SEC EDGAR · 10-Q

10-Q – 2026-08-05 – tln-20260630.htm

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3. Revenue | 11
ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 42
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) weat | 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.
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) weat | 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:
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:
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 mi | 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 a | 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 ex
3. Revenue | The components of operating revenues for the periods were:
2026 2025 2026 2025 | Electricity sales and ancillary services, ISO/RTO $ 626 $ 307 $ 1,962 $ 889 | Capacity revenues 237 88 444 137

EBITDA

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 | “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.
160 | Adjusted EBITDA 378 | Capital expenditures 52 124 2 178
343 | Adjusted EBITDA 115 | Capital expenditures 33 4 — 37
633 | Adjusted EBITDA | 857
363 | Adjusted EBITDA | 324
Reconciliation of Segment Adjusted EBITDA to Income (Loss) Before Income Taxes:
PJM Segment Adjusted EBITDA $ 378 $ 115 $ 857 $ 324
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,

Rörelseresultat

Other operating income (expense), net ( 30 ) ( 9 ) ( 39 ) ( 16 ) | Operating Income (Loss) ( 72 ) 66 138 ( 40 )
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
Other non-operating income (expense), net 23 13 35 18 | Income (Loss) Before Income Taxes ( 129 ) 97 ( 48 ) ( 90 )
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 faciliti | 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.
(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.
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 asso | 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 rel | 30
Other operating income (expense), net (30) (9) (21) | Operating Income (Loss) (72) 66 (138)
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

Periodens resultat

Net Income (Loss) Attributable to Stockholders $ ( 92 ) $ 72 $ ( 29 ) $ ( 63 ) | Per Common Share
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 )
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
Net Income (Loss) $ ( 92 ) $ 72 $ ( 29 ) $ ( 63 ) | Other Comprehensive Income (Loss)
Operating Activities | Net Income (Loss) $ ( 29 ) $ ( 63 ) | Non-cash reconciliation adjustments:
December 31, 2025 45,688 $ 1,709 $ ( 612 ) $ ( 4 ) $ — $ — $ 1,093 | Net Income (Loss) — — 63 — — — 63 | Other comprehensive income (loss) — — — ( 7 ) — — ( 7 )
Net Income (Loss) — — ( 92 ) — — — ( 92 ) | Other comprehensive income (loss) — — — ( 1 ) — — ( 1 )
December 31, 2024 45,962 $ 1,725 $ ( 326 ) $ ( 12 ) $ — $ 1,387 | Net Income (Loss) — — ( 135 ) — — ( 135 ) | Other comprehensive income (loss) — — — 2 — 2

Resultat per aktie

14. Earnings Per Share | 27
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:
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.
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.

Kassaflöde

16. Supplemental Cash Flow Information | 29
Cash Flow Activities | 39
See Note 16 for supplemental cash flow information. | The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
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 man | 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.
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 | 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
16. Supplemental Cash Flow Information | Supplemental information for the Consolidated Statements of Cash Flows for the periods was:
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:
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, 20

Likvida medel

Assets | Cash and cash equivalents $ 231 $ 689 | Restricted cash and cash equivalents (Note 16) 7 63
Cash and cash equivalents $ 231 $ 689 | Restricted cash and cash equivalents (Note 16) 7 63 | Accounts receivable (Note 3) 294 196
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
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
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
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 s | 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 mi
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 s | 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 mi | 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 a
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:

Nettoskuld

Other liabilities ( 47 ) ( 101 ) | Net cash provided by (used in) operating activities 27 ( 65 )
Other 13 2 | Net cash provided by (used in) investing activities ( 2,824 ) ( 114 )
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 )
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:
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, 20
Cash Flow Activities | Net cash provided by (used in) operating, investing, and financing activities for the periods was:
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
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

Eget kapital

15. Stockholders' Equity | 27
Stockholders' Equity (Note 15)
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
15. Stockholders’ Equity
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 | AOCI. Accumulated other comprehensive income or loss, which is a component of stockholders’ equity on the Consolidated Balance Sheets. | ARO. Asset retirement obligation.

Antal aktier

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
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
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.
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:
Denominator: (Thousands) | Weighted-Average Number of Common Shares Outstanding - Basic 45,904 45,554 45,759 45,699
Performance stock units — 2,095 — — | Weighted-Average Number of Common Shares Outstanding - Diluted 45,904 47,905 45,759 45,699
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)
Number of Shares Share Price (a) | Total Amount Number of Shares Share Price (a) | Total Amount

Antal anställda

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.

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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 10-Q

(Mark One)

☒  QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2026
OR

☐  TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from __________ to __________
Commission File Number: 001-37388

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

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

2929 Allen Pkwy, Suite 2200 , Houston , TX 77019
(Address of principal executive offices) (Zip Code)
( 888 ) 211-6011
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class Trading Symbol(s)
Name of each exchange on which registered

Common stock, par value $0.001 per share TLN The Nasdaq Global Select Market

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐ No ☒
As of August 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 lopment s
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

Table of Contents

CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report on Form 10-Q (this “Report”) contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, and (or) future performance or other events, as well as underlying assumptions and other statements, that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would,” or similar expressions. Although we believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, there can be no assurance that these expectations and assumptions will prove to be correct. Forward-looking statements are subject to many risks and uncertainties. The results, events, or circumstances reflected in forward-looking statements may not be achieved or occur, and actual results, events, or circumstances may differ materially from those discussed in forward-looking statements.
The risks, uncertainties, and other factors that could cause actual results to differ materially from the forward-looking statements made by us include those discussed in this Report, 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.
1

Table of Contents

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)

 Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars, except share data) 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.
2

Table of Contents

TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)

 Three Months Ended June 30, Six Months Ended June 30,
(Millions of Dollars) 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.
3

Table of Contents

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.
4

Table of Contents

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.
5

Table of Contents

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.
6

Table of Contents

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.
7

Table of Contents

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 treatm ent 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 Com monwealth 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 SO 2 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 wa s $ 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  

__________________
(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  

__________________
(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.
◦ $(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.

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.