tln-20260630

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, 2026


☐			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 5, 2026, the registrant had outstanding 47,914,259 shares 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	22
		11. Fair Value	23
		12. Postretirement Benefit Obligations	25
		13. Stock-Based Compensation	25
		14. Earnings Per Share	27
		15. Stockholders' Equity	27
		16. Supplemental Cash Flow Information	29
		17. Acquisitions and Divestitures	29
		18. Seg ments	31
	I TEM 2. MANAGEMENT ’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITIO N A ND RESULTS OF OPERATION S
		R ece nt Deve lopments	33
		Factors Affecting Our Financial Condition and Results of Operations	33
		Results of Operations	35
		Liquidity and Capital Resources	38
		Cash Flow Activities	39
		Contractual Obligations and Commitments	39
		Non-GAAP Financial Measure	40
		Critical Accounting Estimates	41
	ITEM 3. QUA NTITATIVE AND QUALITATIVE DISCLO SURES ABOUT MARKET RISK		41
	ITEM 4. CONTROLS AND PROCEDURES		41
P ART II. OTHER INFORMATION
	IT EM 1. L EGAL PROCEEDINGS		42
	I TEM 1A. R ISK FACTORS		42
	ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		42
	ITEM 3. D EF AULTS UPON SENIOR SECURITI ES		42
	I TEM 4. MINE S AF ET Y DISCLOSURES		42
	I TEM 5. O THER IN FORMATION		42
	I TEM 6. EXHIBITS		43
G LOSSAR Y OF TERMS AND ABBREVIA TIONS			44
SIGN ATURES			48

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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, including but not limited to “Item 1A. Risk Factors” in this Report and our most recent Annual Report on Form 10-K for the year ended December 31, 2025 (“2025 Annual Report”), as updated by our Quarterly Report on Form 10-Q for the three months ended March 31, 2026 (“Q1 2026 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” and “Item 1A. Risk Factors” of this Report and our 2025 Annual Report, as updated by our Q1 2026 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.

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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)	2026		2025		2026		2025

Energy and other revenues	$	722	$	366	$	1,756	$	948
Capacity revenues	237		88		444		137
Unrealized gain (loss) on derivative instruments (Note 2)	(212)		176		(324)		(65)
Operating Revenues (Note 3)	747		630		1,876		1,020

Fuel and energy purchases	(357)		(150)		(920)		(418)
Nuclear fuel amortization	(22)		(18)		(46)		(44)
Unrealized gain (loss) on derivative instruments (Note 2)	1		(84)		(41)		(25)
Energy Expenses	(378)		(252)		(1,007)		(487)

Operating Expenses
Operation, maintenance and development	(210)		(192)		(375)		(338)
General and administrative (Includes stock-based compensation of $(70), $(16), $(69) and $(27)) (Note 13)	(98)		(41)		(122)		(75)
Depreciation, amortization and accretion (Note 7)	(103)		(70)		(195)		(144)


Other operating income (expense), net	(30)		(9)		(39)		(16)
Operating Income (Loss)	(72)		66		138		(40)
Nuclear decommissioning trust funds gain (loss), net (Note 6)	134		80		112		68
Interest expense and other finance charges (Note 10)	(214)		(62)		(333)		(136)



Other non-operating income (expense), net	23		13		35		18
Income (Loss) Before Income Taxes	(129)		97		(48)		(90)
Income tax benefit (expense) (Note 4)	37		(25)		19		27


Net Income (Loss) Attributable to Stockholders	$	(92)	$	72	$	(29)	$	(63)
Per Common Share
Net Income (Loss) Attributable to Stockholders - Basic	$	(2.00)	$	1.58	$	(0.63)	$	(1.38)
Net Income (Loss) Attributable to Stockholders - Diluted	$	(2.00)	$	1.50	$	(0.63)	$	(1.38)
Weighted-Average Number of Common Shares Outstanding - Basic (in thousands)	45,904		45,554		45,759		45,699
Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands)	45,904		47,905		45,759		45,699

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 COMPREHENSIVE INCOME (LOSS) (UNAUDITED)


	Three Months Ended June 30,				Six Months Ended June 30,
(Millions of Dollars)	2026		2025		2026		2025

Net Income (Loss)	$	(92)	$	72	$	(29)	$	(63)
Other Comprehensive Income (Loss)
Available-for-sale securities unrealized gain (loss), net (Note 6)	—		2		(9)		8


Income tax benefit (expense)	—		(1)		3		(3)
Gains (losses) arising during the period, net of tax	—		1		(6)		5
Available-for-sale securities unrealized (gain) loss, net (Note 6)	—		(1)		(1)		(2)

Postretirement benefit prior service (credits) costs, net (Note 12)	(1)		(1)		(2)		(2)

Income tax (benefit) expense	—		2		1		2
Reclassifications from AOCI, net of tax	(1)		—		(2)		(2)
Total Other Comprehensive Income (Loss)	(1)		1		(8)		3


Comprehensive Income (Loss) Attributable to Stockholders	$	(93)	$	73	$	(37)	$	(60)

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 BALANCE SHEETS (UNAUDITED)


(Millions of Dollars, except share data)	June 30, 2026		December 31, 2025
Assets
Cash and cash equivalents	$	231	$	689
Restricted cash and cash equivalents (Note 16)	7		63
Accounts receivable (Note 3)	294		196
Inventory, net (Note 5)	298		278
Derivative instruments (Notes 2 and 11)	131		56

Other current assets	67		67
Total current assets	1,028		1,349
Property, plant and equipment, net (Note 7)	11,928		7,546
Nuclear decommissioning trust funds (Notes 6 and 11)	1,997		1,900
Derivative instruments (Notes 2 and 11)	9		4
Other noncurrent assets	106		106
Total Assets	$	15,068	$	10,905

Liabilities and Equity


Long-term debt, due within one year (Notes 10 and 11)	$	29	$	29


Accrued interest	167		60
Accounts payable and other accrued liabilities	347		281
Derivative instruments (Notes 2 and 11)	573		101

Stock-based compensation liabilities (Note 13)	6		501
Other current liabilities	194		78
Total current liabilities	1,316		1,050
Long-term debt (Notes 10 and 11)	9,543		6,782

Derivative instruments (Notes 2 and 11)	150		67
Postretirement benefit obligations (Note 12)	214		229
Asset retirement obligations and accrued environmental costs (Note 8)	497		494
Deferred income taxes	904		486
Acquired contract liabilities (Note 17)	769		662
Other noncurrent liabilities	36		42
Total Liabilities	$	13,429	$	9,812
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	2,533		1,709
Accumulated retained earnings (deficit)	(905)		(612)
Accumulated other comprehensive income (loss)	(12)		(4)
Total Stockholders' Equity	1,616		1,093
Noncontrolling interests	23		—
Total Equity	1,639		1,093
Total Liabilities and Stockholders' Equity	$	15,068	$	10,905

__________________

(a)47,900,355 and 45,687,828 shares issued and outstanding as of June 30, 2026 and December 31, 2025, 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)	2026		2025
Operating Activities
Net Income (Loss)	$	(29)	$	(63)
Non-cash reconciliation adjustments:
Unrealized (gains) losses on derivative instruments (Note 2)	352		103
Depreciation, amortization and accretion (Note 16)	158		141
Nuclear decommissioning trust funds (gain) loss, net (excluding interest and fees) (Note 6)	(85)		(44)
Nuclear fuel amortization (Note 7)	46		44
Deferred income taxes	(34)		(66)
Stock-based compensation (Note 13)	69		27






Other (Note 16)	35		7
Changes in assets and liabilities:
Accounts receivable	(59)		(103)
Inventory, net	10		78
Other assets	14		15
Accounts payable and accrued liabilities	20		(57)
Accrued interest	107		12
Collateral received (posted), net	(35)		(58)
Cash settlement of stock-based awards (Note 13)	(495)		—
Other liabilities	(47)		(101)
Net cash provided by (used in) operating activities	27		(65)

Investing Activities

Property, plant and equipment expenditures (Note 7)	(181)		(51)
Nuclear fuel expenditures (Note 7)	(66)		(50)
Nuclear decommissioning trust funds investment purchases (Note 6)	(195)		(1,201)
Nuclear decommissioning trust funds investment sale proceeds (Note 6)	173		1,186
Cornerstone Acquisition, net (Note 17)	(2,568)		—




Other	13		2
Net cash provided by (used in) investing activities	(2,824)		(114)

Financing Activities
Debt issuances (Note 10)	4,000		—
Debt repayments (Note 10)	(1,215)		(9)
Deferred financing costs	(58)		(9)
Revolving credit facility borrowings (Note 10)	500		75
Revolving credit facility repayments (Note 10)	(500)		(5)
Share repurchases (Note 15)	(298)		(103)
Tax payments related to net-settled stock-based awards (Note 13)	(140)		—





Other	(6)		—
Net cash provided by (used in) financing activities	2,283		(51)
Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents	(514)		(230)
Beginning of period cash and cash equivalents and restricted cash and cash equivalents	752		365
End of period cash and cash equivalents and restricted cash and cash equivalents	$	238	$	135

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 Interests		Total Equity

























December 31, 2025	45,688	$	1,709	$	(612)	$	(4)	$	—	$	—	$	1,093
Net Income (Loss)	—	—		63		—		—		—		63
Other comprehensive income (loss)	—	—		—		(7)		—		—		(7)
Share repurchases	(300)	—		—		—		(101)		—		(101)
Retirement of treasury stock	—	(12)		(89)		—		101		—		—





Equity incentive plans	7	25		—		—		—		—		25
March 31, 2026	45,395	$	1,722	$	(638)	$	(11)	$	—	$	—	$	1,073


Net Income (Loss)	—	—		(92)		—		—		—		(92)
Other comprehensive income (loss)	—	—		—		(1)		—		—		(1)
Share repurchases	(550)	—		—		—		(196)		—		(196)
Retirement of treasury stock	—	(21)		(175)		—		196		—		—
Common stock issued in business combination	2,400	927		—		—		—		—		927
Changes in equity of noncontrolling interests	—	—		—		—		—		23		23




Equity incentive plans	655	(95)		—		—		—		—		(95)
June 30, 2026	47,900	$	2,533	$	(905)	$	(12)	$	—	$	23	$	1,639

__________________

(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		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		—





Equity incentive plans	—	11		—		—		—		11
March 31, 2025	45,510	$	1,718	$	(528)	$	(10)	$	—	$	1,180

Net Income (Loss)	—	—		72		—		—		72
Other comprehensive income (loss)	—	—		—		1		—		1







Equity incentive plans	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

NOTES TO THE INTERIM FINANCIAL STATEMENTS (UNAUDITED)

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 15.7 GW of power infrastructure in the United States, including 2.2 GW of nuclear power and a significant dispatchable fossil 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, Ohio, Indiana, 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, including variable interest entities for which we are the primary beneficiary; (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. These 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.

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.

Summary of Significant Accounting Policies

See Note 1 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 2033. The net notional volumes of commodity derivatives were:


	June 30, 2026 (a)	December 31, 2025 (a)
Power (MWh)	(87,190,322)	(59,634,723)
Natural gas (MMBtu)	311,022,216	169,209,022
Emission allowances (tons)	158,000	—

__________________

(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 range in maturity through 2029. The net notional volumes of open interest rate derivatives were:


	June 30, 2026		December 31, 2025
Interest rate (in millions)	$	990	$	990

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, 2026 and December 31, 2025.

As of June 30, 2026, Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs, and any allowances for doubtful collections, was $1.3 billion and its credit exposure including such netting effects was $60 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 84% of Talen’s total net credit exposure, which primarily relate to entities with 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, 2026 and December 31, 2025.

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, 2026				December 31, 2025
	Assets		Liabilities		Assets		Liabilities
Commodity contracts	$	130	$	572	$	56	$	97
Interest rate contracts	1		1		—		4

Total current derivative instruments	131		573		56		101
Commodity contracts	7		149		4		59
Interest rate contracts	2		1		—		8
Total non-current derivative instruments	$	9	$	150	$	4	$	67

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. 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. See Note 11 for additional information on fair value of commodity and interest rate derivatives.

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, 2026 and December 31, 2025.

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, 2026
Assets	$	1,033	$	(851)	$	182	$	(42)	$	140
Liabilities	1,695		(851)		844		(121)		723
December 31, 2025
Assets	$	456	$	(396)	$	60	$	—	$	60
Liabilities	608		(396)		212		(44)		168

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,
	2026		2025		2026		2025
Realized gain (loss) on commodity contracts
Energy revenues (a)	$	65	$	43	$	(262)	$	16
Fuel and energy purchases (a)	(26)		(5)		26		19
Unrealized gain (loss) on commodity contracts
Operating revenues (b)	(212)		176		(324)		(65)
Energy expenses (b)	1		(84)		(41)		(25)
Realized and unrealized gain (loss) on interest rate contracts
Interest expense and other finance charges	9		—		11		(13)

__________________

(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,
	2026		2025		2026		2025
Electricity sales and ancillary services, ISO/RTO	$	626	$	307	$	1,962	$	889
Capacity revenues	237		88		444		137
Physical electricity sales, bilateral contracts, other	31		14		56		37

Total revenue from contracts with customers	894		409		2,462		1,063
Realized and unrealized gain (loss) on derivative instruments	(147)		218		(586)		(50)

Other revenue	—		3		—		7
Operating revenues	$	747	$	630	$	1,876	$	1,020

Accounts Receivable

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


	June 30, 2026		December 31, 2025
Customer accounts receivable	$	240	$	160
Other accounts receivable	54		36
Accounts receivable	$	294	$	196

During the six months ended June 30, 2026 and 2025, 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

Talen’s estimated future fixed fee performance obligations primarily include capacity volumes awarded, net of capacity repurchases by the Company, through PJM BRAs and incremental PJM capacity auctions, and components of capacity contracts with customers for which consideration is fixed and determinable. See Note 9 for additional information on the PJM BRAs.

Future performance obligations that were unsatisfied or partially unsatisfied were:


	2026 (a)		2027		2028		2029		2030		Thereafter (c)		Total
Expected capacity revenues as of June 30, 2026	$	639	$	1,273	$	561	$	50	$	56	$	226	$	2,807
2028/2029 PJM Capacity Year (b)	—		—		696		491		—		—		1,186
Total expected capacity revenues	$	639	$	1,273	$	1,257	$	541	$	56	$	226	$	3,993

__________________

(a)Estimated for the period from July 1, 2026 through December 31, 2026.

(b)PJM capacity revenues are estimated for the period from June 1, 2028 through May 31, 2029 based on the result of the 2028/2029 PJM BRA held in July 2026. Talen cleared 10,180 MWs at a price of $325.00/MWd for the MAAC, PPL, and RTO locational deliverability areas. PJM BRAs have not yet occurred for periods after the 2028/2029 PJM Capacity Year.

(c)Contractual maturities through 2035.

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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,
	2026			2025			2026			2025
Income (loss) before income taxes	$	(129)		$	97		$	(48)		$	(90)
Income tax benefit (expense)	37			(25)			19			27
Effective tax rate	28.7		%	25.8		%	39.6		%	30.0		%
Income tax benefit (expense) computed at the federal income tax statutory tax rate of 21%	$	27		$	(20)		10			19
Additional tax benefit (expense) due to:

Permanent differences	44			9			41			15
NDT taxes	(20)			(12)			(17)			(10)
Change in state rate	(17)			—			(17)			—
State income taxes, net of federal benefit	3			(2)			2			3






Income tax benefit (expense)	$	37		$	(25)		$	19		$	27

5. Inventory


	June 30, 2026		December 31, 2025
Coal	$	78	$	94
Oil products	56		57
Fuel inventory for electric generation	134		151

Materials and supplies, net	162		124
Environmental products	2		3
Inventory, net	$	298	$	278

6. Nuclear Decommissioning Trust Funds


	June 30, 2026								December 31, 2025
	Amortized Cost		Unrealized Gains		Unrealized Losses		Fair Value		Amortized Cost		Unrealized Gains		Unrealized Losses		Fair Value
Cash equivalents	$	9	$	—	$	—	$	9	$	16	$	—	$	—	$	16
Equity securities	389		827		(20)		1,196		385		739		(19)		1,105
Debt securities	791		4		(9)		786		773		7		(3)		777
Receivables (payables), net	6		—		—		6		2		—		—		2
NDT Funds	$	1,195	$	831	$	(29)	$	1,997	$	1,176	$	746	$	(22)	$	1,900

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, 2026 and December 31, 2025.

As of June 30, 2026, 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, 2026 was:


	Fair Value		Unrealized Losses
Corporate debt securities	$	195	$	(3)
Municipal debt securities	57		(1)
U.S. Government debt securities	311		(5)
Debt securities in unrealized loss position	$	563	$	(9)

As of June 30, 2026, the aggregate fair value of debt securities whose carrying value was below the purchase price for a duration of one year or longer was $115 million and the unrealized losses related to such securities were non-material.

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The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:


	June 30, 2026		December 31, 2025
Maturities within one year	$	21	$	23
Maturities within two to five years	221		233
Maturities thereafter	544		521
Debt securities, fair value	$	786	$	777

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,
	2026		2025		2026		2025
Sales proceeds of NDT funds investments (a)	$	56	$	592	$	136	$	1,168
Realized gains	1		4		2		7
Realized losses	(1)		(3)		(1)		(5)

__________________

(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.

The net unrealized gains and losses recognized associated with equity securities still held at the end of the reporting periods were:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
Equity securities, unrealized gains (losses)	$	124	$	61	$	88	$	37

7. Property, Plant and Equipment


		June 30, 2026						December 31, 2025
	Estimated Useful Life (years)	Gross Value		Accumulated Depreciation		Carrying Value		Gross Value		Accumulated Depreciation		Carrying Value
Electric generation	3-37	$	11,753	$	(634)	$	11,119	$	7,522	$	(481)	$	7,041
Nuclear fuel	1-6	458		(197)		261		403		(213)		190
Other property and equipment	3-24	327		(13)		314		63		(11)		52

Capitalized software	1-5	11		(6)		5		10		(5)		5
Construction work in progress		229		—		229		258		—		258
Property, plant and equipment, net		$	12,778	$	(850)	$	11,928	$	8,256	$	(710)	$	7,546

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,
	2026		2025		2026		2025
Depreciation expense (a)	$	88	$	52	$	165	$	107
Amortization expense (b)	—		3		1		8
Accretion expense (c)	15		15		29		29

Depreciation, amortization and accretion	$	103	$	70	$	195	$	144

__________________

(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.

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.

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8. Asset Retirement Obligations and Accrued Environmental Costs

Certain subsidiaries of the Company have legal retirement obligations for the decommissioning and environmental remediation costs associated with our current and former generation sites. 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.

The Company may be required to revise or recognize new AROs as a result of regulatory changes by the NRC, the EPA, Montana Department of Environmental Quality (the “MDEQ”) or other regulatory entities. Additionally, revisions may result from scope of work amendments to remediation activities as well as changes to remediation costs and other assumptions. If the assumptions underlying any ARO estimates do not materialize as expected, actual cash expenditures and costs could be materially different than currently estimated.

As of June 30, 2026, the fair values of certain conditional AROs as a result of the EPA CCR Rule cannot be determined. See Note 9 for additional information on a recent EPA proposal to rescind certain provisions of the EPA CCR Rule.

The carrying value of AROs and accrued environmental costs were:


	June 30, 2026		December 31, 2025
Asset retirement obligations	$	531	$	514
Accrued environmental costs	19		20
Total asset retirement obligations and accrued environmental costs	550		534
Less: asset retirement obligations and accrued environmental costs due within one year (a)	53		40

Asset retirement obligations and accrued environmental costs due after one year	$	497	$	494

__________________

(a)Presented as “Other current liabilities” on the Consolidated Balance Sheets.

The changes of the ARO carrying value during the period were:


	2026
Carrying value January 1,	$	514

Obligations settled	(16)
Accretion expense	29
Changes in estimates and (or) settlement dates	(1)
Obligations incurred	5
Carrying value, June 30,	$	531

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


	June 30, 2026		December 31, 2025

Nuclear (a)	$	289	$	272
Non-nuclear (b)	242		242
Carrying value	$	531	$	514

__________________

(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 6 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.

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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.

Spent Nuclear Fuel Litigation. Federal law currently 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 2026, the Company reached an agreement with the DOE for a reimbursement of $5 million (reflecting Talen’s 90% share) related to the 2025 period. As the settlement agreement expired at the end of 2025, we are currently in the process of seeking an extension through 2028; however, we cannot be certain that such extension will be executed on similar terms or at all.

Winter Storm Uri Lawsuits. In connection with the sale of Talen’s generating facilities in Texas in May 2024, 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 power market participants. These cases were transferred to a single multi-district litigation (MDL) court. In January 2023, the MDL court ruled on various motions to dismiss, but denied the motions to dismiss filed by the generator defendants. In December 2023, the Texas First Court of Appeals granted a mandamus petition and instructed the MDL court to grant the motions to dismiss filed by the generator defendants. In early 2025, the plaintiffs filed for mandamus relief in the Texas Supreme Court seeking to overturn the Texas First Court of Appeals. In March 2026, the Texas Supreme Court denied the plaintiffs’ requests. While Talen expects the dismissal ruling to be applied broadly to all Uri cases against Talen’s former subsidiaries, the cases remain pending at this time. If the cases are not dismissed, Talen’s maximum potential damages for claims filed prior to the restructuring are expressly limited by Talen’s plan of reorganization to payments from Talen’s insurers. However, claims filed after the restructuring by plaintiffs who did not receive effective notice of the restructuring, if any, may not be subject to the limitations in the plan. Talen cannot predict the effect of an adverse outcome for any such claims.

See Note 9 to the Annual Financial Statements for certain other active legal matters.

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; the North American Energy Reliability Corporation (“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.

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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. In early 2024, the FERC accepted portions of PJM’s proposed market changes and PJM scheduled certain PJM BRAs on a delayed basis. 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. 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, which the FERC approved, six-month delays to the scheduled PJM BRAs for the 2028/2029 and 2029/2030 PJM Capacity Years to June 2026 and December 2026, respectively. The 2028/2029 PJM BRA was held in July 2026. Currently, the auction for the 2030/2031 PJM Capacity Year in May 2027 is scheduled on a non-delayed basis. Talen can provide no assurance that these or any scheduled PJM BRAs will be held on such dates 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.

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 PJM Capacity 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 were 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 PJM Capacity Years and proposed, among other things, a lower capacity price cap. As a result of a subsequent agreement between the Commonwealth 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 Commonwealth 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 and 2027/2028 PJM BRAs. In April 2026, the FERC approved the extension of the same price collar framework for the 2028/2029 and 2029/2030 PJM Capacity Years.

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.

Brandon Shores and H.A. Wagner RMR Agreements. 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 third-party 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 $2.5 million per year unit performance “hold back;” and (iv) each facility will receive separate reimbursement for variable costs and approved project investments. In August 2025, the Maryland Office of People’s Counsel filed an appeal of the FERC’s order approving the Brandon Shores and H.A. Wagner RMR agreements. Talen has intervened in that proceeding and plans to participate.

In May 2026, PJM formally requested extension of the RMR agreements through May 31, 2031. The extension RMR agreements were filed with the FERC in June 2026 and allow for an increase of annual fixed-cost payments to account for cost-of-living adjustments to wages and additional project investments. The Maryland Office of People's Counsel and the Independent Market Monitor filed protests, and the FERC is expected to make a decision by mid-September.

Interconnection of Large Loads. In October 2025, DOE directed the FERC to consider reforms to expedite and facilitate how large loads interconnect to the interstate transmission system. DOE stated that the Federal Power Act permits the FERC to exert jurisdiction over load interconnections even though it has not historically done so. DOE provided a draft advance notice of proposed rulemaking (“ANOPR”) and directed the FERC to initiate rulemaking procedures. In November 2025, the FERC requested public comment on the ANOPR, and the Company provided comments. DOE directed the FERC to take final action by the end of April 2026.

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In August 2025, PJM began an accelerated process known as a Critical Issue Fast Path (“CIFP”) process with stakeholders to address how to integrate large load customers quickly and reliably. The CIFP stakeholders represented a wide range of views about resource allocations, costs, and how the addition of large loads like data centers to PJM should be managed in the context of the capacity market. The Company was an active participant in the CIFP process and submitted a joint proposal amongst itself, Constellation, Calpine, Amazon, Microsoft, and Google representing the group’s collective views on the best approach to large load additions. Neither the joint proposal nor any of the other proposals submitted received broad stakeholder support during voting. Nevertheless, PJM had planned to make a filing at the FERC in January 2026 containing PJM’s ultimate proposal to be in place for the 2028/2029 PJM BRA.

In December 2025, however, the FERC issued an order in a show cause proceeding on large loads co-located with generation. The FERC directed PJM to submit an informational report containing, among other items, all of the CIFP proposals. The FERC also found that the PJM tariff was unjust and unreasonable as to the interconnection of co-located loads. The FERC requested tariff revisions be submitted over the next 30-60 days and established a hearing schedule, which began in February 2026, to establish rates, terms, and conditions of several new transmission services.

In January 2026, the National Energy Dominance Council (“NEDC”) and the Governors from each of the 13 states in PJM issued a “Statement of Principles” for PJM. Among other things, the statement calls for PJM to conduct a reliability backstop auction for new baseload capacity with 15-year contracts by September 2026. It also urged PJM to extend the existing price collar for the next two BRAs. Hours after the NEDC/Governors’ principles were released, the PJM Board of Managers issued a Board Decisional Letter — the final step in the Large Load Addition CIFP process. The Board’s Decisional Letter adopted specific elements of various proposals, including load forecasting improvements, voluntary bring your own generation paired with an expedited interconnection track, a holistic review in the coming year of investment incentives in PJM’s markets, and immediate initiation of a reliability backstop procurement.

In May 2026, PJM published a report examining the causes of the growing capacity shortfall and initiated the holistic market review called for by the PJM Board. PJM is holding a series of meetings to discuss proposed pathways with stakeholders. As with the other PJM stakeholder processes, the Company is participating.

In June 2026, the FERC issued tailored FPA Section 206 Show Cause Orders to each of the RTO/ISOs, including PJM in lieu of a nation-wide rulemaking. Each order asked the RTO to explain or revise its tariff in five key areas: (i) large load interconnection process; (ii) cost allocation; (iii) providing new transmission services for flexible large loads; (iv) behind the meter generation and co-located loads; and (v) developing a process to study generating facilities that serve electrically proximate and co-located loads. PJM has 60 days to respond. Additionally, the order gave PJM 30 days to submit an informational report describing how PJM intends to ensure that adequate generation will be available to serve existing and new large loads.

PJM Reliability Backstop Procurement. In February 2026, PJM launched a series of workshops to develop a proposal for a reliability backstop procurement, a one-time, transitional procurement of capacity to begin to address the expected future load growth in the PJM region. As with the CIFP process, the Company is actively participating and presented a joint proposal with a cross-sector coalition. In April 2026, PJM staff presented its initial proposal for a two-phase reliability backstop procurement. The first phase, which would run from September 2026 to March 2027, entailed PJM acting as a “matchmaker” for bilateral contracts; the second phase, which would not commence until March 2027, was a centralized procurement. Additional workshops to receive feedback on the proposal and receive alternative proposals were held in May and June 2026. At the end of the process, PJM stakeholders approved an alternative proposed by the Joint Electric Distribution Companies with the Data Center Coalition. This alternative proposal included a backstop procurement based on a voluntary “registry-based subscription model” rather than forecasted demand and a $555/MWd cap. On July 31, 2026, PJM filed its final version of the reliability backstop procurement with the FERC. The final version of the procurement included a one-time pay-as-bid auction based on the recent 2028/2029 base residual auction shortfall of 6.8 GW. The proposal calls for capacity contracts for 15 years with the auction starting in September 2026 with new capacity to go online by 2032. In addition, it contains a maximum bid price that is capped at the volume-weighted average of levelized costs of all selected offers, with that value set at $555/MWd. The proposal is now pending at the FERC.

PJM also plans to file an “Interim Resource Adequacy Service” proposal, that is designed to address how new data center load connects to the grid.

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Environmental Matters

Extensive federal, state, and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, 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. The EPA’s reconsiderations for many of these regulations and policies remain ongoing, and 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 continue 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 and Pennsylvania 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 in April 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 has continued to be uncertain.

In January 2026, the EPA proposed Phase 1 of its reconsideration of the Good Neighbor Plan. In its proposal, the EPA proposes to approve state implementation plan submissions governing interstate emissions from eight states (Alabama, Arizona, Kentucky, Minnesota, Mississippi, Nevada, New Mexico, and Tennessee). If finalized, these states would no longer be subject to Good Neighbor Plan requirements. Although Talen does not operate in any of the states identified in the proposed rule, the EPA in its proposal states that it intends to undertake a separate action to address interstate transport obligations for the remaining states covered under the Good Neighbor Plan. The comment period on the proposal ended in March 2026.

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) (the “2024 EPA MATS Rule”). Challenges to the 2024 EPA MATS Rule were filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. The appeal on the merits of the 2024 rule remains pending in the D.C. Circuit Court of Appeals, but the litigation has been held in abeyance since February 2025, while the EPA reconsidered the rule. In February 2026, the EPA completed its reconsideration and issued a final rule repealing the lower particulate matter standards set in the 2024 amendments and reverting to particulate matter standards promulgated in the 2012 EPA MATS Rule (the “MATS Repeal Rule”). In March 2026, environmental groups challenged the MATS Repeal Rule in the D.C. Circuit Court of Appeals. Talen filed a motion to intervene in the MATS Repeal Rule litigation in April 2026, which remains pending. The D.C. Circuit Court of Appeals issued an order holding the challenge to the 2024 EPA MATS Rule in abeyance until the litigation over EPA’s MATS Repeal Rule is fully resolved. In April 2026, environmental groups challenging the MATS Repeal Rule also filed an administrative petition requesting that the EPA reconsider the final rule. The petitioners filed a motion requesting that the D.C. Circuit Court of Appeals hold litigation over the MATS Repeal Rule in abeyance for six months to allow the EPA to act on their petition for reconsideration. The motion to hold the case in abeyance remains pending in the D.C. Circuit Court of Appeals. No assurance can be provided as to whether the MATS Repeal Rule will survive judicial challenge and when such challenges will be resolved. Colstrip was not expected to meet the 2024 particulate matter standard without substantial upgrades to its control equipment. As a result, if the MATS Repeal Rule is vacated by a court or reconsidered by the EPA in the future, Talen Montana and the other Colstrip co-owners may 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 other compliance requirements.

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In April 2025, President Trump granted Colstrip a two-year exemption from compliance obligations of the 2024 EPA MATS Rule via Section 112(i)(4) of the Clean Air Act. Environmental groups filed separate lawsuits in the D.C. Circuit Court of Appeals and the U.S. District Court for D.C., challenging the presidential exemptions issued to Colstrip and other fossil fuel-fired power plants. On August 5, 2025, the EPA filed a motion in each case requesting the courts hold the litigation in abeyance for six months pending the EPA’s efforts to repeal the 2024 EPA MATS Rule. Talen filed motions to intervene in both cases on August 8, 2025. On September 3, 2025, the U.S. District Court for D.C. granted the EPA’s motion to hold the case in abeyance for six months and also granted Talen’s motion to intervene. Plaintiffs filed a motion asking the court to reconsider its decision to hold the case in abeyance. The U.S. District Court for D.C. denied that motion in November 2025. The D.C. Circuit Court of Appeals granted the EPA’s motion for an abeyance and Talen’s motion to intervene in October 2025. In March 2026, both the U.S. District Court for D.C. and the D.C. Circuit Court of Appeals granted plaintiffs’ motions to hold the case in abeyance until the litigation over the EPA’s MATS Repeal Rule is fully resolved. The Company could be forced to make operating decisions about the future of Colstrip before clarity is obtained on legal challenges regarding the MATS Repeal Rule and the presidential exemption litigation.

EPA GHG Rule. In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and greenhouse gas (“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. In June 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 public comment period on the proposal expired in August 2025. No assurance can be provided as to whether the rule will be finalized and whether a final rule will survive judicial challenge. 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 February 2026, the EPA issued a final rule rescinding its 2009 finding that GHG emissions endanger public health and welfare and repealing all GHG emissions standards for light-, medium-, and heavy-duty vehicles and engines. 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 and has subsequently relied on this finding as a basis to regulate other sources of GHGs. In the final rule, the EPA states it must rescind the endangerment finding because it lacks the statutory authority to regulate GHG emissions from vehicles in response to global climate changes concerns. The EPA does not explicitly state how the rescission impacts its authority to regulate GHG emissions from stationary sources. However, the final rule acknowledges that the EPA has relied on the endangerment finding “to extend the GHG regulatory program to new and existing stationary source performance standards and guidelines for power plants under CAA section 111.” Citizen groups, states, municipalities and cities have challenged the final rule in the D.C. Circuit Court of Appeals. In May 2026, a citizen group representing 18 youth plaintiffs filed a motion requesting that the D.C. Circuit Court of Appeals stay the final rule pending the court’s review. The D.C. Circuit Court of Appeals has not yet ruled on the stay motion. Environmental groups, a coalition of state and local governments, a labor union, and a zero-emission vehicle advocacy group also filed four separate petitions for administrative reconsideration with the EPA. In June 2026, the petitioners notified the EPA that they intended to sue the agency to compel action on their administrative petitions for reconsideration. No assurance can be provided as to whether the rule will survive judicial challenge or administrative reconsideration.

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NSPS for Stationary Combustion Turbines. In January 2026, the EPA finalized a rule revising new source performance standards (“NSPS”) for stationary combustion turbines. The final rule establishes NOx emission standards for various combustion turbine sizes, retains existing SO2 standards and establishes design efficiency subcategories and utilization requirements. The final rule applies to combustion turbines that commenced construction, modification, or reconstruction after December 13, 2024. As a result, the rule could impact certain, newer generating assets of the Company or development projects. In March 2026, environmental groups challenged the final rule in the D.C. Circuit Court of Appeals and separately filed with the EPA a petition for administrative reconsideration. In May 2026, petitioners requested that the D.C. Circuit Court of Appeals hold the case in abeyance to provide the EPA additional time to take action on their pending reconsideration petition. Talen is a member of an ad hoc industry coalition that filed a motion to intervene in the case in April 2026. The D.C. Circuit Court of Appeals granted the coalition’s motion to intervene in May 2026, and the EPA’s motion to hold the case in abeyance in July 2026. No assurance can be provided as to when the challenges to the final NSPS will be resolved or whether such challenges will be resolved in the Company’s favor.

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. In November 2025, the Pennsylvania legislature passed a budget that included provisions requiring Pennsylvania to withdraw from RGGI. As a result, the PADEP filed an application to the Pennsylvania Supreme Court requesting to discontinue its appeal. The Pennsylvania Supreme Court granted the application and dismissed the case in January 2026.

EPA ELG Rule. In November 2015, the EPA revised the effluent limitation guidelines (“ELGs”) 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 (“UWAG”), 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. No assurance can be provided as to when the challenges to the 2024 EPA ELG Rule will be resolved.

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 September 2025, the EPA issued a direct final rule extending a short-term deadline and a companion proposal extending many compliance deadlines for the 2024 EPA ELG Rule and providing some flexibility relating to some deadlines in the 2020 ELG Rule. In November 2025, the EPA issued a notice withdrawing the direct final rule due to the receipt of adverse comments. The EPA finalized its proposal in December 2025. Among other things, the final rule extends zero-discharge compliance deadlines established in the 2024 EPA ELG Rule by five years from December 31, 2029 to December 31, 2034. The extension rule has been legally challenged by environmental groups. These challenges have been consolidated in the U.S. Court of Appeals for the Second Circuit. In March 2026, the court granted UWAG’s motion to intervene in the consolidated litigation. In May 2026, the EPA issued a separate proposal to revise the 2024 ELG for unmanaged combustion residual leachate (“UCRL”). In the proposed rule, the EPA outlines three proposed regulatory options to address UCRL, proposes new provisions to clarify the applicability of UCRL limits, and seeks additional information to inform further potential revisions to the 2024 EPA ELG Rule. Talen submitted comments on the proposal in June 2026. The comment period for the proposal ended on June 17, 2026. No assurance can be provided as to whether the EPA will finalize changes to the EPA ELG Rule and whether any changes will survive judicial review.

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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 (“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. The EPA has also announced it will reform the EPA CCR Rule and provided in the Legacy CCR Rule litigation proceeding that EPA CCR Rule reforms will be completed in 2026. As an initial reform step, in February 2026, the EPA issued a final rule extending compliance deadlines for elements in the Legacy CCR Rule, including required applicability assessments, the initiation of new groundwater monitoring detection, and the initiation of unit closure. In April 2026, the EPA issued a proposal to amend various provisions in the CCR regulations. Among other things, the EPA proposes to rescind all requirements for CCRMUs, restore the categorical exemption for onsite beneficial use of CCR, and allow for site-specific flexibilities for closures of CCR units through a CCR permitting program. The comment deadline for the CCR proposal was June 29, 2026. Talen submitted comments in support of the EPA’s proposed amendments to the CCR regulations. In May 2026, the EPA also reopened the comment period for its 2020 proposal to establish a federal permit program for the disposal of CCR. The EPA accepted comments on the proposed rule until July 29, 2026. No assurance can be provided as to when and how federal CCR regulations will change further, when the legal challenges to the Legacy CCR Rule will be resolved, how the EPA’s interpretations or further EPA CCR Rule reforms will be resolved, or whether such challenges will be decided in the Company’s favor.

Talen continues to review the Legacy CCR Rule provisions that went into effect in 2024, perform the required applicability assessments, and await additional EPA CCR Rule reforms. As a result of the EPA’s February 2026 CCRMU Extension Rule, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are now due in February 2027. Following that, site investigation may be required to further investigate applicability, and a subsequent facility report is due in February 2028. 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 to meet these deadlines. 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.

As of June 30, 2026, 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.

Certain Resolved Matters

See Note 9 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.

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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, 2026 and December 31, 2025, the aggregate amount of surety bonds outstanding was $221 million and $228 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below.

Talen Montana Financial Assurance. Pursuant to the Colstrip Administrative Order on Consent (the “Colstrip AOC”), Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (the “MDEQ”) on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.

The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities was $103 million and $114 million as of June 30, 2026 and December 31, 2025, 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.

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, 2026, TES was not in default under any of its debt or credit agreements.

Long-Term Debt


	Interest Rate (a)	June 30, 2026		December 31, 2025
TLB-1	5.39 %	$	844	$	848
TLB-2	5.39 %	837		842
TLB-3	5.64 %	1,194		1,200
Secured Notes	8.625 %	—		1,200
2031 Unsecured Notes	6.125 %	1,500		—
2033 Unsecured Notes	6.375 %	2,500		—
2034 Unsecured Notes	6.250 %	1,400		1,400
2036 Unsecured Notes	6.500 %	1,290		1,290
PEDFA 2009B Bonds	5.25 %	50		50
PEDFA 2009C Bonds	5.25 %	81		81
Total principal		9,696		6,911
Unamortized deferred financing costs and original issuance discounts		(124)		(100)
Total carrying value		9,572		6,811
Less: long-term debt, due within one year		29		29
Long-term debt		$	9,543	$	6,782

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(a)Computed interest rate as of June 30, 2026, except the interest rate related to the Secured Notes which were redeemed in April 2026.

Revolving Credit and Other Facilities


		June 30, 2026								December 31, 2025
	Maturity	Committed Capacity (a)		Direct Cash Borrowings		LCs Issued		Unused Capacity		Committed Capacity (a)		Direct Cash Borrowings		LCs Issued		Unused Capacity
RCF	December 2029	$	1,350	$	—	$	—	$	1,350	$	900	$	—	$	—	$	900
LCF	December 2029	1,500		—		598		902		1,100		—		448		652
Total		$	2,850	$	—	$	598	$	2,252	$	2,000	$	—	$	448	$	1,552

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(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.

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Financing Transactions

During the second quarter 2026, TES entered into various amendments to the Credit Agreement.

Repricing Transactions. In May 2026, TES repriced the RCF, TLB-1 and TLB-2 to each bear interest at:

•A variable interest rate equal to the highest of: (i) the Federal Funds Effective Rate on such day plus 0.50%; (ii) The Wall Street Journal “U.S. Prime Rate;” or (iii) the one-month Adjusted Term SOFR Rate plus 1%; plus in each case, an applicable margin (0.50% with respect to the RCF and 0.75% with respect to the TLB-1 and TLB-2); or

•The Adjusted Term SOFR Rate, plus an applicable margin (1.50% with respect to the RCF and 1.75% with respect to the TLB-1 and TLB-2).

Upsizes and Extensions.

•In June 2026, in connection with the closing of the Cornerstone Acquisition, TES (i) upsized the existing RCF (including its revolving LC capacity) from $900 million to $1.35 billion; and (ii) upsized its existing $1.1 billion LCF to $1.5 billion and extended its maturity from December 2027 to December 2029.

•In May 2026, TES extended its TLB-1 maturity from May 2030 to November 2032. In connection with the TLB-1 extension, approximately $18 million is presented as “Interest expense and other finance charges” on the Consolidated Statement of Operations primarily consisting of the derecognition of TLB-1 capitalized original issuance discount and deferred financing costs.

Unsecured Notes due 2031 and 2033. In April 2026, TES issued in private placement transactions not involving a public offering, and each at par: (i) $1.5 billion in aggregate principal amount of 6.125% Senior Unsecured Notes due 2031, with interest payable on May 1 and November 1 of each year; and (ii) $2.5 billion in aggregate principal amount of 6.375% Senior Unsecured Notes due 2033, with interest payable on May 1 and November 1 of each year. The net proceeds from the issuance and sale of the Unsecured Notes due 2031 and 2033 were used to (i) fund the cash portion of the Cornerstone Acquisition; and (ii) redeem the Company’s outstanding Secured Notes.

Additionally, in June 2026, in connection with the closing of the Cornerstone Acquisition, TES entered into (i) First Supplemental Indentures to each of the indentures governing the Unsecured Notes due 2031 and 2033; and (ii) Second Supplemental Indentures to each of the indentures governing the Unsecured Notes due 2034 and 2036, in each case, to add the entities acquired or formed in connection with the Cornerstone Acquisition as subsidiary guarantors to each series of Unsecured Notes, respectively.

Secured Notes. In April 2026, TES redeemed in full the Company’s outstanding Secured Notes in aggregate principal amount of $1.2 billion, using a portion of the net proceeds from the issuance and sale of the Unsecured Notes due 2031 and 2033. In connection with the redemption, approximately $60 million is presented as “Interest expense and other finance charges” on the Consolidated Statement of Operations primarily consisting of a make-whole payments and the derecognition of capitalized deferred financing costs.

See Note 17 for additional information on the Cornerstone Acquisition.

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 $892 million under Secured ISDAs as of June 30, 2026.

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. See Note 1 to the Annual Financial Statements for additional descriptions on fair value levels.

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The classifications of recurring fair value measurements within the fair value hierarchy were:


	June 30, 2026								December 31, 2025
	Level 1		Level 2		NAV		Netting (a)		Total		Level 1		Level 2		NAV		Netting (a)		Total
Assets
Cash equivalents	$	—	$	—	$	9	$	—	$	9	$	—	$	—	$	16	$	—	$	16
Equity securities (b)	961		—		235		—		1,196		871		—		234		—		1,105
U.S. government debt securities	252		116		—		—		368		297		102		—		—		399
Municipal debt securities	—		94		—		—		94		—		101		—		—		101
Corporate debt securities	—		324		—		—		324		—		277		—		—		277

Receivables (payables), net (c)	—		—		—		—		6		—		—		—		—		2
NDT funds	1,213		534		244		—		1,997		1,168		480		250		—		1,900

Commodity derivatives	890		140		—		(893)		137		361		95		—		(396)		60
Interest rate derivatives	—		3		—		—		3		—		—		—		—		—
Total assets	$	2,103	$	677	$	244	$	(893)	$	2,137	$	1,529	$	575	$	250	$	(396)	$	1,960

Liabilities
Commodity derivatives	$	950	$	743	$	—	$	(972)	$	721	$	407	$	189	$	—	$	(440)	$	156
Interest rate derivatives	—		2		—		—		2		—		12		—		—		12

Total liabilities	$	950	$	745	$	—	$	(972)	$	723	$	407	$	201	$	—	$	(440)	$	168

__________________

(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, 2026 and December 31, 2025.

Nonrecurring Fair Value Measurements

There were no nonrecurring fair value measurements related to impairments of long-lived assets during the three and six months ended June 30, 2026 and 2025. See Note 17 to the Interim Financial Statements for fair value measurements related to the Cornerstone Acquisition.

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 carrying value and fair value (classified as Level 2) of indebtedness presented on the Consolidated Balance Sheets were:


	June 30, 2026				December 31, 2025
	Carrying Value		Fair Value		Carrying Value		Fair Value

Long-term debt (a)	$	9,572	$	9,688	$	6,811	$	7,069

__________________

(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,
	2026		2025		2026		2025
Postretirement benefits service cost (a)	$	—	$	—	$	1	$	1

Postretirement benefit (gain) loss
Interest cost	$	17	$	17	$	33	$	34
Expected return on plan assets	(18)		(18)		(37)		(37)

Amortization of:
Postretirement prior service cost (credit)	(1)		(1)		(2)		(2)

Postretirement benefit (gain) loss, net (b)	$	(2)	$	(2)	$	(6)	$	(5)

Net periodic defined benefit cost (credit)	$	(2)	$	(2)	$	(5)	$	(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.

Talen Montana Pension Plan

The Talen Montana defined benefit pension plan was frozen as of April 30, 2026, and participants ceased accruing additional benefits.

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.

Performance Stock Units

PSUs have two or three-year cliff vesting schedules or vest upon consummation of a change in control event based on continued employment and the achievement of certain market conditions over the applicable performance period. Certain participants will be awarded additional PSUs if market conditions exceed certain targets at the time of vesting. The PSUs accrue dividends (if declared and paid) at the same rate as TEC’s common stock. These dividends are paid at the time of vesting.

Changes in non-vested PSUs during the six months ended June 30, 2026 were:


	Liability-Classified PSUs (a)	Equity-Classified PSUs	Total PSUs	Weighted-Average Grant Date Fair Value per Unit
Non-vested as of December 31, 2025	569,477	488,857	1,058,334	$	147.45
Granted	—	146,903	146,903	2,034.32
Forfeited	—	(7,032)	(7,032)	518.24
Vested	(569,477)	(386,870)	(956,347)	55.04

Non-vested as of June 30, 2026 (b)	—	241,858	241,858	$	1,430.56

__________________

(a)See description of liability-classified awards below.

(b)Represents the target number of PSUs. 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. Assuming all non-vested PSUs vested on June 30, 2026 at the then current share price of the Company’s common stock the aggregate non-vested PSUs would be 619,525.

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The fair value of PSUs is determined using a Monte Carlo valuation methodology based on the fair value of the underlying stock price at the grant date. Significant inputs and assumptions used in the valuations of PSUs were:


						Six Months Ended June 30, 2026
Volatility (a)						40% - 50%
Expected term (in years)						2 - 3
Risk-free rate (b)						3.45% - 3.97%

__________________

(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 two or three-year ratable or two-year cliff vesting schedules beginning on the grant date. The fair value of RSUs granted is based on the closing price of TEC common stock on the grant date. The RSUs accrue dividends (if declared and paid) at the same rate as TEC’s common stock. These dividends are paid at the time of vesting.

Changes in non-vested RSUs during the six months ended June 30, 2026 were:


	Liability-Classified RSUs (a)	Equity-Classified RSUs	Total RSUs	Weighted-Average Grant Date Fair Value per Unit
Non-vested as of December 31, 2025	169,642	171,011	340,653	$	106.18
Granted	3,358	72,992	76,350	391.37
Forfeited	—	(2,645)	(2,645)	207.95
Vested	(151,800)	(111,204)	(263,004)	68.15

Non-vested as of June 30, 2026	21,200	130,154	151,354	$	296.55

__________________

(a)See description of liability-classified awards below.

Liability-Classified Awards

PSU and RSU awards of certain executive officers that have or are scheduled to vest in 2026 were or will be partially settled in cash. Generally, the cash settlement amount is equal up to 60% of the net after-tax value on the vesting date of each such award and is subject to a cap. Additionally, it is expected that some non-employee directors will elect to net-settle a portion of their vested PSUs and RSUs for the payment of income taxes. The portion of each employee’s applicable awards that is expected to be settled in cash and all non-employee director awards are presented as “Stock-based compensation liabilities” on the Consolidated Balance Sheets and had a carrying value of $6 million and $501 million as of June 30, 2026 and December 31, 2025, respectively, measured based on the closing share price of TEC common stock on such dates.

Liability-classified awards that vested and settled during the three months ended June 30, 2026, resulted in cash payments of $495 million, including payments related to income tax. Equity-classified awards that vested concurrently with the liability-classified awards resulted in the net settlement of 655,350 shares of TEC common stock and $140 million of cash payments related to income taxes.

Stock-Based Compensation Expense

Stock-based compensation expense presented as “General and administrative” on the Consolidated Statement of Operations was:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

Stock-based compensation expense (benefit), net, liability-classified awards	$	28	$	—	$	4	$	—
Stock-based compensation expense (benefit), net, equity-classified awards	42		16		65		27
Income tax benefit	(11)		(4)		(17)		(7)
After-tax stock-based compensation expense (benefit), net	$	60	$	12	$	52	$	20

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Unrecognized stock-based compensation expense and related periods of recognition as of June 30, 2026 were:


	PSUs			RSUs
	Liability-Classified	Equity-Classified		Liability-Classified		Equity-Classified
Unrecognized stock-based compensation expense (a)	N/A	$	274	$	1	$	28
Weighted-average period of recognition (in years)	N/A	1.6		0.5		1.5

__________________

(a) Stock-based compensation expense related to liability-classified awards is subject to variability due to changes in their value through the settlement date.

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,
	2026		2025		2026		2025
Numerator: (Millions of Dollars)



Net Income (Loss) Attributable to Stockholders	$	(92)	$	72	$	(29)	$	(63)

Denominator: (Thousands)
Weighted-Average Number of Common Shares Outstanding - Basic	45,904		45,554		45,759		45,699

Restricted stock units	—		257		—		—
Performance stock units	—		2,095		—		—
Weighted-Average Number of Common Shares Outstanding - Diluted	45,904		47,905		45,759		45,699

Earnings per Share - Basic	$	(2.00)	$	1.58	$	(0.63)	$	(1.38)
Earnings per Share - Diluted	(2.00)		1.50		(0.63)		(1.38)

As there was a Net Loss Attributable to Stockholders, the computation of diluted EPS excludes 138,886 RSUs and 619,525 PSUs for the three and six months ended June 30, 2026. Diluted EPS for the three months ended June 30, 2025 excludes 83,347 PSUs due to their anti-dilutive nature. As there was 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.

15. Stockholders’ Equity

Share Repurchase Program

Summary of activity under the SRP:


	Six Months Ended June 30, 2026		Six Months Ended June 30, 2025
		Number of Shares	Share Price (a)		Total Amount		Number of Shares	Share Price (a)		Total Amount
Share repurchases		850,000	$	350.21	$	298	452,130	$	186.24	$	85
Share retirements		(850,000)	350.21		(298)		(452,130)	186.24		(85)

__________________

(a)Weighted average price per share, including transaction costs and excise taxes, if applicable.

As of June 30, 2026, the remaining capacity under the SRP was $1.7 billion and all repurchased shares have been retired. See Note 1 to the Annual Financial Statements for the accounting policy related to treasury stock and retirement of treasury stock.

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Accumulated Other Comprehensive Income

Changes in AOCI for the periods were:


	Six Months Ended June 30,
	2026		2025
Beginning balance	$	(4)	$	(12)
Gains (losses) arising during the period	(9)		8
Reclassifications to Consolidated Statements of Operations	(3)		(4)
Income tax benefit (expense)	4		(1)
Other comprehensive income (loss)	(8)		3

Accumulated other comprehensive income (loss)	$	(12)	$	(9)

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


	Six Months Ended June 30,
	2026		2025
Available-for-sale securities unrealized gain (loss), net	$	(4)	$	1

Postretirement benefit prior service credits (costs), net	10		13
Postretirement benefit actuarial gain (loss), net	(18)		(23)
Accumulated other comprehensive income (loss)	$	(12)	$	(9)

Reclassification adjustments from AOCI to the Consolidated Statements of Operations were non-material amounts for the six months ended June 30, 2026 and 2025.

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,
	2026		2025
Cash paid (received) during the period
Interest and other finance charges, net of capitalized interest (a)	$	154	$	107
Income taxes, net	(1)		70

Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows
Commodity contracts	$	365	$	90
Interest rate swap contracts (interest expense)	(13)		13
Unrealized (gain) loss on derivative instruments	$	352	$	103

Depreciation, amortization and accretion included on the Statements of Cash Flows
Depreciation, amortization and accretion	$	195	$	144
Amortization of acquired contract liabilities	(45)		—

Other	8		(3)
Depreciation, amortization and accretion	$	158	$	141

Reconciliation of other non-cash operating activities
Debt restructuring (gain) loss, net	$	22	$	—
Derivative option premium amortization	17		33

(Gain) loss on sale of assets, net	—		(12)










Other	(4)		(14)
Total	$	35	$	7

Non-cash investing activities
Accrued PP&E additions not paid at period end	$	121	$	9

__________________

(a)Capitalized interest was non-material for the six months ended June 30, 2026 and 2025.

Cash and Restricted Cash

The following table provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Balance Sheets to such amounts shown on the Consolidated Statements of Cash Flows:


	June 30, 2026		December 31, 2025
Cash and cash equivalents	$	231	$	689
Restricted cash and cash equivalents (a)	7		63
Total	$	238	$	752

__________________

(a)Comprised of commodity exchange margin deposits.

17. Acquisitions and Divestitures

Acquisitions

Cornerstone Acquisition. On June 15, 2026, the Company completed the Cornerstone Acquisition, which increases the Company’s generation by approximately 2.6 GW and provides efficient baseload and peaker generation and cash flow diversification. The aggregate purchase price was $3.5 billion, comprised of the following:



Cash consideration	$	2,615
Shares of TEC common stock issued ($0.001 par value)	2,399,998
Closing price per share of TEC common stock on June 15, 2026	$	386.21
Equity consideration	$	927
Total consideration	$	3,542

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The Cornerstone Acquisition was accounted for as a business combination. Accordingly, fair value measurements were allocated to acquired assets and assumed liabilities with no resulting goodwill or bargain purchase adjustments. Such fair value measurements are provisional, and revisions may occur up to one year from the date of the acquisition as new information is obtained. The following table summarizes the provisional purchase price allocation for the identifiable assets acquired and liabilities assumed:


	June 15, 2026
Cash and cash equivalents	$	47
Accounts receivable	40
Inventory	31
Other current assets	13
Property, plant and equipment	4,211


Total assets acquired	$	4,342

Accounts payable and other accrued liabilities	$	45
Derivative liabilities, current	93

Asset retirement obligations	5
Acquired contract liabilities	151
Deferred income taxes	457
Derivative liabilities, noncurrent	49
Total liabilities assumed	$	800
Fair value of net assets acquired	$	3,542

The fair values allocated to property, plant and equipment were determined using the income approach valuation technique that discounted the projected future net cash flows expected to be generated by Cornerstone over their remaining economic lives utilizing market participant discount rates. Significant assumptions included the forecasted prices for capacity, wholesale power, and natural gas, volumetric assumptions, and discount rates.

Impact of Cornerstone Acquisition. The following table presents revenues and earnings included in the Consolidated Statements of Operations for the entities acquired in the Cornerstone Acquisition since the acquisition date (June 15, 2026) through June 30, 2026:


	Six Months Ended June 30, 2026
Operating Revenues	$	7
Net Income (Loss) Attributable to Stockholders	(19)

Pro Forma Financial Information. The following unaudited pro forma financial information for the three and six months ended June 30, 2026 and June 30, 2025 assumes the Cornerstone Acquisition occurred on January 1, 2025. The unaudited pro forma financial information is provided for informational purposes only and is not necessarily indicative of the results of operations that would have occurred had the Cornerstone Acquisition been completed on January 1, 2025, nor is the unaudited pro forma financial information indicative of future results of operations.


	Three Months Ended June 30, 2026		Three Months Ended June 30, 2025		Six Months Ended June 30, 2026		Six Months Ended June 30, 2025
Operating Revenues	$	879	$	805	$	2,270	$	1,288
Net Income (Loss) Attributable to Stockholders	(69)		12		(5)		(243)

The unaudited pro forma financial information presented above reflects adjustments for: (i) incremental depreciation associated with the provisional fair value allocated to acquired net assets; (ii) the elimination of historical interest expense of the acquired entities; (iii) the elimination of interest expense related to the Secured Notes redemption; (iv) interest expense associated with debt issued to finance the Cornerstone Acquisition and redeem the Secured Notes; (v) transaction costs associated with the Cornerstone Acquisition and expenses associated with the Secured Notes redemption; (vi) the income tax effects of the Cornerstone Acquisition and related financing transactions; and (vii) the alignment of certain accounting policies.

The Company incurred $24 million and $29 million of acquisition-related transaction costs during the three and six months ended June 30, 2026, respectively, presented as “Other operating income (expense), net” on the Consolidated Statements of Operations, and deferred financing costs of $55 million during the three and six months ended June 30, 2026, respectively, presented as “Long-term debt” on the Consolidated Balance Sheets. See Note 10 for information on recent financing transactions related to the Cornerstone Acquisition.

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Amortization of acquired contract liabilities. The acquisition fair value of a capacity contract presented as “Acquired contract liabilities” on the Consolidated Balance Sheets is subject to periodic amortization. Amortization associated with this contract will begin at the start of the contract term in 2028 and will be presented as an increase to “Capacity revenues.”


	2028		2029		2030		2031		2032		Thereafter (a)		Total
Estimated amortization of acquired contract liabilities	$	18	$	29	$	29	$	24	$	21	$	30	$	151

__________________

(a)Contractual maturities through 2034.

Divestitures

Sale of Keystone Interests. In June 2026, the Company entered into a purchase and sale agreement with an unaffiliated party to sell its 12.34% interest in the Keystone generation facility and certain related assets for an aggregate $85 million in cash, subject to certain working capital adjustments and potential adjustments based on PJM BRA results. Additionally, under the terms of the agreement, the buyer is entitled to the net cash flow attributable to the interests from and after July 1, 2026. The transaction is expected to close in the second half of 2026 and is subject to the satisfaction of customary closing conditions and regulatory approvals from the FERC.

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 (the “CODM”), reviews results. Adjusted EBITDA is the key profit metric used by the CODM to review segment performance and allocate resources as it provides a clearer view of segment profitability by focusing on operational performance. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision maker.

“PJM” represents electricity generation, marketing activities, and commodity risk and fuel management within the PJM 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.

“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, 2026
Operating revenues	$	740	$	13	$	(6)	$	747
Operation, maintenance and development expenses (a)	202		8
Interest expense and other finance charges	—		—		214		214
Other segment items (b)	160
Adjusted EBITDA	378
Capital expenditures	52		124		2		178

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

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	PJM		Other		Corporate and Eliminations		Total
Six Months Ended June 30, 2026
Operating revenues	$	1,850	$	41	$	(15)	$	1,876
Operation, maintenance and development expenses (a)	360		15
Interest expense and other finance charges	—		—		333		333
Other segment items (b)	633
Adjusted EBITDA	857
Capital expenditures	119		126		2		247

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

__________________

(a)This significant segment expense category aligns with the segment-level information that is regularly reviewed by the CODM.

(b)Other segment items are primarily comprised of fuel and energy purchases.

Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes:


	Three Months Ended June 30,				Six Months Ended June 30,
	2026		2025		2026		2025

PJM Segment Adjusted EBITDA	$	378	$	115	$	857	$	324


Reconciling Items:
Interest expense and other finance charges	$	(214)	$	(62)	$	(333)	$	(136)
Depreciation, amortization and accretion (a)	(88)		(67)		(151)		(137)
Nuclear fuel amortization (a)	(22)		(18)		(46)		(44)

Unrealized gain (loss) on commodity derivative contracts	(211)		92		(365)		(90)
Nuclear decommissioning trust funds gain (loss), net	134		80		112		68
Stock-based and other long-term incentive compensation expense	(71)		(18)		(73)		(31)





Acquisition and divestiture activities (b)	(28)		3		(37)		(4)








"Other" operating segment	6		(1)		15		8

Corporate and Eliminations	(10)		(24)		(25)		(42)
Other items	(3)		(3)		(2)		(6)
Income (Loss) Before Income Taxes	$	(129)	$	97	$	(48)	$	(90)

__________________

(a)Includes the periodic amortization of fair value adjustments associated with acquired fuel supply contract liabilities and intangible assets.

(b)Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.

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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 (“MD&A”) 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 2028/2029 Base Residual Auction

In July 2026, PJM announced the results of the 2028/2029 PJM BRA. Talen cleared 10,180 MWs at a price of $325.00/MWd for the MAAC, PPL, and RTO locational deliverability areas.

See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets” for additional information.

Closing of the Cornerstone Acquisition

In June 2026, the Company consummated the Cornerstone Acquisition for an aggregate $3.5 billion, consisting of $2.6 billion in cash, and 2,399,998 shares of TEC common stock, valued at $927 million. The cash portion of the consideration was funded using a portion of the net proceeds of the issuance and sale of the Unsecured Notes due 2031 and 2033 in April 2026. Additionally, in June 2026, we increased the capacities of our existing RCF and LCF.

In connection with the closing of the Cornerstone Acquisition, and pursuant to the Cornerstone RRA, the Company filed a registration statement on Form S-3 (Reg. No. 333-296901), with the SEC on June 18, 2026, registering the shares issued as equity consideration.

See Notes 10 and 17 to the Interim Financial Statements for additional information on the Cornerstone Acquisition and related financing transactions and “Part I, Item 1A. Risk Factors—Risks Related to the Cornerstone Acquisition” of our 2025 Annual Report for a discussion of the associated risks.

Financing Transactions

During the second quarter 2026, TES entered into various amendments to the Credit Agreement.

Repricing Transactions. In May 2026, TES repriced the RCF, TLB-1, and TLB-2.

Upsizes and Extensions. In June 2026, in connection with the Cornerstone Acquisition, TES (i) upsized its existing RCF (including its revolving LC capacity) from $900 million to $1.35 billion; and (ii) upsized its existing $1.1 billion LCF to $1.5 billion and extended its maturity from December 2027 to December 2029. In May 2026, TES extended the maturity of the TLB-1 from May 2030 to November 2032.

Unsecured Notes due 2031 and 2033. In April 2026, TES issued in private placement transactions not involving a public offering: (i) $1.5 billion in aggregate principal amount of 6.125% Senior Unsecured Notes due 2031; and (ii) $2.5 billion in aggregate principal amount of 6.375% Senior Unsecured Notes due 2033. The net proceeds from the issuance and sale of the Unsecured Notes due 2031 and 2033 were used to (i) fund the Cornerstone Acquisition and (ii) redeem the Company’s outstanding Secured Notes.

Secured Notes. In April 2026, TES redeemed in full the Company’s outstanding Secured Notes in aggregate principal amount of $1.2 billion, using a portion of the net proceeds of the Unsecured Notes due 2031 and 2033.

See Note 10 the Interim Financial Statements for additional information on the financing transactions.

Common Stock Repurchases

During the three months ended June 30, 2026, we repurchased and retired 550,000 shares of TEC’s outstanding common stock under the SRP. The aggregate purchase price, including transaction fees, was $198 million at a weighted average price of $359.54 per share. As of June 30, 2026, the remaining capacity under the SRP is $1.7 billion through 2028.

See Note 15 to the Interim Financial Statements and “Item 2. Unregistered Sales of Equity Securities and Use of Proceeds” of this Report for additional information on the SRP.

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,” “Item 1A. Risk Factors” of our 2025 Annual Report, as updated by our Q1 2026 Quarterly Report, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.

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Commodity Markets

During the second quarter 2026, PJM market conditions were influenced by weather-related volatility, as periods of above-average temperatures increased electricity demand and contributed to higher settled on-peak power prices. TETCO M‑3 natural gas prices settled below the five-year average, reflecting ample supply conditions. Natural gas storage inventories remained above the five-year average throughout the quarter.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended June 30, were:


	2026		2025
PJM West Hub Day Ahead Peak - $/MWh	$	65.58	$	52.71
PJM PPL Zone Day Ahead Peak - $/MWh	37.42		40.91
TETCO M-3 - $/MMBtu	2.15		2.47
PJM AEP-D Hub Day Ahead Peak - $/MWh	52.96		49.58

TETCO M-2 - $/MMBtu	2.06		2.35

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


	2026		2025
PJM West Hub ATC - $/MWh	$	71.08	$	49.52
PJM West Hub ATC Spark Spreads - $/MWh (a)	50.04		28.86
PJM AEP-D Hub ATC - $/MWh	58.05		46.23
PJM AEP-D Hub ATC Sparks Spreads - $/MWh (b)	40.50		27.98

__________________

(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

(b)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-2 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. Additionally, capacity prices may be affected by regulatory proceedings and (or) interventions by government stakeholders.

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. 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. 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.

See Note 9 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:


	2028/2029		2027/2028		2026/2027		2025/2026		2024/2025
PJM Capacity Performance ($/MWd) (a)
MAAC and PPL	$	325.00	$	333.44	$	329.17	$	269.92	$	49.49
RTO	325.00		333.44		329.17		269.92		28.92

__________________

(a)Displayed prices are from the applicable market publications.

The PJM BRA for the 2028/2029 PJM Capacity Year was held in July 2026 and the Company cleared 10,180 MW at a price of $325.00/MWd.

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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 maintain 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. Susquehanna commenced its planned refueling outage on Unit 1 on March 23, 2026 and successfully completed the work on May 4, 2026.

Results of Operations

The results of operations presented below are prepared in accordance with GAAP and should be reviewed in conjunction with the Interim Financial Statements and the related Notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the three and six months ended June 30, 2026, compared to the three and six months ended June 30, 2025.

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, and sales under wholesale bilateral contracts. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.

Unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy Expenses.” We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.

Results for the Three Months Ended June 30, 2026 and 2025


	Three Months Ended June 30,				Favorable (Unfavorable) Variance
	2026		2025
Energy and other revenues	$	722	$	366	$	356
Capacity revenues	237		88		149
Unrealized gain (loss) on derivative instruments (Note 2)	(212)		176		(388)
Operating Revenues (Note 3)	747		630		117

Fuel and energy purchases	(357)		(150)		(207)
Nuclear fuel amortization	(22)		(18)		(4)
Unrealized gain (loss) on derivative instruments (Note 2)	1		(84)		85
Energy Expenses	(378)		(252)		(126)

Operating Expenses
Operation, maintenance and development	(210)		(192)		(18)
General and administrative (includes stock-based compensation of $(70) and $(16) (Note 13)	(98)		(41)		(57)
Depreciation, amortization and accretion (Note 7)	(103)		(70)		(33)


Other operating income (expense), net	(30)		(9)		(21)
Operating Income (Loss)	(72)		66		(138)
Nuclear decommissioning trust funds gain (loss), net (Note 6)	134		80		54
Interest expense and other finance charges (Note 10)	(214)		(62)		(152)



Other non-operating income (expense), net	23		13		10
Income (Loss) Before Income Taxes	(129)		97		(226)
Income tax benefit (expense) (Note 4)	37		(25)		62


Net Income (Loss) Attributable to Stockholders	$	(92)	$	72	$	(164)

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Three Months Ended June 30, 2026 compared to Three Months Ended June 30, 2025

Net Income (Loss) Attributable to Stockholders decreased by $(164) million, primarily driven by the factors discussed below.

•Operating Revenues, net of Energy Expenses. $(9) million unfavorable decrease, primarily due to the following:

◦Energy and other revenues, net of Fuel and energy purchases. $149 million favorable increase. This is primarily related to an increase in generation volumes: (i) as a result of the Freedom and Guernsey acquisitions that were completed in November 2025; and (ii) at Susquehanna and our other dispatchable fossil generation facilities.

◦Capacity revenues. $149 million favorable increase. This is primarily driven by higher cleared capacity prices received through the 2025/2026 PJM BRA compared to the 2024/2025 PJM BRA, and higher capacity results due to the Freedom and Guernsey acquisitions that were completed in November 2025.

◦Unrealized gain (loss) on derivative instruments, net. $(303) million unfavorable decrease. This is primarily related to the change in fair value of mark-to-market contracts resulting from higher forward power prices that is partially offset by the change in fair value associated with mark-to-market contracts acquired as a result of the Cornerstone Acquisition.

•General and administrative. $(57) million unfavorable increase. This is primarily associated with: (i) the expense recognized in the current period for stock-based compensation awards granted in the first quarter 2026, and (ii) the effects from a change from equity to liability classification for certain awards in the fourth quarter 2025. Refer to Note 13 to the Interim Financial Statements for additional information on stock-based compensation.

•Depreciation, amortization and accretion. $(33) million unfavorable increase. This is primarily due to an increase in depreciation associated with the Freedom and Guernsey acquisitions that were completed in November 2025.

•Nuclear decommissioning trust funds gain (loss), net. $54 million favorable increase. This is primarily due to unrealized gains on investments in equity securities.

•Interest expense and other finance charges. $(152) million unfavorable increase. This primarily consisted of:

◦$(60) million increase in cash interest expense on the TLB-3 and Unsecured Notes due 2034 and 2036, each issued in the fourth quarter 2025 in connection with the Freedom and Guernsey acquisitions that were completed in November 2025.

◦$(25) million increase in cash interest expense due to the combined effect of financing transactions in April 2026 that included the issuances of the Unsecured Notes due 2031 and 2033 and redemption of the Secured Notes.

◦$(54) million non-recurring make-whole payments associated with the redemption of the Secured Notes.

Refer to Note 10 to the Interim Financial Statements for additional information on long-term debt transactions, including the issuances associated with the Cornerstone Acquisition.

•Income tax benefit (expense). $62 million favorable increase. This is primarily related to a change from pre-tax income for the three months ended June 30, 2025 to pre-tax loss for the three months ended June 30, 2026.

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Results for the Six Months Ended June 30, 2026 and 2025


	Six Months Ended June 30,				Favorable (Unfavorable) Variance
	2026		2025
Energy and other revenues	$	1,756	$	948	$	808
Capacity revenues	444		137		307
Unrealized gain (loss) on derivative instruments (Note 2)	(324)		(65)		(259)
Operating Revenues (Note 3)	1,876		1,020		856

Fuel and energy purchases	(920)		(418)		(502)
Nuclear fuel amortization	(46)		(44)		(2)
Unrealized gain (loss) on derivative instruments (Note 2)	(41)		(25)		(16)
Energy Expenses	(1,007)		(487)		(520)

Operating Expenses
Operation, maintenance and development	(375)		(338)		(37)
General and administrative (includes stock-based compensation of $(69) and $(27)) (Note 13)	(122)		(75)		(47)
Depreciation, amortization and accretion (Note 7)	(195)		(144)		(51)


Other operating income (expense), net	(39)		(16)		(23)
Operating Income (Loss)	138		(40)		178
Nuclear decommissioning trust funds gain (loss), net (Note 6)	112		68		44
Interest expense and other finance charges (Note 10)	(333)		(136)		(197)



Other non-operating income (expense), net	35		18		17
Income (Loss) Before Income Taxes	(48)		(90)		42
Income tax benefit (expense) (Note 4)	19		27		(8)


Net Income (Loss) Attributable to Stockholders	$	(29)	$	(63)	$	34

Six Months Ended June 30, 2026 compared to Six Months Ended June 30, 2025

Net Income (Loss) Attributable to Stockholders increased by $34 million, primarily driven by the factors discussed below.

•Operating Revenues, net of Energy Expenses. $336 million favorable increase, primarily due to the following:

◦Energy and other revenues, net of Fuel and energy purchases. $306 million favorable increase. This is primarily related to a favorable increase in margin associated with electric generation as a result of: (i) the Freedom and Guernsey acquisitions that were completed in November 2025; (ii) higher realized market prices; and (iii) higher generation volumes at Susquehanna and our dispatchable fossil generation facilities. Such favorable increase in margin associated with electric generation is partially offset by lower realized hedge results.

◦Capacity revenues. $307 million favorable increase. This is primarily driven by: (i) higher cleared capacity prices, partially offset by a decrease to lowered cleared volumes through the 2025/2026 PJM BRA compared to the 2024/2025 PJM BRA; and (ii) higher capacity results due to the Freedom and Guernsey acquisitions that were completed in November 2025.

◦Unrealized gain (loss) on derivative instruments, net. $(275) million unfavorable decrease. This is primarily related to the change in fair value mark-to-mark contracts resulting from higher forward power prices associated with net short power positions that is partially offset by the change in fair value associated with market-to-market contracts acquired as a result of the Cornerstone Acquisition.

•Operation, maintenance and development. $(37) million unfavorable increase. Higher generation facility operating costs are due to: (i) an increase associated with the Freedom and Guernsey acquisitions, which were completed in November 2025; (ii) outage and major maintenance projects at our dispatchable fossil generation facilities; and (iii) ongoing operating costs associated with the Brandon Shores and H.A. Wagner RMR Agreements, which began in June 2025.

•General and administrative. $(47) million unfavorable increase. This is primarily associated with the expense recognized in the current period for stock-based compensation awards granted in the first quarter 2026. Refer to Note 13 to the Interim Financial Statements for additional information on stock-based compensation.

•Depreciation, amortization and accretion. $(51) million unfavorable increase. This is primarily due to an increase in depreciation associated with the Freedom and Guernsey acquisitions that were completed in November 2025.

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•Nuclear decommissioning trust funds gain (loss), net. $44 million favorable increase. This is primarily due to unrealized gains on investments in equity securities.

•Interest expense and other finance charges. $(197) million unfavorable increase. This primarily consisted of:

◦$(120) million increase in cash interest expense on the TLB-3 and Unsecured Notes due 2034 and 2036, each issued in the fourth quarter 2025 in connection with the Freedom and Guernsey acquisitions that were completed in November 2025.

◦$(54) million non-recurring make-whole payments associated with the redemption of the Secured Notes.

Refer to Note 10 to the Interim Financial Statements for additional information on long-term debt transactions, including the issuances associated with the Cornerstone Acquisition.

Liquidity and Capital Resources

Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our commercial and hedging activities including settlements, 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 contracts lowers 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, 2026		December 31, 2025
Cash and cash equivalents, unrestricted	$	231	$	689
Unutilized RCF capacity (a)	1,350		900

Total available liquidity	$	1,581	$	1,589
Additional unutilized LC capacity (b)	$	902	$	652

__________________

(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.

(b)Includes LC capacity under the LCF and excludes LC capacity available under the RCF.

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, 2026		December 31, 2025
Outstanding surety bonds	$	221	$	228

Forecasted Uses of Cash

Capital Expenditures. Capital expenditure plans are revised periodically for changes in operational needs, market conditions, regulatory requirements, and cost projections. Accordingly, the expected cash requirements for capital expenditures are subject to revision.


	2026		2027
Nuclear fuel	$	122	$	137
PJM nuclear generation facility	53		46
PJM fossil generation facilities	150		162

Other	13		13
Total (a)	$	338	$	358

__________________

(a)Expected capitalized interest on capital expenditures is a non-material amount in 2026 and 2027.

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
	2026		2025
Operating activities	$	27	$	(65)	$	92
Investing activities	(2,824)		(114)		(2,710)
Financing activities	2,283		(51)		2,334

Operating activities

A change of $92 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 $(2.7) billion in net cash provided by (used in) investing activities was primarily due to $(2.6) billion used to finance the Cornerstone Acquisition. See Note 17 to the Interim Financial Statements for additional information on the acquisition.

Financing activities

A change of $2.3 billion in net cash provided by (used in) financing activities was primarily due to (i) $4.0 billion in new debt from the issuance of the Unsecured Notes due 2031 and 2033; (ii) $(1.2) billion redemption of the Secured Notes; (iii) $(195) million decrease in share repurchases; and (iv) $(140) million in payments for tax withholdings related to stock-based awards.

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.

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Non-GAAP Financial Measure

Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.

Adjusted EBITDA

We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.

Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business.

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)	2026		2025		2026		2025
Net Income (Loss)	$	(92)	$	72	$	(29)	$	(63)
Adjustments
Interest expense and other finance charges	214		62		333		136
Income tax (benefit) expense	(37)		25		(19)		(27)
Depreciation, amortization and accretion (a)	88		67		151		137
Nuclear fuel amortization (a)	22		18		46		44

Unrealized (gain) loss on commodity derivative contracts	211		(92)		365		90
Nuclear decommissioning trust funds (gain) loss, net	(134)		(80)		(112)		(68)
Stock-based and other long-term incentive compensation expense	71		18		73		31





Acquisition and divestiture activities (b)	28		(3)		37		4








Other	3		3		2		6
Total Adjusted EBITDA	$	374	$	90	$	847	$	290

__________________

(a)Includes the periodic amortization of fair value adjustments associated with acquired fuel supply contract liabilities and intangible assets.

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Critical Accounting 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 our 2025 Annual Report 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.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

We have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2026.

Changes in Internal Control Over Financial Reporting

During the three months ended June 30, 2026, management was in the process of integrating the internal controls of the entities recently acquired in the Cornerstone Acquisition into the Company’s existing operations. Other than additional controls associated with the Cornerstone Acquisition, there were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2026 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

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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 2025 Annual Report, as updated by our Q1 2026 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

For information related to the Company’s risk factors, see “Part I, Item 1A. Risk Factors” in our 2025 Annual Report.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Issuer Purchases of Equity Securities

The following table contains information regarding our purchases of our common stock during the three months ended June 30, 2026:


Monthly Period	Total number of shares purchased	Average price paid per share (a)		Total number of shares purchased as part of publicly announced plan (b)	Approximate dollar value of shares that may yet be purchased under the plan (c)
April	—	$	—	—	$	1,900
May	133,327	361.22		133,327	1,852
June	416,673	358.98		416,673	1,702
Total	550,000	$	359.53	550,000

__________________

(a)Excludes transaction costs and excise taxes.

(b)Represents shares repurchased under the SRP. See below for a description of the SRP.

(c)Dollars in millions.

Our Board of Directors approved the SRP in October 2023, authorizing the Company to repurchase TEC’s outstanding shares of common stock. See “Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” in our 2025 Annual Report for additional information related to the SRP and shares repurchased under the SRP.

The following table contains information on changes to the SRP since program inception:

Board Authorization Date

SRP Expiration Date

Remaining SRP Capacity at Time of Authorization (a)

October 2023

December 2025

300

May 2024

December 2025

1,000

September 2024

December 2026

1,250

September 2025

December 2028

2,000

__________________

(a)Dollars in millions.

For a description of limitations on the payment of our dividends, see “Part II, Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities” in our 2025 Annual Report.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

Rule 10b5-1 Trading Plans

During the three months ended June 30, 2026, 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#^	Agreement and Plan of Merger, dated as of January 15, 2026, by and among Talen Energy Corporation, Cornerstone Generation Holdings, LP, ECP Cornerstone Generation Holdings GP, LLC, ECP V-B (AG IP) Blocker Corp, ECP V-C (AG IP) Blocker Corp, ECP V-D (AG IP) Blocker Corp, ECP V-D, as a holder representative, and solely for the limited purposes set forth therein, ECP GP V, LP.	10-K	001-37388	February 26, 2026	2.1
3.1	Third Amended and Restated Certificate of Incorporation of Talen Energy Corporation.	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
4.1	Registration Rights Agreeme nt , dated June 15 , 2026, by and among Tale n Energy Corporation and the holders named therein.	8-K	001-37388	June 15, 2026	4.1
4.2	Indenture, dated as of April 29, 2026, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as t rustee (relating to the 6 .125 % Senior Unsecured Notes due 2031 ).	10-Q	001-37388	May 05, 2026	4.2
4.3	F orm of 6.125% Senior Unsec ured Notes due 2031 (included as Exhi bit A to Exhibit 4.2 hereto).	10-Q	001-37388	May 05, 2026	4.3
4.4	Indenture, dated as of April 29, 2026, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB, as t rustee (relating to the 6.375% Senio r Unsecured Notes due 2033 ).	10-Q	001-37388	May 05, 2026	4.4
4.5	F orm of 6.375% Senior Unsecured Note due 2033 (included as Exhibit A to Exhibit 4.4 hereto).	10-Q	001-37388	May 05, 2026	4.5
4.6*	First Supplemental Indenture, dated as of June 16, 2026 , by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB , as t rustee (relating to the 6.125 % Senior Unsecured Notes due 2031 ).	—	—	—	—
4.7*	First Supplemental Indenture, dated as of June 16, 2026 , by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Wilmington Savings Fund Society, FSB , as t rustee (relating to the 6.375 % S enior Unsecured Notes due 2033 ).	—	—	—	—
4.8*	Second Supplemental Indenture, dated as of June 16, 2026 , by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Citibank, N.A ., as t rustee (relating to the 6.250% Senior Unsecured Notes due 2034 ).	—	—	—	—
4.9*	Second Supplemental Indenture, dated as of June 16, 2026, by and among Talen Energy Supply, LLC, the subsidiary guarantors party thereto and Citibank, N.A., as trustee (relating to the 6.500% Senior Unsecured Notes due 2036).	—	—	—	—
10.1	Amendment No. 6 to Credit Agreement, dated as of May 20 , 2026, by and among Talen Energy Supply, LLC, as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent.	8-K	001-37388	May 21, 2026	10.1
10.2	A mendment No. 7 to Credit Agreement, dated as of June 15, 2026, by and among T alen Energy Supply, LLC , as borrower, the subsidiary guarantors party thereto, the lenders party thereto and Citibank, N.A., as administrative agent and collateral agent.	8-K	001-37388	June 15, 2026	10.1
31.1*	Certification of Principal Executive Officer p ursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
31.2*	Certification of Principal Financial Officer p ursuant to Section 302 of the Sarbanes-Oxley Act of 2002.	—	—	—	—
32.1**	Certification of Principal Executive Officer and 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.

# 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.

† Management contract or compensatory plan or arrangement.

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GLOSSARY OF TERMS AND ABBREVIATIONS

Adjusted EBITDA. Net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business.

Annual Financial Statements. The audited consolidated balance sheets of TEC as of December 31, 2025 and December 31, 2024; the related audited consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the years ended December 31, 2025 and December 31, 2024, for the period from May 18, 2023 through December 31, 2023, and for the period from January 1, 2023 through May 17, 2023; and the related notes included in the Company’s Annual Report on Form 10-K filed with the SEC on February 26, 2026.

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 adjacent to Susquehanna.

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 occurred in April 2026.

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.

Capacity Performance. The sole class of capacity product that electricity providers within PJM can offer to satisfy PJM’s capacity obligation and thereby receive capacity payments from PJM. Auctions for this opportunity, generally referred to as capacity auctions, are scheduled by PJM periodically, up to three years in advance of the applicable PJM Capacity Year and in accordance with the terms of PJM’s Tariff and the FERC’s orders. Capacity Performance providers assume higher performance requirements during system emergencies and are subject to penalties for non-performance.

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 7 to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in Colstrip.

Cornerstone Acquisition. Our acquisition of Waterford, Darby, and Lawrenceburg from affiliates of Energy Capital Partners, which closed in June 2026. See Note 17 to the Interim Financial Statements for additional information.

Cornerstone RRA. Registration Rights Agreement, dated June 15, 2026, by and among TEC and the holders named therein, entered into at the closing of the Cornerstone Acquisition in connection with the issuance of stock consideration.

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, TLB-3, and LCF, as the same may be amended, amended and restated, supplemented, or otherwise modified from time to time.

Credit Facilities. Collectively, the RCF, TLB-1, TLB-2, TLB-3 and LCF.

Darby. A Talen-owned and operated generation facility in Mount Sterling, Ohio.

DOE. U.S. Department of Energy.

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EPA. U.S. Environmental Protection Agency.

EPA CCR Rule. The national regulatory standards required by the EPA for the management of coal combustion residuals 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, the EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 MW.

EPS. Earnings per share.

Exchange Act. The Securities Exchange Act of 1934, as amended.

FERC. U.S. Federal Energy Regulatory Commission.

Freedom. A Talen-owned and operated generation facility in Salem Township, Luzerne County, Pennsylvania.

GAAP. Generally Accepted Accounting Principles in the United States.

Guernsey. A Talen-owned and operated generation facility in Byesville, Ohio.

GW. Gigawatt.

H.A. Wagner. A Talen-owned and operated generation facility in Curtis Bay, Maryland.

Interim Financial Statements. The condensed consolidated balance sheets of TEC as of June 30, 2026 and December 31, 2025; the related condensed consolidated statements of operations, statements of comprehensive income, and statements of equity for the three and six months ended June 30, 2026 and 2025, the consolidated statements of cash flows for the six months ended June 30, 2026 and 2025; and the related notes.

ISA. Interconnection Service Agreement.

ISO. Independent System Operator.

Lawrenceburg. A Talen-owned and operated generation facility in Lawrenceburg, Indiana.

LC. Letter of credit.

LCF. The $1.5 billion 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.

MWd. Megawatt-day.

MWh. Megawatt-hour.

NAV. Net asset value.

NDT. Nuclear facility decommissioning trust that is expected to fund Talen’s proportionate costs associated with the future decommissioning activities of Susquehanna.

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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 (or “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.

PJM Reliability Pricing Model. PJM’s capacity market, or the Reliability Pricing Model, formed under PJM’s Open Access Transmission Tariff, which is intended to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted energy demand in the future. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.

PP&E. Property, plant and equipment.

RCF. The senior secured revolving credit facility that provides $1.35 billion in aggregate revolving loan and LC commitments under the Credit Agreement.

RCRA. The Resource Conservation and Recovery Act, a federal law enacted in 1976 giving the EPA authority to control hazardous and non-hazardous solid waste from its creation to its disposal.

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, which were redeemed in full in April 2026.

Secured Notes 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, the Fourth Supplemental Indenture, dated as of January 13, 2025, and the Fifth Supplemental Indenture, dated as of November 25, 2025, each between TES, the Subsidiary Guarantors and Wilmington Savings Fund Society, FSB, as trustee, which governed the Secured Notes, as the same may be further amended, amended and restated, supplemented or otherwise modified from time-to-time. The Secured Notes were redeemed in full in April 2026.

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, the Secured Notes, and the Unsecured 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”). Talen Energy Corporation 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.

TLB-1. The $580 million (subsequently increased to $870 million) senior secured term loan B facility, due November 2032, under the Credit Agreement.

TLB-2. The $850 million senior secured term loan B facility, due December 2031, under the Credit Agreement.

TLB-3. The $1.2 billion senior secured term loan B facility, due November 2032, under the Credit Agreement.

Unsecured Notes. Collectively, TES’s 6.125% Senior Unsecured Notes due 2031, 6.375% Senior Unsecured Notes due 2033, 6.250% Senior Unsecured Notes due 2034, and 6.500% Senior Unsecured Notes due 2036.

Waterford. A Talen-owned and operated generation facility in Waterford Township, Ohio.

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 thereunto duly authorized.