Talen Energy Corporation
11/05/2025 | Press release | Distributed by Public on 11/05/2025 16:20
Quarterly Report for Quarter Ending September 30, 2025 (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 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
Financing Transactions
Issuance of Senior Notes. In October 2025, TES issued: (i) $1.4 billionin aggregate principal amount of 6.25%Senior Unsecured Notes due 2034; and (ii) $1.29 billionin aggregate principal amount of 6.50%Senior Unsecured Notes due 2036. We expect to use the net proceeds from the Unsecured Notes, together with the proceeds of the new TLB-3 discussed below, to fund the Freedom and Guernsey Acquisitions.
Credit Facility Transactions. Also in October 2025, TES undertook the following financing transactions that are expected to become effective concurrently with the closing of either the Freedom Acquisition or the Guernsey Acquisition (whichever closes first): (i) allocated and priced a $1.2 billion senior secured term loan B credit facility (the TLB-3), a portion of which may be incurred on a delayed-draw basis, the proceeds of which, together with the proceeds from the Unsecured Notes, are intended to be used to fund the Freedom and Guernsey Acquisitions; (ii) received commitments to increase its existing RCF (including its revolving LC capacity) from $700 million to $900 million; and (iii) received commitments to upsize its existing $900 million LCF to $1.1 billion and extend the maturity from December 2026 to December 2027.
Bridge Commitment Termination. Also in October 2025, in connection with the financing transactions described above, TES terminated its previous commitment letters for $3.8 billion in secured and unsecured indebtedness to fund the Freedom and Guernsey Acquisitions.
See Notes 10 and 17 to the Interim Financial Statements for additional information on the financing transactions and the Freedom and Guernsey Acquisitions.
Upsize of Share Repurchase Program
In September 2025, the Board of Directors approved the upsizing of the Company's existing SRP from $995 million to a aggregate remaining capacity of $2 billion and extended the expiration of the SRP from December 31, 2026 to December 31, 2028. The execution of this additional authorization is contingent on the completion of the Freedom and Guernsey Acquisitions.
See Note 15 to the Interim Financial Statements for additional information.
Sale of Nuclear Production Tax Credits
The Nuclear PTC, created under the Inflation Reduction Act, provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. Subject to the qualification requirements, electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 is eligible for the credit.
In September 2025, we sold certain 2024 Nuclear PTCs to an unaffiliated third party for $191 million. See Note 4 to the Interim Financial Statements for additional information on the sale of the Nuclear PTCs.
See Note 3 to the Interim Financial Statements for additional information on the recognized revenue that is associated with the Nuclear PTC.
Camden and Dartmouth Sales
In September 2025, we sold the Camden and Dartmouth generation facilities for a combined as-adjusted purchase price of $25 million in cash, subject to further post-closing adjustments.
See Note 17 to the Interim Financial Statements for additional information.
Freedom and Guernsey Acquisitions
In July 2025, we entered into definitive agreements to acquire Caithness Energy's 1,045 MW (summer rating) Freedom Generating Station in Pennsylvania and 1,836 MW (summer rating) Guernsey Power Station in Ohio, both gas fired combined cycle plants located within the PJM power market, for an aggregate gross purchase price of approximately $3.8 billion (subject to working capital and other customary adjustments), or $3.5 billion after adjusting for estimated tax benefits. See Note 10 to the Interim Financial Statements for additional information on the financing transactions related to the Freedom and Guernsey Acquisitions.
The addition of these assets to Talen's portfolio will increase our generating capacity by approximately 3 gigawatts and is expected to enhance our ability to offer reliable, scalable, grid-supported, and regionally diverse low-carbon capacity to hyperscale data centers and other large commercial off-takers. Additionally, as these facilities have an average heat rate of 6,550 Btu/kWh, the Freedom and Guernsey Acquisitions will provide the Company with incremental baseload generation and cash flow diversification. The presence of these facilities in the PJM market complements our existing commercial and marketing capabilities, and their strategic location adjacent to the Marcellus and Utica shale formations provides ample natural gas supplies and reliable access to natural gas pipeline infrastructure and interconnects.
The transactions are subject to regulatory approvals and the satisfaction of other customary closing conditions, and are both expected to close in the first quarter of 2026. The relevant regulatory filings have all been made and are now pending at the agencies.
See Note 17 to the Interim Financial Statements for additional information on the Freedom and Guernsey Acquisitions and "Part II, Item 1A. Risk Factors" of our Quarterly Report on Form 10-Q for the three months ended June 30, 2025 for a discussion of the associated risks.
The foregoing description of the Purchase Agreements and the transactions contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Purchase Agreements, copies of which are attached as Exhibits 2.1 and 2.2 to this Report. The Purchase Agreements are being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Purchase Agreements, which may be subject to important limitations and qualifications, and which may change after the date of the Purchase Agreements, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.
Factors Affecting Our Financial Condition and Results of Operations
Earnings in future periods are subject to various uncertainties and risks. See "Cautionary Note Regarding Forward-Looking Information," the sections entitled "Item 1A. Risk Factors" in this Report and our 2024 Annual Report, as updated by our 2025 Quarterly Reports, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the third quarter 2025, PJM weather-related volatility resulted in certain days that experienced above-average temperatures. This contributed to an increase in load demand and higher settled on-peak power prices for the period. Texas Eastern M-3 natural gas prices settled higher in the period due to the effect of increased electric demand despite elevated storage levels that continue to exceed the five-year average.
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended September 30, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 61.89 | $ | 50.03 | ||||||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 47.78 | 37.54 | ||||||||||||
| Texas Eastern M-3 - $/MMBtu | 2.27 | 1.50 | ||||||||||||
The weighted average forward market prices for the periods from October 1 through December 31 as of September 30, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub ATC - $/MWh | $ | 47.50 | $ | 42.67 | ||||||||||
| Texas Eastern M-3 - $/MMBtu | 3.07 | 2.47 | ||||||||||||
|
PJM West Hub ATC Spark Spreads - $/MWh (a)
|
26.00 | 25.34 | ||||||||||||
__________________
(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, Texas Eastern M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Capacity Markets
Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.
PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.
Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2026/2027 PJM Capacity Year was held in July 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 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:
| 2026/2027 | 2025/2026 | 2024/2025 | 2023/2024 | |||||||||||||||||||||||
|
PJM Capacity Performance ($/MWd) (a)
|
||||||||||||||||||||||||||
| MAAC | $ | 329.17 | $ | 269.92 | $ | 49.49 | $ | 49.49 | ||||||||||||||||||
| PPL | 329.17 | 269.92 | 49.49 | 49.49 | ||||||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
For the 2026/2027 PJM Capacity Year, the Company cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.
Seasonality/Scheduled Maintenance
The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.
Results of Operations
The results of operations presented below for the three and nine months ended September 30, 2025 and 2024, should be reviewed in conjunction with the Interim Financial Statements and Notes thereto.Our results of operations as reported in the Interim Financial Statements are prepared in accordance with GAAP.
In the explanations below, "Energy and other revenues" and "Fuel and energy purchases" are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. "Energy and other revenues" relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedges, Bitcoin revenue, and Nuclear PTC revenue. "Fuel and energy purchases" includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
Unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within "Operating Revenues" and expenses within "Energy Expenses." We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.
Results for the Three Months Ended September 30, 2025 and 2024
The following table and subsequent section display the results of operations:
| Three Months Ended September 30, |
Favorable (Unfavorable) Variance
|
|||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Capacity revenues | $ | 166 | $ | 50 | $ | 116 | ||||||||||||||
| Energy and other revenues | 604 | 505 | 99 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | 42 | 95 | (53) | |||||||||||||||||
| Operating Revenues (Note 3) | 812 | 650 | 162 | |||||||||||||||||
| Fuel and energy purchases | (259) | (222) | (37) | |||||||||||||||||
| Nuclear fuel amortization | (27) | (30) | 3 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (6) | 7 | (13) | |||||||||||||||||
| Energy Expenses | (292) | (245) | (47) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (131) | (127) | (4) | |||||||||||||||||
| General and administrative | (38) | (38) | - | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (61) | (75) | 14 | |||||||||||||||||
| Other operating income (expense), net | (27) | (7) | (20) | |||||||||||||||||
| Operating Income (Loss) | 263 | 158 | 105 | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | 81 | 67 | 14 | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (67) | (66) | (1) | |||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 25 | - | 25 | |||||||||||||||||
| Other non-operating income (expense), net | 2 | 20 | (18) | |||||||||||||||||
| Income (Loss) Before Income Taxes | 304 | 179 | 125 | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | (97) | (11) | (86) | |||||||||||||||||
| Net Income (Loss) | 207 | 168 | 39 | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | 207 | $ | 168 | $ | 39 | ||||||||||||||
Three Months Ended September 30, 2025 compared to Three Months Ended September 30, 2024
Net Income (Loss) Attributable to Stockholders increased by $39 million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses.$115 million favorable increase, primarily due to the following:
◦Capacity Revenues. $116 million favorable increase. This is primarily related to a $172 million increase due to higher cleared capacity prices though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by a $(56) million decrease due to lower volumes cleared though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $62 million favorable increase. This is primarily related to the combined effects of: (i) $118 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet, and higher generation volumes at our PJM fossil fleet, coupled with (ii) $36 million increase in realized hedge results. Such amounts are partially offset by a $(92) million decrease in digital revenue and Nuclear PTC revenue.
◦Unrealized Gain (Loss) on Derivative Instruments, net. $(66) million unfavorable decrease. This is primarily related to unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
•Gain (Loss) on Sale of Assets, net. $25 million favorable increase. This is primarily related to a $22 million gain on sale of the Camden and Dartmouth facilities in September 2025.
•Income Tax Benefit (Expense).$(86) million unfavorable increase. This is primarily related to an increase in pre-tax income for the three months ended September 30, 2025, and the absence of a change in the Company's valuation allowance that occurred in 2024.
Results for the Nine Months Ended September 30, 2025 and 2024
The following table and subsequent sections display the results of operations:
| Nine Months Ended September 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Capacity revenues | $ | 303 | $ | 141 | $ | 162 | ||||||||||||||
| Energy and other revenues | 1,552 | 1,444 | 108 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (23) | 63 | (86) | |||||||||||||||||
| Operating Revenues (Note 3) | 1,832 | 1,648 | 184 | |||||||||||||||||
| Fuel and energy purchases | (677) | (535) | (142) | |||||||||||||||||
| Nuclear fuel amortization | (71) | (93) | 22 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (31) | (5) | (26) | |||||||||||||||||
| Energy Expenses | (779) | (633) | (146) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (469) | (445) | (24) | |||||||||||||||||
| General and administrative | (113) | (121) | 8 | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (205) | (225) | 20 | |||||||||||||||||
| Other operating income (expense), net | (43) | (14) | (29) | |||||||||||||||||
| Operating Income (Loss) | 223 | 210 | 13 | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | 149 | 169 | (20) | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (203) | (187) | (16) | |||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 36 | 885 | (849) | |||||||||||||||||
| Other non-operating income (expense), net | 9 | 60 | (51) | |||||||||||||||||
| Income (Loss) Before Income Taxes | 214 | 1,137 | (923) | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | (70) | (192) | 122 | |||||||||||||||||
| Net Income (Loss) | 144 | 945 | (801) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | - | 29 | 29 | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | 144 | $ | 916 | $ | (772) | ||||||||||||||
Nine Months Ended September 30, 2025 compared to Nine Months Ended September 30, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(772) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses.$38 million favorable increase, primarily due to the following:
◦Capacity Revenues. $162 million favorable increase. This is primarily related to a $246 million increase due to higher cleared capacity prices through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by $(84) million decrease due to lower volumes cleared through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $(34) million unfavorable decrease. This is primarily related to the combined effects of: (i) $(235) million decrease in digital revenue and Nuclear PTC revenue, coupled with (ii) $(112) million decrease in realized hedge results. Such amounts are partially offset by $313 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet.
◦Unrealized Gain (Loss) on Derivative Instruments, net. $(112) million unfavorable decrease. This is primarily driven by $(84) million lower volume of hedge positions executed in the current period and $(27) million unrealized losses from the settlement of previously recognized mark-to-market liabilities.
•Nuclear Fuel Amortization.$22 million favorable decrease. This is primarily related to a $16 million decrease in the amortization of intangible assets related to certain nuclear fuel supply contracts which have expired.
•Operation, Maintenance and Development.$(24) million unfavorable increase. This is primarily due to incremental maintenance at Susquehanna performed during its planned refueling outage on Unit 2 in Spring 2025.
•Other Operating Income (Expense), net.$(29) million unfavorable decrease. This is primarily related to the loss resulting from the sale of Nuclear PTCs and noncash charges associated with miscellaneous assets.
•Gain (Loss) on Sale of Assets, net.$(849) million unfavorable decrease. This primarily consisted of a: (i) $564 million gain from the ERCOT Sale that closed in the second quarter 2024; (ii) $324 million gain from the AWS Data Campus Sale in the first quarter 2024; and (iii) a $22 million gain from the sale of the Camden and Dartmouth in September 2025. See Note 17 to the Interim Financial Statements for additional information.
•Other Non-Operating Income (Expense), net. $(51) million unfavorable decrease. This primarily consisted of interest income on cash deposits earned in 2024.
•Income Tax Benefit (Expense).$122 million favorable decrease. This is primarily due to a decrease in pre-tax income for the nine months ended September 30, 2025, and the absence of a change in the Company's valuation allowance that occurred in 2024.
•Net Income Attributable to Noncontrolling Interest.$29 million favorable decrease. This is related to the purchase of the remaining noncontrolling interests in Cumulus Digital in the fourth quarter 2024.
Liquidity and Capital Resources
Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our hedging activities including cash collateral and other forms of credit support; (v) the settlement of, or forms of credit in support of, legacy asset retirement and (or) environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.
Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.
Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, the stability provided by contracted cash flows associated with long-term PPAs as well as the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) lower our overall hedging requirements.
We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.
See the following Notes to the Interim Financial Statements for additional information on liquidity topics discussed below: Note 2 for derivatives and hedging, Note 8 for AROs and environmental obligations, Note 10 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.
Liquidity and Letter of Credit Capacity
|
September 30, 2025 |
December 31, 2024 |
|||||||||||||
| Cash and cash equivalents, unrestricted | $ | 497 | $ | 328 | ||||||||||
|
Unutilized RCF capacity (a)
|
700 | 700 | ||||||||||||
|
Total available liquidity
|
$ | 1,197 | $ | 1,028 | ||||||||||
|
Additional unutilized LC capacity (b)
|
$ | 465 | $ | 526 | ||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
(b)Excludes LC capacity available under the RCF and includes LC capacity under the LCF.
In October 2025, TES received commitments to (i) increase its existing RCF (including its revolving LC capacity) from $700 million to $900 million and (ii) upsize its existing $900 million LCF to $1.1 billion and extend the maturity from December 2026 to December 2027, in each case effective upon the closing of either the Freedom Acquisition or the Guernsey Acquisition (whichever closes first). See Note 10 to the Interim Financial Statements for additional information.
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, 2025 |
December 31, 2024 |
|||||||||||||
| Outstanding surety bonds | $ | 232 | $ | 234 | ||||||||||
In May 2025, the Company elected to replace a surety provider and, as of September 30, 2025, the replacement surety bonds issued by the new provider were outstanding. However, an aggregate $10 million of replaced surety bonds (included in the total above) continued to be outstanding as their release was not yet completed as of September 30, 2025.
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.
| 2025 | 2026 | |||||||||||||
| Nuclear fuel | $ | 104 | $ | 122 | ||||||||||
| PJM nuclear generation facility | 40 | 53 | ||||||||||||
| PJM fossil generation facilities | 41 | 77 | ||||||||||||
| Other | 15 | 25 | ||||||||||||
|
Total (a)
|
$ | 200 | $ | 277 | ||||||||||
__________________
(a)Expected capitalized interest on capital expenditures is a non-material amount in 2025 and 2026.
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
| Nine Months Ended September 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Operating activities | $ | 424 | $ | 246 | $ | 178 | ||||||||||||||
| Investing activities | (156) | 1,225 | (1,381) | |||||||||||||||||
| Financing activities | (136) | (1,240) | 1,104 | |||||||||||||||||
Operating activities
A change of $178 million in net cash provided by (used in) operating activities is generally aligned with results from operations combined with working capital changes in the normal course of business. See "-Results of Operations" for additional information.
Investing activities
A change of $(1,381) million in net cash provided by (used in) investing activities was primarily due to: (i) $(635) million in proceeds from the AWS Data Campus Sale in 2024; and (ii) $(763) million of proceeds from the ERCOT Sale in 2024. See Note 17 to the Interim Financial Statements for additional information on the AWS Data Campus Sale and the ERCOT Sale.
Financing activities
A change of $1,104 million in net cash provided by (used in) financing activities is primarily the result of the combined effect of the: (i) $182 million repayment of the Cumulus Digital TLF; (ii) $39 million purchase of noncontrolling interest in Cumulus Digital, both in the first quarter 2024; and (iii) a $853 million decrease in share repurchases.
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. Pursuant to TES's debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company's operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.
The following table presents a reconciliation of the GAAP financial measure of "Net Income (Loss)" presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:
| Three Months Ended September 30, | Nine Months Ended September 30, | |||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Net Income (Loss) | $ | 207 | $ | 168 | $ | 144 | $ | 945 | ||||||||||||||||||
| Adjustments | ||||||||||||||||||||||||||
| Interest expense and other finance charges | 67 | 66 | 203 | 187 | ||||||||||||||||||||||
| Income tax (benefit) expense | 97 | 11 | 70 | 192 | ||||||||||||||||||||||
|
Depreciation, amortization and accretion
|
61 | 75 | 205 | 225 | ||||||||||||||||||||||
| Nuclear fuel amortization | 27 | 30 | 71 | 93 | ||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | (36) | (102) | 54 | (58) | ||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | (81) | (67) | (149) | (169) | ||||||||||||||||||||||
| Stock-based and other long-term incentive compensation expense | 18 | 11 | 49 | 43 | ||||||||||||||||||||||
|
(Gain) loss on asset sales, net(a)
|
(25) | - | (36) | (885) | ||||||||||||||||||||||
| Operational and other restructuring activities | 14 | 40 | 23 | 61 | ||||||||||||||||||||||
| Noncontrolling interest | - | (3) | - | (21) | ||||||||||||||||||||||
| Other | 14 | 1 | 19 | (7) | ||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 363 | $ | 230 | $ | 653 | $ | 606 | ||||||||||||||||||
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(a)See Note 17 to the Interim Financial Statements for additional information.
Critical Accounting Policies and Estimates
The Company's financial statements are prepared in conformity with GAAP, which requires the application of appropriate accounting policies to form the basis of estimates utilizing methods, judgments, and (or) assumptions that materially affect: (i) the measurement and carrying values of assets and liabilities as of the date of the financial statements; (ii) the revenues recognized and expenses incurred during the presented reporting periods; and (iii) financial statement disclosures of commitments, contingencies, and other significant matters. Such judgments and assumptions may include significant subjectivity due to inherent uncertainties of future events which exist to such an extent that there is a reasonable likelihood that materially different amounts would have been reported under different conditions or if different assumptions had been used. See our 2024 Annual Report for a description of our significant accounting policies and estimates.
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