |  |  |  |  |  |  |  |  |
General and administrative |  | (41) |  |  | (40) |  |  | (1) |  |  |  |  |  |  |  |  |
Depreciation, amortization and accretion (Note 7) |  | (70) |  |  | (75) |  |  | 5 |  |  |  |  |  |  |  |  |
Other operating income (expense), net |  | (9) |  |  | (7) |  |  | (2) |  |  |  |  |  |  |  |  |
Operating Income (Loss) |  | 66 |  |  | 27 |  |  | 39 |  |  |  |  |  |  |  |  |
Nuclear decommissioning trust funds gain (loss), net (Note 6) |  | 80 |  |  | 27 |  |  | 53 |  |  |  |  |  |  |  |  |
Interest expense and other finance charges (Note 10) |  | (62) |  |  | (62) |  |  | — |  |  |  |  |  |  |  |  |
Gain (loss) on sale of assets, net (Note 17) |  | 9 |  |  | 561 |  |  | (552) |  |  |  |  |  |  |  |  |
Other non-operating income (expense), net |  | 4 |  |  | 17 |  |  | (13) |  |  |  |  |  |  |  |  |
Income (Loss) Before Income Taxes |  | 97 |  |  | 570 |  |  | (473) |  |  |  |  |  |  |  |  |
Income tax benefit (expense) (Note 4) |  | (25) |  |  | (112) |  |  | 87 |  |  |  |  |  |  |  |  |
Net Income (Loss) |  | 72 |  |  | 458 |  |  | (386) |  |  |  |  |  |  |  |  |
Less: Net income (loss) attributable to noncontrolling interest |  | — |  |  | 4 |  |  | 4 |  |  |  |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders |  | $ | 72 |  |  | $ | 454 |  |  | $ | (382) |  |  |  |  |  |  |  |  |

Three Months Ended June 30, 2025 compared to Three Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(382) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $65 million favorable increase, primarily due to the following:
◦Capacity Revenues. $42 million favorable increase. This is primarily related to a $60 million increase due to higher cleared capacity prices though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by an $(18) million decrease due to lower volumes cleared though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $12 million favorable increase. This is primarily related to the combined effects of: (i) $70 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet, partially offset by lower generation volumes at Susquehanna and lower ancillary revenues; and (ii) $10 million increase in realized hedge results. Such amounts are partially offset by a $(68) million decrease in digital revenue and Nuclear PTC revenue.
•Operation, Maintenance and Development. $(28) million unfavorable increase. This is primarily due to incremental maintenance at Susquehanna performed during its planned refueling outage on Unit 2 in Spring 2025.
•Nuclear Decommissioning Trust Funds Gain (Loss), net. $53 million favorable increase. This is primarily due to the combined effect of: (i) $61 million increase in the unrealized value of equity securities in the second quarter 2025 compared with a $17 million increase in the second quarter 2024; and (ii) $8 million increase in realized activity in the second quarter 2025. See Notes 6 and 11 to the Interim Financial Statements for additional information.
•Gain (Loss) on Sale of Assets, net. $(552) million unfavorable decrease. This is primarily related to the ERCOT Sale that closed in the second quarter 2024. See Note 17 to the Interim Financial Statements for additional information.
•Income Tax Benefit (Expense). $87 million favorable decrease. This is primarily due to a decrease in pre-tax income in the second quarter 2025 as compared to the second quarter 2024.
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Results for the Six Months Ended June 30, 2025 and 2024
The following table and subsequent sections display the results of operations:

|  |  |  | Six Months Ended June 30, |  | Favorable (Unfavorable) Variance |  |  |
|  |  |  |  |  | 2025 |  | 2024 |  |  |  |  |  |
Capacity revenues |  |  |  |  |  | $ | 137 |  |  | $ | 91 |  |  | $ | 46 |  |  |  |  |  |
Energy and other revenues |  |  |  |  |  | 948 |  |  | 939 |  |  | 9 |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  |  |  |  |  | (65) |  |  | (32) |  |  | (33) |  |  |  |  |  |
Operating Revenues (Note 3) |  |  |  |  |  | 1,020 |  |  | 998 |  |  | 22 |  |  |  |  |  |
Fuel and energy purchases |  |  |  |  |  | (418) |  |  | (313) |  |  | (105) |  |  |  |  |  |
Nuclear fuel amortization |  |  |  |  |  | (44) |  |  | (63) |  |  | 19 |  |  |  |  |  |
Unrealized gain (loss) on derivative instruments (Note 2) |  |  |  |  |  | (25) |  |  | (12) |  |  | (13) |  |  |  |  |  |
Energy Expenses |  |  |  |  |  | (487) |  |  | (388) |  |  | (99) |  |  |  |  |  |
Operating Expenses |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Operation, maintenance and development |  |  |  |  |  | (338) |  |  | (318) |  |  | (20) |  |  |  |  |  |
General and administrative |  |  |  |  |  | (75) |  |  | (83) |  |  | 8 |  |  |  |  |  |
Depreciation, amortization and accretion (Note 7) |  |  |  |  |  | (144) |  |  | (150) |  |  | 6 |  |  |  |  |  |
Other operating income (expense), net |  |  |  |  |  | (16) |  |  | (7) |  |  | (9) |  |  |  |  |  |
Operating Income (Loss) |  |  |  |  |  | (40) |  |  | 52 |  |  | (92) |  |  |  |  |  |
Nuclear decommissioning trust funds gain (loss), net (Note 6) |  |  |  |  |  | 68 |  |  | 102 |  |  | (34) |  |  |  |  |  |
Interest expense and other finance charges (Note 10) |  |  |  |  |  | (136) |  |  | (121) |  |  | (15) |  |  |  |  |  |
Gain (loss) on sale of assets, net (Note 17) |  |  |  |  |  | 11 |  |  | 885 |  |  | (874) |  |  |  |  |  |
Other non-operating income (expense), net |  |  |  |  |  | 7 |  |  | 40 |  |  | (33) |  |  |  |  |  |
Income (Loss) Before Income Taxes |  |  |  |  |  | (90) |  |  | 958 |  |  | (1,048) |  |  |  |  |  |
Income tax benefit (expense) (Note 4) |  |  |  |  |  | 27 |  |  | (181) |  |  | 208 |  |  |  |  |  |
Net Income (Loss) |  |  |  |  |  | (63) |  |  | 777 |  |  | (840) |  |  |  |  |  |
Less: Net income (loss) attributable to noncontrolling interest |  |  |  |  |  | — |  |  | 29 |  |  | 29 |  |  |  |  |  |
Net Income (Loss) Attributable to Stockholders |  |  |  |  |  | $ | (63) |  |  | $ | 748 |  |  | $ | (811) |  |  |  |  |  |

Six Months Ended June 30, 2025 compared to Six Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(811) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $(77) million unfavorable decrease, primarily due to the following:
◦Capacity Revenues. $46 million favorable increase. This is primarily related to a $63 million increase due to higher cleared capacity prices through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by $(17) million decrease due to lower volumes cleared through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $(96) million unfavorable decrease. This is primarily related to the combined effects of: (i) $(152) million decrease in realized hedge results; and (ii) $(143) million decrease in digital revenue and Nuclear PTC revenue. Such amounts are partially offset by a $199 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet and higher generation volumes at our PJM fossil fleet, partially offset by lower generation volumes at Susquehanna.
◦Unrealized Gain (Loss) on Derivative Instruments, net. $(46) million unfavorable decrease. This is primarily related to the combined effect of $(85) million associated with lower volume of hedge positions executed during current period as compared to hedge positions executed in the prior period, partially offset by $40 million of unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
•Operation, Maintenance and Development. $(20) million unfavorable increase. This is primarily due to incremental maintenance at Susquehanna performed during its planned refueling outage on Unit 2 in Spring 2025.
•Nuclear Decommissioning Trust Funds Gain (Loss), net. $(34) million unfavorable decrease. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 6 and 11 to the Interim Financial Statements for additional information.
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•Gain (Loss) on Sale of Assets, net. $(874) million unfavorable decrease. This primarily consists of a: (i) $563 million gain from the ERCOT Sale that closed in the second quarter 2024; and (ii) $324 million gain from the AWS Data Campus Sale in the first quarter 2024. See Note 17 to the Interim Financial Statements for additional information.
•Other Non-Operating Income (Expense), net. $(33) million unfavorable decrease. This primarily consisted of interest income on cash deposits.
•Income Tax Benefit (Expense). $208 million favorable decrease. This is primarily due to a decrease in pre-tax income for the six months ended June 30, 2025 as compared to 2024.
•Net Income Attributable to Noncontrolling Interest. $29 million favorable decrease. This is related to the buyout of the remaining noncontrolling interest in Cumulus Digital in the fourth quarter 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, the stability provided by contracted cash flows associated with long-term PPAs as well as the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) lower our overall hedging requirements.
We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.
See the following Notes to the Interim Financial Statements for additional information on liquidity topics discussed below: Note 2 for derivatives and hedging, Note 8 for AROs and environmental obligations, Note 10 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.
Liquidity and Letter of Credit Capacity

|  | June 30, 2025 |  | December 31, 2024
Cash and cash equivalents, unrestricted |  | $ | 122 |  |  | $ | 328 |
Unutilized RCF capacity (a) |  | 630 |  |  | 700 |
Total available liquidity |  | $ | 752 |  |  | $ | 1,028 |
Additional unutilized LC capacity (b) |  | $ | 487 |  |  | $ | 526 |

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(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.
As of August 4, 2025, the unutilized RCF capacity was $700 million.
Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 10 to the Interim Financial Statements for additional information on the RCF and LCF.
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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.

|  | June 30, 2025 |  | December 31, 2024
Outstanding surety bonds |  | $ | 263 |  |  | $ | 234 |

In May 2025, the Company elected to replace a surety provider and, as of June 30, 2025, the replacement surety bonds issued by the new provider were outstanding. However, an aggregate $42 million of replaced surety bonds (included in the total above) continued to be outstanding as their release was not yet completed as of June 30, 2025.
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:

|  | Six Months Ended June 30, |  |  |  |  |  |  | Favorable (Unfavorable) Variance
|  | 2025 |  | 2024 |  |  |  |  |  |
Operating activities |  | $ | (65) |  |  | $ | 150 |  |  |  |  |  |  |  | $ | (215) |
Investing activities |  | (114) |  |  | 979 |  |  |  |  |  |  |  | (1,093) |
Financing activities |  | (51) |  |  | (915) |  |  |  |  |  |  |  | 864 |

Operating activities
A change of $(215) 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 $(1,093) million in net cash provided by (used in) investing activities was primarily due to: (i) $(339) million in proceeds from the AWS Data Campus Sale in the first quarter 2024; and (ii) $(754) million of proceeds from the ERCOT Sale in the second quarter 2024. See Note 17 to the Interim Financial Statements for additional information on the AWS Data Campus Sale and the ERCOT Sale.
Financing activities
A change of $864 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; (ii) $39 million purchase of noncontrolling interest in Cumulus Digital, both in the first quarter 2024; (iii) a $551 million decrease in share repurchases; and (iv) RCF borrowings of $70 million in the second 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 9 to the Interim Financial Statements for additional information regarding guarantees.
Non-GAAP Financial Measure
Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
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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 June 30, |  | Six Months Ended June 30, |  |  |
(Millions of Dollars) |  | 2025 |  | 2024 |  | 2025 |  | 2024 |  |  |  |  |
Net Income (Loss) |  | $ | 72 |  |  | $ | 458 |  |  | $ | (63) |  |  | $ | 777 |  |  |  |  |  |
Adjustments |  |  |  |  |  |  |  |  |  |  |  |  |
Interest expense and other finance charges |  | 62 |  |  | 62 |  |  | 136 |  |  | 121 |  |  |  |  |  |
Income tax (benefit) expense |  | 25 |  |  | 112 |  |  | (27) |  |  | 181 |  |  |  |  |  |
Depreciation, amortization and accretion |  | 70 |  |  | 75 |  |  | 144 |  |  | 150 |  |  |  |  |  |
Nuclear fuel amortization |  | 18 |  |  | 28 |  |  | 44 |  |  | 63 |  |  |  |  |  |
Unrealized (gain) loss on commodity derivative contracts |  | (92) |  |  | (91) |  |  | 90 |  |  | 44 |  |  |  |  |  |
Nuclear decommissioning trust funds (gain) loss, net |  | (80) |  |  | (27) |  |  | (68) |  |  | (102) |  |  |  |  |  |
Stock-based and other long-term incentive compensation expense |  | 18 |  |  | 14 |  |  | 31 |  |  | 32 |  |  |  |  |  |
(Gain) loss on asset sales, net (a) |  | (9) |  |  | (561) |  |  | (11) |  |  | (885) |  |  |  |  |  |
Operational and other restructuring activities |  | — |  |  | 19 |  |  | 9 |  |  | 21 |  |  |  |  |  |
Noncontrolling interest |  | — |  |  | (7) |  |  | — |  |  | (18) |  |  |  |  |  |
Other |  | 6 |  |  | 5 |  |  | 5 |  |  | (8) |  |  |  |  |  |
Total Adjusted EBITDA |  | $ | 90 |  |  | $ | 87 |  |  | $ | 290 |  |  | $ | 376 |  |  |  |  |  |

__________________
(a)See Note 17 to the Interim Financial Statements for additional information.
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 2 to the Interim Financial Statements for a description of our market risk.
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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 June 30, 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 June 30, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
There have been no additional material developments with respect to the information previously reported under “Part I, Item 3. Legal Proceedings” of our 2024 Annual Report, as updated by “Part II, Item 1. Legal Proceedings” of our March 31, 2025 Quarterly Report.
See Note 9 to the Interim Financial Statements for information about other material legal proceedings to which we are subject.
ITEM 1A. RISK FACTORS
Risks Related to the Freedom and Guernsey Acquisitions
The proposed Freedom and Guernsey Acquisitions are subject to a number of conditions which, if not satisfied or waived, could delay or impair our ability to complete the transactions on the agreed terms or at all. Failure to consummate the Freedom and (or) Guernsey Acquisitions as contemplated or at all could adversely affect us and the price of our common stock.
Completion of each of the Freedom and Guernsey Acquisitions is subject to the satisfaction or waiver of a number of conditions, including: (i) receipt of all requisite regulatory approvals, including from the FERC; (ii) expiration or termination of the applicable waiting period under the HSR Act; and (iii) other customary closing conditions, including but not limited to the absence of certain “material adverse events.” We cannot guarantee if or when these conditions will be satisfied or that the proposed acquisitions will be completed on the current terms or at all. There can also be no assurance as to the cost, scope, or impact of the actions, restrictions, or other conditions that may be required to obtain regulatory consents and approvals, and the Purchase Agreements generally do not permit us to terminate the transactions due to the terms of required regulatory consents or approvals.
It is a condition to closing the acquisitions that no governmental law, ruling, or order is in effect that prohibits their consummation. Although we are not currently aware of any, legal actions relating to the proposed acquisitions could be filed under antitrust, securities, or other laws. There can be no assurance of the outcome of any such actions and, regardless, defending against them could result in delays, additional costs, or diversion of time and resources.
Each of the Purchase Agreements provide that either we or the sellers can terminate the applicable agreement if the respective acquisition is not completed by July 17, 2026 (which may be automatically extended to January 17, 2027 in the case of pending antitrust and (or) regulatory approvals). If the Freedom and (or) Guernsey Acquisitions are not consummated, or are consummated on different terms or timing than currently contemplated, we could be subject to a variety of risks, including:
•we will still incur and remain liable for significant transaction costs, including legal, accounting, financing, advisory, and other costs;
•under certain circumstances, we may be required to pay the sellers a termination fee of approximately $63 million in the case of Freedom and $100 million in the case of Guernsey;
•our stockholders may be prevented from realizing the anticipated benefits of the acquisition and (or) the market price of our common stock could decline significantly;
•we could experience reputational harm due to the adverse public perception of any failure to successfully complete the acquisition; and
•management and employee attention may be diverted from day-to-day matters or our business may be otherwise disrupted by efforts to consummate the proposed transaction.
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If completed, the Freedom and Guernsey Acquisitions may not achieve their intended results.
Although we currently anticipate that the Freedom and Guernsey Acquisitions will be accretive to our earnings and cash flow, that expectation is based on preliminary estimates that are subject to change. We may fail to realize the anticipated benefits of the acquisitions, encounter additional transaction and integration-related costs, or be affected by other factors that impact preliminary estimates, any of which could decrease or delay the expected accretion and (or) contribute to a decrease in the price of our common stock.
We entered into the Purchase Agreements with the expectation that the Freedom and Guernsey Acquisitions would result in various benefits to the Company, including enhanced generation capabilities. Achievement of the anticipated benefits is subject to a number of uncertainties, including our ability to effectively integrate the acquired assets, which may be complex, costly, and time-consuming. Additional challenges could include, among others:
•implementing our business plan for, and achieving the targeted operating or long-term strategic benefits from, the acquired assets;
•issues or costs in integrating (i) financial, information technology, communications, and other systems; (ii) relationships with industry contacts and business partners, including third-party service providers who provide key services for the acquired assets; and (iii) key hedging and other commercial activities, arrangements, and relationships;
•possible inconsistencies between our standards, controls, policies, and procedures and those of the acquired assets, as well as the resources required to implement or improve the internal controls, procedures, and policies of the acquired assets to meet public company standards;
•potential unknown liabilities and unforeseen expenses, delays, or regulatory conditions associated with the acquisitions, as well as any unexpected write offs or impairment charges resulting from the acquisitions; and
•performance of the acquired assets and the costs to operate and maintain them, relative to expectations, including any unanticipated capital expenditures or investments.
Furthermore, the Company will not control Freedom or Guernsey until completion of the proposed acquisitions, and the acquired assets or their value could be negatively impacted by conditions occurring while the acquisitions are pending. Adverse changes could result from, among other things, physical asset damage, legal or regulatory developments, deteriorating general business, market, industry, or economic conditions, and other factors both within and beyond the control of the Company and the sellers. In addition, there could be potential unknown liabilities or unforeseen expenses not discovered during due diligence and not adequately covered by representation and warranty insurance (should we choose to procure it) or otherwise adjusted for in the Purchase Agreements. Any such conditions could cause the value of the acquired assets to decline and (or) reduce the benefits of the acquisitions to the Company and its stockholders.
Any of the foregoing risks could result in failure to achieve the anticipated benefits of the acquisitions, and the expectations of our future financial condition and results of operations following the acquisitions might not be met. See also “Part I, Item 1A. Risk Factors—Commercial and Operational Risks—Acquisitions, divestitures, mergers, or other corporate transactions may expose us to additional risks” in our 2024 Annual Report.
We expect to incur a significant amount of indebtedness to finance the Freedom and Guernsey Acquisitions. However, we are obligated to complete the transactions whether or not we have obtained the necessary funding.
We intend to raise approximately $3.8 billion of additional indebtedness to fund the Freedom and Guernsey Acquisitions. The amount of our indebtedness following the acquisitions could have adverse consequences for us, including, among others:
•hindering our ability to adjust to changing market, industry, or economic conditions;
•making us more vulnerable to economic or industry downturns, including interest rate increases;
•limiting the amount of free cash flow available for future operations, acquisitions, dividends, stock repurchases, or other uses;
•reducing flexibility under the terms of our indebtedness to, among other things, make restricted payments, obtain other financing, operate our business, and (or) take advantage of mergers, acquisitions, or other corporate opportunities; and
•placing us at a competitive disadvantage compared to less leveraged competitors.
Increased indebtedness could also impact our credit ratings, borrowing costs, access to capital markets, and ability to comply with our indebtedness. See also “Part I, Item 1A. Risk Factors—Financial and Equity Risks—The amount and terms of our indebtedness could adversely affect our financial condition and impair our ability to operate our business” in our 2024 Annual Report.
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The Purchase Agreements do not contain a financing condition, and we would be required to complete the proposed acquisitions even if we do not have the required funds on hand. TEC has issued parent guaranties in favor of the sellers to guarantee performance of our obligations under the Purchase Agreements. While we have obtained 12-month commitments for 364-day bridge facilities, they are subject to a number of conditions and we cannot guarantee that we will be able to close the financings as anticipated or that the acquisitions will close prior to expiration of the bridge commitments. In addition, the tenor, economics, and other terms of the bridge facilities, provide significant incentive for us to not draw on the bridge facilities or, if drawn, to promptly refinance those facilities. Whether to initially fund the purchase price or to later refinance the bridge facilities, we will be required to raise long-term financing for the acquisitions, which could subject us to less favorable timing, costs, and market conditions than we would otherwise choose. If we cannot close on any element of our financing plan, we will need to pursue other financing options and certain existing indebtedness at Freedom and (or) Guernsey or their affiliates may remain in place, which could result in less favorable financing terms that could negatively impact our costs, credit ratings, or financing and operating flexibility, or realization of the anticipated benefits from the acquisitions. See also “Part I, Item 1A. Risk Factors—Financial and Equity Risks—We may not have sufficient access to financing for our business” in our 2024 Annual Report.
Additional Risk Factors
For additional information related to the Company’s risk factors, see “Item 1A. Risk Factors” in our 2024 Annual Report, as updated by our March 31, 2025 Quarterly Report.
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES 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 2024 Annual Report for additional information related to the SRP and shares repurchased under the SRP.
There were no share repurchases during the three months ended June 30, 2025.
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 June 30, 2025, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading agreement” or “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408 of Regulation S-K).
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ITEM 6. EXHIBITS

|  |  |  | Incorporated by Reference
Exhibit No. |  | Description |  | Form |  | File Number |  | Date of Filing |  | Exhibit Number
2.1*#^ |  | Purchase and Sale Agreement, dated as of July 17, 2025, by and between Caithness Energy, L.L.C., as seller, and Talen Generation, LLC, as buyer. |  | — |  | — |  | — |  | —
2.2*#^ |  | Purchase and Sale Agreement, dated as of July 17, 2025, by and among Caithness Energy, L.L.C., as seller, Caithness Apex Guernsey, LLC, as subsidiary seller, and Talen Generation, LLC, as buyer. |  | — |  | — |  | — |  | —
3.1 |  | Third Amended and Restated Certificate of Incorporation of Talen Energy Corporatio n. |  | S-1 |  | 333-280341 |  | June 20, 2024 |  | 3.1
3.2 |  | Second Amended and Restated Bylaws of Talen Energy Corporation. |  | S-1 |  | 333-280341 |  | June 20, 2024 |  | 3.2
10.1† |  | Amended and Restated 2025 Employee Stock Purchase Plan. |  | 10-Q |  | 001-37388 |  | May 8, 2025 |  | 10.1
31.1* |  | Certification of Chief Executive Officer (Principal Executive Officer) p ursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | — |  | — |  | — |  | —
31.2* |  | Certification of Chief Financial Officer (Principal Financial Officer) p ursuant to Section 302 of the Sarbanes-Oxley Act of 2002. |  | — |  | — |  | — |  | —
32.1** |  | Certification of Chief Executive Officer (Principal Executive Officer) and Chief Financial Officer (Principal Financial Officer) p ursuant to Section 906 of the Sarbanes-Oxley Act of 2002. |  | — |  | — |  | — |  | —
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.
# Certain of the schedules and attachments to the exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or attachment will be furnished to the SEC upon request.
^ Certain private and immaterial portions of the exhibit have been redacted pursuant to Item 601(a)(6) of Regulation S-K.
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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 data center campus initially developed by a subsidiary of Cumulus Digital adjacent to Susquehanna. See Note 17 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 17 to the Interim Financial Statements for additional information.
AWS PPA. The March 2024 (as revised in June 2025) power purchase agreement between the Company and AWS pursuant to which, among other things, the Company agreed to supply up to 960 MW of long-term power to the AWS Data Campus from Susquehanna. In June 2025, the Company and AWS entered into a revised AWS PPA, under which the Company is expected to provide AWS with up to 1,920 MW of power in a “front-of-the-meter” model through 2042. The transition to the revised AWS PPA is expected to occur in Spring 2026.
Bilateral LCF. The $75 million senior secured bilateral LC facility provided by Barclays Bank PLC. The Bilateral LCF was terminated in December 2024.
Board of Directors. The board of directors of Talen Energy Corporation.
Brandon Shores. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Brunner Island. A Talen-owned and operated generation facility in York Haven, Pennsylvania.
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.
DOE. U.S. Department of Energy.
EPA. U.S. Environmental Protection Agency.
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EPA CCR Rule. The national regulatory standards required by the EPA for the management of CCRs in landfills and surface impoundments.
EPA CSAPR. The Cross-State Air Pollution Rule, a federal program that aims to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. A cap-and-trade system for both annual and ozone season periods is used to reduce the target pollutants—sulfur dioxide and nitrogen oxides. CSAPR regulations have been changed over time, and different versions of the regulations have been referred to as the “CSAPR Update,” the “Revised CSAPR Update,” and the “Good Neighbor Plan.”
EPA ELG Rule. The effluent limitation guidelines, which are national regulatory standards required by the EPA for wastewater discharged from specific industrial categories, including but not limited to coal-fired electric generation facilities, to surface waters and municipal sewage treatment plants.
EPA GHG Rule. An EPA rule that establishes carbon dioxide limits for new electric generating units and GHG guidelines for certain existing electric generating units.
EPA MATS Rule. The Mercury and Air Toxics Standards, EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 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.
Freedom and Guernsey Acquisitions. Our pending acquisitions of the Freedom Energy Center in Pennsylvania and the Guernsey Power Station in Ohio from affiliates of Caithness Energy. See Note 17 to the Interim Financial Statements for additional information.
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 June 30, 2025 and December 31, 2024; the related consolidated statements of operations, statements of comprehensive income, and statements of equity for the three and six months ended June 30, 2025 and 2024; the consolidated statement of cash flows for the six months ended June 30, 2025 and 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.
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MWd. Megawatt-day.
MWh. Megawatt-hour.
Nautilus. Nautilus Cryptomine LLC, a cryptocurrency project that was previously a joint venture between the Company and TeraWulf. The Company purchased TeraWulf’s interest in October 2024 and now owns 100% of Nautilus.
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.
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.
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Talen Energy Corporation (or “TEC”). Talen Energy Corporation, the parent company of Talen Energy Supply and its consolidated subsidiaries.
Talen Energy Marketing. Talen Energy Marketing, LLC, a direct subsidiary of Talen Energy Supply that provides energy management services to Talen-owned and operated generation facilities and engages in wholesale commodity marketing activities.
Talen Energy Supply (or “TES”). Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation that, thorough subsidiaries, indirectly holds all of Talen’s assets and operations.
Talen Montana. Talen Montana, LLC, a Talen subsidiary that operates Colstrip, owns an undivided interest in Colstrip Unit 3, and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
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: | August 7, 2025 | By: | /s/ Terry L. Nutt |
|  | Name: | Terry L. Nutt |
|  | Title: | Chief Financial Officer |

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