Talen Energy Corporation

11/03/2026 | Press release | Distributed by Public on 11/03/2026 08:00

Quarterly Report for Quarter Ending September 30, 2026 (Form 10-Q)

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 Capacity Monetization
On October 1, 2026, TEM closed on a capacity monetization agreement to sell rights to approximately $1.5 billion in future PJM capacity cash flows for the 2027/2028 and 2028/2029 PJM Capacity Years and the Company used the net proceeds of $1.3 billion to fund accelerated share repurchases.
See Note 3 to the Interim Financial Statements for additional information.
Upsize of Share Repurchase Program and Accelerated Share Repurchases
In September 2026, the Board of Directors approved the upsizing of the Company's existing SRP from $1.5 billion to an aggregate remaining capacity of $3 billion, subject to utilization under the ASR program.
On October 1, 2026, the Company received and retired 3,811,460 shares of TEC common stock repurchased under ASR program with multiple dealers, which is equivalent to 80% of the aggregate $1.5 billion value of the ASR program. The final settlement is expected to be completed no later than the first quarter of 2027. The accelerated share repurchases are being funded by net proceeds of $1.3 billion from the capacity monetization transaction and cash on hand.
See Note 15 to the Interim Financial Statements for additional information.
Common Stock Repurchases
During the three months ended September 30, 2026, the Company repurchased and retired 600,000 shares of TEC's outstanding common stock under the SRP, separate from the ASR program. The aggregate purchase price, including transaction fees, was $204 million at a weighted average price of $339.48 per share. As of September 30, 2026, the remaining capacity under the SRP was $3.0 billion through 2028.
See Note 15 to the Interim Financial Statements and "Part II, 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" and "Part I, Item 1A. Risk Factors" of our 2025 Annual Report, as updated by our 2026 Quarterly Reports, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the third quarter 2026, PJM market conditions were influenced by weather, as periods of above-average temperatures increased electricity demand and contributed to higher settled on-peak power prices. Natural gas prices settled below the five-year average and natural gas storage inventories remained above the five-year average throughout the quarter, reflecting ample supply conditions.
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended September 30, were:
2026 2025
PJM West Hub Day Ahead Peak - $/MWh $ 100.51 $ 61.89
PJM PPL Zone Day Ahead Peak - $/MWh 58.65 47.78
TETCO M-3 - $/MMBtu 1.88 2.27
PJM AEP-D Hub Day Ahead Peak - $/MWh 83.44 55.58
TETCO M-2 - $/MMBtu 1.79 2.17
The weighted average forward market prices for the periods October 1 through December 31 as of September 30, were:
2026 2025
PJM West Hub ATC - $/MWh $ 71.54 $ 47.50
PJM West Hub ATC Spark Spreads - $/MWh (a)
52.76 26.00
PJM AEP-D Hub ATC - $/MWh 60.16 44.33
PJM AEP-D Hub ATC Sparks Spreads - $/MWh (b)
45.07 27.05
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(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
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(a)Displayed prices are from the applicable market publications.
In July 2026, the Company cleared 10,180 MW in the PJM BRA for the 2028/2029 PJM Capacity Year at a price of $325.00/MWd.
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.
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 nine months ended September 30, 2026, compared to the three and nine months ended September 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 September 30, 2026 and 2025
Three Months Ended September 30,
Favorable (Unfavorable) Variance
2026 2025
Energy and other revenues $ 1,187 $ 604 $ 583
Capacity revenues 323 166 157
Unrealized gain (loss) on derivative instruments (Note 2) (183) 42 (225)
Operating Revenues (Note 3) 1,327 812 515
Fuel and energy purchases (626) (259) (367)
Nuclear fuel amortization (27) (27) -
Unrealized gain (loss) on derivative instruments (Note 2) (7) (6) (1)
Energy Expenses (660) (292) (368)
Operating Expenses
Operation, maintenance and development (167) (131) (36)
General and administrative (includes stock-based compensation of $(51) and $(15)) (Note 13)
(76) (38) (38)
Depreciation, amortization and accretion (Note 7) (157) (61) (96)
Other operating income (expense), net (12) (27) 15
Operating Income (Loss) 255 263 (8)
Nuclear decommissioning trust funds gain (loss), net (Note 6) 18 81 (63)
Interest expense and other finance charges (Note 10) (148) (67) (81)
Gain (loss) on sale of assets, net (Note 17) 66 25 41
Other non-operating income (expense), net 4 2 2
Income (Loss) Before Income Taxes 195 304 (109)
Income tax benefit (expense) (Note 4) (57) (97) 40
Net Income (Loss) Attributable to Stockholders $ 138 $ 207 $ (69)
Three Months Ended September 30, 2026 compared to Three Months Ended September 30, 2025
Net Income (Loss) Attributable to Stockholders decreased by $(69) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $147 million favorable increase, primarily due to the following:
◦Energy and other revenues, net of Fuel and energy purchases. $216 million favorable increase. This is primarily related to: (i) an increase in generation volumes as a result of the Freedom and Guernsey acquisitions that were completed in November 2025 and the Cornerstone Acquisition that was completed in June 2026; and (ii) an increase in realized prices and generation volumes at Susquehanna and our other dispatchable fossil generation facilities. Such amounts were offset by a decrease in realized hedge results.
◦Capacity revenues. $157 million favorable increase. This is primarily related to: (i) higher cleared capacity prices, partially offset by lower volumes cleared through the 2026/2027 PJM BRA compared to the 2025/2026 PJM BRA; and (ii) higher capacity revenue due to the Freedom and Guernsey acquisitions that were completed in November 2025 and the Cornerstone Acquisition that was completed in June 2026.
◦Unrealized gain (loss) on derivative instruments, net. $(226) million unfavorable decrease. This is primarily related to the impact of higher forward power prices on the fair value of mark-to-market contracts that were entered into during the period.
•Operation, maintenance and development. $(36) million unfavorable increase. This is primarily related to higher generation facility operating costs due to: (i) an increase associated with the Freedom and Guernsey acquisitions and the Cornerstone Acquisition, which were completed in November 2025 and June 2026, respectively; and (ii) operations and routine maintenance projects at our dispatchable fossil generation facilities.
•General and administrative. $(38) million unfavorable increase. This is primarily due to an increase in grant date stock price of RSUs and grant date fair value of PSUs. See Note 13 to the Interim Financial Statements for additional information on stock-based compensation.
•Depreciation, amortization and accretion. $(96) 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 and the Cornerstone Acquisition completed in June 2026.
•Nuclear decommissioning trust funds gain (loss), net. $(63) million unfavorable decrease. This is primarily due to an aggregate decrease of unrealized and realized net gains on investments in equity securities.
•Interest expense and other finance charges. $(81) million unfavorable increase. This is primarily related to the: (i) TLB-3 and the 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; and (ii) 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.
See Note 10 to the Interim Financial Statements for additional information on long-term debt transactions, including the issuances associated with the Cornerstone Acquisition.
•Gain (loss) on sale of assets, net. $41 million favorable increase. This is primarily related to the September 2026 sale of interests in the Keystone generation facility and certain related assets.
•Income tax benefit (expense). $40 million favorable decrease. This is primarily related to a decrease in pre-tax income and NDT taxes.
Results for the Nine Months Ended September 30, 2026 and 2025
Nine Months Ended September 30,
Favorable (Unfavorable) Variance
2026 2025
Energy and other revenues $ 2,943 $ 1,552 $ 1,391
Capacity revenues 767 303 464
Unrealized gain (loss) on derivative instruments (Note 2) (507) (23) (484)
Operating Revenues (Note 3) 3,203 1,832 1,371
Fuel and energy purchases (1,546) (677) (869)
Nuclear fuel amortization (73) (71) (2)
Unrealized gain (loss) on derivative instruments (Note 2) (48) (31) (17)
Energy Expenses (1,667) (779) (888)
Operating Expenses
Operation, maintenance and development (542) (469) (73)
General and administrative (includes stock-based compensation of $(120) and $(42)) (Note 13)
(198) (113) (85)
Depreciation, amortization and accretion (Note 7) (352) (205) (147)
Other operating income (expense), net (51) (43) (8)
Operating Income (Loss) 393 223 170
Nuclear decommissioning trust funds gain (loss), net (Note 6) 130 149 (19)
Interest expense and other finance charges (Note 10) (481) (203) (278)
Gain (loss) on sale of assets, net (Note 17) 69 36 33
Other non-operating income (expense), net 36 9 27
Income (Loss) Before Income Taxes 147 214 (67)
Income tax benefit (expense) (Note 4) (38) (70) 32
Net Income (Loss) Attributable to Stockholders $ 109 $ 144 $ (35)
Nine Months Ended September 30, 2026 compared to Nine Months Ended September 30, 2025
Net Income (Loss) Attributable to Stockholders decreased by $(35) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $483 million favorable increase, primarily due to the following:
◦Energy and other revenues, net of Fuel and energy purchases. $522 million favorable increase. This is primarily related to: (i) an increase in generation volumes as a result of the Freedom and Guernsey acquisitions that were completed in November 2025 and the Cornerstone Acquisition that was completed in June 2026; and (ii) an increase in realized prices and generation volumes at Susquehanna and our other dispatchable fossil generation facilities. Such amounts were offset by a decrease in realized hedge results.
◦Capacity revenues. $464 million favorable increase. This is primarily related to: (i) higher cleared capacity prices, partially offset by lower volumes cleared through the 2026/2027 PJM BRA compared to the 2025/2026 PJM BRA; and (ii) higher capacity revenue due to the Freedom and Guernsey acquisitions that were completed in November 2025 and the Cornerstone Acquisition that was completed in June 2026.
◦Unrealized gain (loss) on derivative instruments, net. $(501) million unfavorable decrease. This is primarily related to the impact of higher forward power prices on the fair value of mark-to-market contracts that were open or entered into during the period.
•Operation, maintenance and development. $(73) million unfavorable increase. This is primarily related to higher generation facility operating costs due to: (i) an increase associated with the Freedom and Guernsey acquisitions and the Cornerstone Acquisition, which were completed in November 2025 and June 2026, respectively; and (ii) operations, outage, and routine maintenance projects at our dispatchable fossil generation facilities.
•General and administrative. $(85) million unfavorable increase. This is primarily associated with (i) an increase in grant date stock price of RSUs and grant date fair value of PSUs; and (ii) an accounting change of certain awards to liability classification in the fourth quarter 2025 as well as the periodic expense recognized for awards granted prior to 2026. See Note 13 to the Interim Financial Statements for additional information on stock-based compensation.
•Depreciation, amortization and accretion. $(147) 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 and the Cornerstone Acquisition that was completed in June 2026.
•Interest expense and other finance charges. $(278) million unfavorable increase. This is primarily related to the: (i) interest associated with the TLB-3 and the 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), (ii) combined effect of financing transactions in April 2026 that included the issuances of the Unsecured Notes due 2031 and 2033 (each issued in connection with the Cornerstone Acquisition that was completed in June 2026) as well as the redemption of the Secured Notes, and (iii) $(77) million nonrecurring make-whole payments associated with the Secured Notes redemption. Such amounts were partially offset primarily by the recognition of net gains associated with the change in fair value of interest rate swaps due to higher SOFR forward prices.
See Note 10 to the Interim Financial Statements for additional information on long-term debt transactions, including the issuances associated with the Cornerstone Acquisition.
•Gain (loss) on sale of assets, net. $33 million favorable increase. This is primarily related to a $66 million gain on the sale of our interests in the Keystone generation facility and certain related assets, partially offset by a $22 million gain from the sale of the Camden and Dartmouth generation facilities in September 2025. See Note 17 to the Interim Financial Statements for additional information.
•Income tax benefit (expense). $32 million favorable decrease. This is primarily related to a decrease in pre-tax income and an increase in permanent differences reducing the effective tax rate, partially offset by a change in the state blended tax rate due to 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
September 30,
2026 		December 31,
2025
Cash and cash equivalents, unrestricted $ 335 $ 689
Unutilized RCF capacity (a)
1,350 900
Total available liquidity $ 1,685 $ 1,589
Additional unutilized LC capacity (b)
$ 1,018 $ 652
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(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.
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.
September 30,
2026 		December 31,
2025
Outstanding surety bonds $ 224 $ 228
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
Nine Months Ended September 30, Change
2026 2025
Operating activities $ 490 $ 424 $ 66
Investing activities (2,963) (156) (2,807)
Financing activities 2,070 (136) 2,206
Operating activities
A change of $66 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 $(2.8) 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 $2.2 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) $(399) million decrease in share repurchases; and (iv) $(141) 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.
Non-GAAP Financial Measure
Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
Adjusted EBITDA
We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.
Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business.
Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company's operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.
The following table presents a reconciliation of the GAAP financial measure of "Net Income (Loss)" presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:
Three Months Ended September 30, Nine Months Ended September 30,
(Millions of Dollars) 2026 2025 2026 2025
Net Income (Loss) $ 138 $ 207 $ 109 $ 144
Adjustments
Interest expense and other finance charges 148 67 481 203
Income tax (benefit) expense 57 97 38 70
Depreciation, amortization and accretion (a)
122 61 273 198
Nuclear fuel amortization (a)
27 27 73 71
Unrealized (gain) loss on commodity derivative contracts 190 (36) 555 54
Nuclear decommissioning trust funds (gain) loss, net (18) (81) (130) (149)
Stock-based and other long-term incentive compensation expense
54 18 127 49
(Gain) loss on asset sales, net (Note 17)
(66) (25) (69) (36)
Non-cash impairments and other charges
1 1 2 11
Acquisition and divestiture activities (b)
2 8 39 12
Operational and other restructuring activities
4 3 11 6
Other 10 16 7 20
Total Adjusted EBITDA $ 669 $ 363 $ 1,516 $ 653
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(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.
Critical Accounting Estimates
The Company's financial statements are prepared in conformity with GAAP, which requires the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i) the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. See our 2025 Annual Report for a description of our significant accounting policies and estimates.
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