Talen Energy Corporation
08/07/2025 | Press release | Distributed by Public on 08/07/2025 07:01
Quarterly Report for Quarter Ending June 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
PJM 2026/2027 Base Residual Auction
In July 2025, PJM announced the results of the 2026/2027 PJM BRA. Talen cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.
See "-Factors Affecting Our Financial Condition and Results of Operations-Capacity Markets" for additional information.
Freedom and Guernsey Acquisitions
In July 2025, we entered into definitive agreements to acquire Caithness Energy's 1,045 MW (summer rating) Freedom Energy Center in Pennsylvania and 1,836 MW (summer rating) Guernsey Power Station in Ohio, both gas fired combined cycle plants located within the PJM power market, for an aggregate gross purchase price of approximately $3.8 billion (subject to working capital and other customary adjustments), or $3.5 billion after adjusting for estimated tax benefits. We expect to issue approximately $3.8 billion in new debt to fund the Freedom and Guernsey Acquisitions.
The addition of these assets to Talen's portfolio will increase our generating capacity by approximately 3 GW and is expected to enhance our ability to offer reliable, scalable, grid-supported, and regionally diverse low-carbon capacity to hyperscale data centers and other large commercial off-takers. Additionally, as these facilities have an average heat rate of 6,550 Btu/kWh, the Freedom and Guernsey Acquisitions will provide the Company with incremental baseload generation and cash flow diversification. The presence of these facilities in the PJM market complements our existing commercial and marketing capabilities, and their strategic location adjacent to the Marcellus and Utica shale formations provides ample natural gas supplies and reliable access to natural gas pipeline infrastructure and interconnects.
The transactions are subject to regulatory approvals and the satisfaction of other customary closing conditions, and are both expected to close in the fourth quarter 2025. The relevant regulatory filings have all been made and are now pending at the agencies.
See Note 17 to the Interim Financial Statements for additional information on the Freedom and Guernsey Acquisitions and "Part II, Item 1A. Risk Factors" of this Report for a discussion of the associated risks.
The foregoing description of the Purchase Agreements and the transactions contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Purchase Agreements, copies of which are attached as Exhibits 2.1 and 2.2 to this Report. The Purchase Agreements are being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Purchase Agreements, which may be subject to important limitations and qualifications, and which may change after the date of the Purchase Agreements, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.
Expanded AWS PPA
In June 2025, we entered into a new retail PPA agreement with AWS, expanding, and eventually replacing, the existing AWS PPA. The existing Susquehanna co-located load arrangement between Talen and AWS will transition to a "front-of-the-meter" arrangement after the completion of transmission reconfiguration projects expected to occur in Spring 2026, concurrent with Susquehanna's annual refueling outage. Under the terms of the revised AWS PPA, Talen Energy Marketing will act as the retail electric generation supplier to AWS and PPL Electric Utilities will be responsible for transmission and delivery. At the full contract quantity, AWS is expected to receive 1,920 MW of power through 2042 for operations that support AI and other cloud technologies at the AWS Data Campus. The power delivery schedule will ramp over time, expecting to achieve the full volume no later than 2032. Talen and AWS will also explore building small modular reactors within Talen's Pennsylvania footprint and pursue expanding Susquehanna's energy output through uprates, with the intent to add net-new energy to the PJM grid.
Camden and Dartmouth Sales
In June 2025, we entered into a purchase and sale agreement to sell the Camden and Dartmouth generation facilities for an aggregate $32 million in cash, subject to customary working capital adjustments and an economic effective date of June 1, 2025. FERC approval for the sale was received in August 2025 and the transaction is expected to close in the second half of 2025.
See Note 17 to the Interim Financial Statements for additional information.
RMR Arrangements
In May 2025, the FERC approved the terms under which Talen will operate Brandon Shores and H.A. Wagner until May 31, 2029, beyond their previously-scheduled May 31, 2025 retirement dates. Under the RMR agreement, Brandon Shores Units 1 and 2 and H.A. Wagner Units 3 and 4 will remain in service and provide power necessary to maintain grid and transmission reliability in and around the City of Baltimore until transmission upgrades to provide reliable power to the area from other sources are complete. Beginning June 1, 2025, we expect to receive $145 million annually for Brandon Shores and $35 million for H.A. Wagner, inclusive of some performance incentives.
See Note 7 to the Interim Financial Statements for additional information.
Factors Affecting Our Financial Condition and Results of Operations
Earnings in future periods are subject to various uncertainties and risks. See "Cautionary Note Regarding Forward-Looking Information," the sections entitled "Item 1A. Risk Factors" in this Report and our 2024 Annual Report, as updated by our March 31, 2025 Quarterly Report, and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the second quarter 2025, natural gas prices for Texas Eastern M-3 settled at the ten-year average as natural gas storage levels climbed above the five-year average. In PJM, above average temperatures during June contributed to increased load demand that resulted in higher settled on-peak power prices compared with the prior year.
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the three months ended June 30, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 52.71 | $ | 37.67 | ||||||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 40.91 | 28.34 | ||||||||||||
| Texas Eastern M-3 - $/MMBtu | 2.47 | 1.53 | ||||||||||||
The weighted average forward market prices for the periods from July 1 through December 31 as of June 30, were:
| 2025 | 2024 | |||||||||||||
| PJM West Hub ATC - $/MWh | $ | 49.52 | $ | 43.64 | ||||||||||
| Texas Eastern M-3 - $/MMBtu | 2.95 | 2.14 | ||||||||||||
|
PJM West Hub ATC Spark Spreads - $/MWh (a)
|
28.86 | 28.64 | ||||||||||||
__________________
(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, Texas Eastern M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Capacity Markets
Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.
PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.
Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2026/2027 PJM Capacity Year was held on July 22, 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 9 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.
Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:
| 2026/2027 | 2025/2026 | 2024/2025 | 2023/2024 | |||||||||||||||||||||||
|
PJM Capacity Performance ($/MWd) (a)
|
||||||||||||||||||||||||||
| MAAC | $ | 329.17 | $ | 269.92 | $ | 49.49 | $ | 49.49 | ||||||||||||||||||
| PPL | 329.17 | 269.92 | 49.49 | 49.49 | ||||||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
For the 2026/2027 PJM Capacity Year, the Company cleared 6,702 MWs at a price of $329.17/MWd for the MAAC, PPL, and PSEG locational deliverability areas.
Nuclear Production Tax Credit
The Inflation Reduction Act was signed into law in August 2022. Among the Act's provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. See Note 3 to the Interim Financial Statements for additional information on Nuclear PTC revenue recognized.
Seasonality/Scheduled Maintenance
The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.
On March 25, 2025, Susquehanna commenced its planned refueling outage on Unit 2. During the outage, we identified incremental maintenance in the non-nuclear portion of the Unit. As a prudent operator, we elected to complete this scope of work while Unit 2 was already in outage and market prices and demand were relatively low. The outage was completed on June 4, 2025. The incremental maintenance investment during the extended outage was comprised of approximately $25 million in operations and maintenance expenses and $6 million of capital expenditures. We expect similar incremental maintenance activities on Unit 1 to be performed during Susquehanna's Spring 2026 planned outage. While the scope of work and outage schedule has not yet been finalized, we expect our planning activities with respect to the Unit 1 incremental work to result in an outage of shorter duration than the Unit 2 outage as well as for the Unit 1 incremental maintenance costs to be in line with or below the Unit 2 costs.
Results of Operations
The results of operations presented below for the three and six months ended June 30, 2025 and 2024, should be reviewed in conjunction with the Interim Financial Statements and Notes thereto.Our results of operations as reported in the Interim Financial Statements are prepared in accordance with GAAP.
In the explanations below, "Energy and other revenues" and "Fuel and energy purchases" are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. "Energy and other revenues" relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedges, Bitcoin revenue, and Nuclear PTC revenue. "Fuel and energy purchases" includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.
Unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within "Operating Revenues" and expenses within "Energy Expenses." We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.
Results for the Three Months Ended June 30, 2025 and 2024
The following table and subsequent section display the results of operations:
| Three Months Ended June 30, |
Favorable (Unfavorable) Variance
|
|||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Capacity revenues | $ | 88 | $ | 46 | $ | 42 | ||||||||||||||
| Energy and other revenues | 366 | 367 | (1) | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | 176 | 76 | 100 | |||||||||||||||||
| Operating Revenues (Note 3) | 630 | 489 | 141 | |||||||||||||||||
| Fuel and energy purchases | (150) | (163) | 13 | |||||||||||||||||
| Nuclear fuel amortization | (18) | (28) | 10 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (84) | 15 | (99) | |||||||||||||||||
| Energy Expenses | (252) | (176) | (76) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (192) | (164) | (28) | |||||||||||||||||
| General and administrative | (41) | (40) | (1) | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (70) | (75) | 5 | |||||||||||||||||
| Other operating income (expense), net | (9) | (7) | (2) | |||||||||||||||||
| Operating Income (Loss) | 66 | 27 | 39 | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | 80 | 27 | 53 | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (62) | (62) | - | |||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 9 | 561 | (552) | |||||||||||||||||
| Other non-operating income (expense), net | 4 | 17 | (13) | |||||||||||||||||
| Income (Loss) Before Income Taxes | 97 | 570 | (473) | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | (25) | (112) | 87 | |||||||||||||||||
| Net Income (Loss) | 72 | 458 | (386) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | - | 4 | 4 | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | 72 | $ | 454 | $ | (382) | ||||||||||||||
Three Months Ended June 30, 2025 compared to Three Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(382) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses.$65 million favorable increase, primarily due to the following:
◦Capacity Revenues. $42 million favorable increase. This is primarily related to a $60 million increase due to higher cleared capacity prices though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by an $(18) million decrease due to lower volumes cleared though the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $12 million favorable increase. This is primarily related to the combined effects of: (i) $70 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet, partially offset by lower generation volumes at Susquehanna and lower ancillary revenues; and (ii) $10 million increase in realized hedge results. Such amounts are partially offset by a $(68) million decrease in digital revenue and Nuclear PTC revenue.
•Operation, Maintenance and Development.$(28) million unfavorable increase. This is primarily due to incremental maintenance at Susquehanna performed during its planned refueling outage on Unit 2 in Spring 2025.
•Nuclear Decommissioning Trust Funds Gain (Loss), net.$53 million favorable increase. This is primarily due to the combined effect of: (i) $61 million increase in the unrealized value of equity securities in the second quarter 2025 compared with a $17 million increase in the second quarter 2024; and (ii) $8 million increase in realized activity in the second quarter 2025. See Notes 6 and 11 to the Interim Financial Statements for additional information.
•Gain (Loss) on Sale of Assets, net.$(552) million unfavorable decrease. This is primarily related to the ERCOT Sale that closed in the second quarter 2024. See Note 17 to the Interim Financial Statements for additional information.
•Income Tax Benefit (Expense).$87 million favorable decrease. This is primarily due to a decrease in pre-tax income in the second quarter 2025 as compared to the second quarter 2024.
Results for the Six Months Ended June 30, 2025 and 2024
The following table and subsequent sections display the results of operations:
| Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Capacity revenues | $ | 137 | $ | 91 | $ | 46 | ||||||||||||||
| Energy and other revenues | 948 | 939 | 9 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (65) | (32) | (33) | |||||||||||||||||
| Operating Revenues (Note 3) | 1,020 | 998 | 22 | |||||||||||||||||
| Fuel and energy purchases | (418) | (313) | (105) | |||||||||||||||||
| Nuclear fuel amortization | (44) | (63) | 19 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (25) | (12) | (13) | |||||||||||||||||
| Energy Expenses | (487) | (388) | (99) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (338) | (318) | (20) | |||||||||||||||||
| General and administrative | (75) | (83) | 8 | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (144) | (150) | 6 | |||||||||||||||||
| Other operating income (expense), net | (16) | (7) | (9) | |||||||||||||||||
| Operating Income (Loss) | (40) | 52 | (92) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | 68 | 102 | (34) | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (136) | (121) | (15) | |||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 11 | 885 | (874) | |||||||||||||||||
| Other non-operating income (expense), net | 7 | 40 | (33) | |||||||||||||||||
| Income (Loss) Before Income Taxes | (90) | 958 | (1,048) | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | 27 | (181) | 208 | |||||||||||||||||
| Net Income (Loss) | (63) | 777 | (840) | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | - | 29 | 29 | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders | $ | (63) | $ | 748 | $ | (811) | ||||||||||||||
Six Months Ended June 30, 2025 compared to Six Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders decreased by $(811) million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses.$(77) million unfavorable decrease, primarily due to the following:
◦Capacity Revenues. $46 million favorable increase. This is primarily related to a $63 million increase due to higher cleared capacity prices through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year, partially offset by $(17) million decrease due to lower volumes cleared through the PJM BRA for the 2025/2026 PJM Capacity Year compared to the 2024/2025 PJM Capacity Year.
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $(96) million unfavorable decrease. This is primarily related to the combined effects of: (i) $(152) million decrease in realized hedge results; and (ii) $(143) million decrease in digital revenue and Nuclear PTC revenue. Such amounts are partially offset by a $199 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices received at Susquehanna and our PJM fossil fleet and higher generation volumes at our PJM fossil fleet, partially offset by lower generation volumes at Susquehanna.
◦Unrealized Gain (Loss) on Derivative Instruments, net. $(46) million unfavorable decrease. This is primarily related to the combined effect of $(85) million associated with lower volume of hedge positions executed during current period as compared to hedge positions executed in the prior period, partially offset by $40 million of unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
•Operation, Maintenance and Development.$(20) million unfavorable increase. This is primarily due to incremental maintenance at Susquehanna performed during its planned refueling outage on Unit 2 in Spring 2025.
•Nuclear Decommissioning Trust Funds Gain (Loss), net. $(34) million unfavorable decrease. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 6 and 11 to the Interim Financial Statements for additional information.
•Gain (Loss) on Sale of Assets, net.$(874) million unfavorable decrease. This primarily consists of a: (i) $563 million gain from the ERCOT Sale that closed in the second quarter 2024; and (ii) $324 million gain from the AWS Data Campus Sale in the first quarter 2024. See Note 17 to the Interim Financial Statements for additional information.
•Other Non-Operating Income (Expense), net. $(33) million unfavorable decrease. This primarily consisted of interest income on cash deposits.
•Income Tax Benefit (Expense).$208 million favorable decrease. This is primarily due to a decrease in pre-tax income for the six months ended June 30, 2025 as compared to 2024.
•Net Income Attributable to Noncontrolling Interest.$29 million favorable decrease. This is related to the buyout of the remaining noncontrolling interest in Cumulus Digital in the fourth quarter 2024.
Liquidity and Capital Resources
Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our hedging activities including cash collateral and other forms of credit support; (v) the settlement of, or forms of credit in support of, legacy asset retirement and (or) environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.
Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.
Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, the stability provided by contracted cash flows associated with long-term PPAs as well as the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) lower our overall hedging requirements.
We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.
See the following Notes to the Interim Financial Statements for additional information on liquidity topics discussed below: Note 2 for derivatives and hedging, Note 8 for AROs and environmental obligations, Note 10 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.
Liquidity and Letter of Credit Capacity
|
June 30, 2025 |
December 31, 2024 |
|||||||||||||
| Cash and cash equivalents, unrestricted | $ | 122 | $ | 328 | ||||||||||
|
Unutilized RCF capacity (a)
|
630 | 700 | ||||||||||||
|
Total available liquidity
|
$ | 752 | $ | 1,028 | ||||||||||
|
Additional unutilized LC capacity (b)
|
$ | 487 | $ | 526 | ||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
(b)Excludes LC capacity available under the RCF and includes LC capacity under the LCF.
As of August 4, 2025, the unutilized RCF capacity was $700 million.
Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 10 to the Interim Financial Statements for additional information on the RCF and LCF.
Financial Performance Assurances
TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including but not limited to environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.
|
June 30, 2025 |
December 31, 2024 |
|||||||||||||
| Outstanding surety bonds | $ | 263 | $ | 234 | ||||||||||
In May 2025, the Company elected to replace a surety provider and, as of June 30, 2025, the replacement surety bonds issued by the new provider were outstanding. However, an aggregate $42 million of replaced surety bonds (included in the total above) continued to be outstanding as their release was not yet completed as of June 30, 2025.
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
| Six Months Ended June 30, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2025 | 2024 | |||||||||||||||||||
| Operating activities | $ | (65) | $ | 150 | $ | (215) | ||||||||||||||
| Investing activities | (114) | 979 | (1,093) | |||||||||||||||||
| Financing activities | (51) | (915) | 864 | |||||||||||||||||
Operating activities
A change of $(215) million in net cash provided by (used in) operating activities is generally aligned with results from operations combined with working capital changes in the normal course of business. See "-Results of Operations" for additional information.
Investing activities
A change of $(1,093) million in net cash provided by (used in) investing activities was primarily due to: (i) $(339) million in proceeds from the AWS Data Campus Sale in the first quarter 2024; and (ii) $(754) million of proceeds from the ERCOT Sale in the second quarter 2024. See Note 17 to the Interim Financial Statements for additional information on the AWS Data Campus Sale and the ERCOT Sale.
Financing activities
A change of $864 million in net cash provided by (used in) financing activities is primarily the result of the combined effect of the: (i) $182 million repayment of the Cumulus Digital TLF; (ii) $39 million purchase of noncontrolling interest in Cumulus Digital, both in the first quarter 2024; (iii) a $551 million decrease in share repurchases; and (iv) RCF borrowings of $70 million in the second quarter 2025.
Contractual Obligations and Commitments
Guarantees of Subsidiary Obligations
TES guarantees certain agreements and obligations for its subsidiaries. Certain agreements may contingently require payments to a guaranteed or indemnified party. See "Guarantees and Other Assurances" in Note 9 to the Interim Financial Statements for additional information regarding guarantees.
Non-GAAP Financial Measure
Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
Adjusted EBITDA
We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.
Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES's debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company's operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.
The following table presents a reconciliation of the GAAP financial measure of "Net Income (Loss)" presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:
| Three Months Ended June 30, | Six Months Ended June 30, | |||||||||||||||||||||||||
| (Millions of Dollars) | 2025 | 2024 | 2025 | 2024 | ||||||||||||||||||||||
| Net Income (Loss) | $ | 72 | $ | 458 | $ | (63) | $ | 777 | ||||||||||||||||||
| Adjustments | ||||||||||||||||||||||||||
| Interest expense and other finance charges | 62 | 62 | 136 | 121 | ||||||||||||||||||||||
| Income tax (benefit) expense | 25 | 112 | (27) | 181 | ||||||||||||||||||||||
|
Depreciation, amortization and accretion
|
70 | 75 | 144 | 150 | ||||||||||||||||||||||
| Nuclear fuel amortization | 18 | 28 | 44 | 63 | ||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | (92) | (91) | 90 | 44 | ||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | (80) | (27) | (68) | (102) | ||||||||||||||||||||||
| Stock-based and other long-term incentive compensation expense | 18 | 14 | 31 | 32 | ||||||||||||||||||||||
|
(Gain) loss on asset sales, net(a)
|
(9) | (561) | (11) | (885) | ||||||||||||||||||||||
| Operational and other restructuring activities | - | 19 | 9 | 21 | ||||||||||||||||||||||
| Noncontrolling interest | - | (7) | - | (18) | ||||||||||||||||||||||
| Other | 6 | 5 | 5 | (8) | ||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 90 | $ | 87 | $ | 290 | $ | 376 | ||||||||||||||||||
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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 the Annual Financial Statements for a description of our significant accounting policies and estimates.
Talen Energy Corporation published this content on August 07, 2025, and is solely responsible for the information contained herein. Distributed via SEC EDGAR on August 07, 2025 at 13:02 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]