Talen Energy Corporation
05/05/2026 | Press release | Distributed by Public on 05/05/2026 15:11
Quarterly Report for Quarter Ending March 31, 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
Financing Transactions
Unsecured Notes due 2031 and 2033. In April 2026, TES issued in private placement transactions not involving a public offering: (i) $1.5 billion in aggregate principal amount of 6.125% Senior Unsecured Notes due 2031; and (ii) $2.5 billion in aggregate principal amount of 6.375% Senior Unsecured Notes due 2033. We intend to use the net proceeds from the issuance and sale of the Unsecured Notes due 2031 and 2033 to fund: (i) the previously announced Cornerstone Acquisition and (ii) the redemption in full of the Company's outstanding Secured Notes.
Secured Notes. In April 2026, using a portion of the net proceeds of the Unsecured Notes due 2031 and 2033, TES redeemed in full, the Company's outstanding Secured Notes in aggregate principal amount of $1.2 billion.
Credit Facility Transactions. In April 2026, TES also undertook the following financing transactions that are expected to become effective concurrently with the closing of the Cornerstone Acquisition: (i) received commitments to increase its existing RCF (including its revolving LC capacity) from $900 million to $1.35 billion; and (ii) received commitments to upsize its existing $1.1 billion LCF to $1.5 billion and extend the maturity from December 2027 to December 2029.
See Notes 10 and 17 to the Interim Financial Statements for additional information on the financing transactions and the Cornerstone Acquisition.
Common Stock Repurchases
During the three months ended March 31, 2026, we repurchased and retired 300,000 shares of TEC's outstanding common stock under the SRP. The aggregate purchase price, including transaction fees and excise tax, was $101 million at a weighted average price of $336.42 per share. As of March 31, 2026, the remaining capacity under the SRP is $1.9 billion through 2028. See Note 15 to the Interim Financial Statements for additional information on the SRP.
Cornerstone Acquisition
In January 2026, we entered into the Cornerstone Merger Agreement to acquire from affiliates of Energy Capital Partners ("ECP") the 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana, for an aggregate purchase price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of TEC common stock, valued at approximately $900 million at the time of the entry into the Cornerstone Merger Agreement. The final value of the equity portion of the transaction price will be based on the value of TEC common stock at the close of the transaction. The cash portion of the purchase price will be funded from the proceeds of the Unsecured Notes due 2031 and 2033 which were issued in April 2026. The stock consideration will be subject to lock-ups of 90 days on 50% of the stock consideration and 180 days on the remaining stock consideration.
The addition of these assets to Talen's portfolio will increase generation capacity by approximately 2.5 GW of natural gas generation, substantially expanding Talen's presence in the western PJM market and adding additional efficient baseload generation assets to its fleet.
At the closing of the Cornerstone Acquisition, the Company intends to enter into the Cornerstone RRA with certain parties, under which it will use commercially reasonable efforts to file a registration statement on Form S-3 with the SEC to register the TEC common stock to be issued pursuant to the Cornerstone Merger Agreement within three business days (and in any event within five business days) after issuance.
The proposed Cornerstone Acquisition is subject to regulatory approvals and the satisfaction of other customary closing conditions, and is expected to close early in the second half of 2026.
See Note 17 to the Interim Financial Statements for additional information on the Cornerstone Acquisition and "Item 1A. Risk Factors-Risks Related to the Cornerstone Acquisition" of our 2025 Annual Report for a discussion of the associated risks.
The foregoing description of the Cornerstone Merger Agreement and the transaction 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 Cornerstone Merger Agreement, a copy of which is incorporated by reference as Exhibit 2.1 to our 2025 Annual Report. The Cornerstone Merger Agreement was 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 Cornerstone Merger Agreement, which may be subject to important limitations and qualifications, and which may change after the date of the Cornerstone Merger Agreement, 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," "Item 1A. Risk Factors," and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.
Commodity Markets
During the first quarter 2026, PJM experienced weather-related volatility as extreme temperatures over certain days contributed to increased load demand, resulting in higher settled on-peak power prices. Additionally, TETCO M-3 natural gas prices settled higher in the period due to the effect of increased electric demand resulting from the extreme temperature days in PJM driving natural gas prices to historic highs on those days. Natural gas storage levels during the quarter were near the 5-year average.
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended March 31, were:
| 2026 | 2025 | |||||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 102.98 | $ | 60.50 | ||||||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 86.95 | 53.87 | ||||||||||||
| PJM AEP-D Hub Day Ahead Peak - $/MWh | 74.81 | 53.40 | ||||||||||||
| TETCO M-3 - $/MMBtu | 9.61 | 6.42 | ||||||||||||
The weighted average forward market prices for the periods from April 1 through December 31 as of March 31, were:
| 2026 | 2025 | |||||||||||||
| PJM West Hub ATC - $/MWh | $ | 57.85 | $ | 53.87 | ||||||||||
|
PJM West Hub ATC Spark Spreads - $/MWh (a)
|
37.92 | 27.30 | ||||||||||||
| TETCO M-3 - $/MMBtu | 2.85 | 3.80 | ||||||||||||
__________________
(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.
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.
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 2027/2028 PJM Capacity Year was held in December 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:
| 2027/2028 | 2026/2027 | 2025/2026 | 2024/2025 | 2023/2024 | ||||||||||||||||||||||||||||
|
PJM Capacity Performance ($/MWd) (a)
|
||||||||||||||||||||||||||||||||
| MAAC | $ | 333.44 | $ | 329.17 | $ | 269.92 | $ | 49.49 | $ | 49.49 | ||||||||||||||||||||||
| PPL | 333.44 | 329.17 | 269.92 | 49.49 | 49.49 | |||||||||||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
For the 2027/2028 PJM Capacity Year, the Company cleared 8,745 MW at a price of $333.44/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.
Susquehanna commenced its planned refueling outage on Unit 1 on March 23, 2026. We expect similar incremental maintenance activities that were performed on Unit 2 in 2025 to be performed during this outage on Unit 1, and anticipate the completion of the work in the first half of May 2026.
Results of Operations
The results of operations presented below are prepared in accordance with GAAP and should be reviewed in conjunction with the Interim Financial Statements and the related Notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the three months ended March 31, 2026, compared to the three months ended March 31, 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 March 31, 2026 and 2025
| Three Months Ended March 31, |
Favorable (Unfavorable) Variance
|
|||||||||||||||||||
| 2026 | 2025 | |||||||||||||||||||
| Energy and other revenues | $ | 1,034 | $ | 582 | $ | 452 | ||||||||||||||
| Capacity revenues | 207 | 49 | 158 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (112) | (241) | 129 | |||||||||||||||||
| Operating Revenues (Note 3) | 1,129 | 390 | 739 | |||||||||||||||||
| Fuel and energy purchases | (563) | (268) | (295) | |||||||||||||||||
| Nuclear fuel amortization | (24) | (26) | 2 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments (Note 2) | (42) | 59 | (101) | |||||||||||||||||
| Energy Expenses | (629) | (235) | (394) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (165) | (146) | (19) | |||||||||||||||||
| General and administrative | (24) | (34) | 10 | |||||||||||||||||
| Depreciation, amortization and accretion (Note 7) | (92) | (74) | (18) | |||||||||||||||||
| Other operating income (expense), net | (9) | (7) | (2) | |||||||||||||||||
| Operating Income (Loss) | 210 | (106) | 316 | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net (Note 6) | (22) | (12) | (10) | |||||||||||||||||
| Interest expense and other finance charges (Note 10) | (119) | (74) | (45) | |||||||||||||||||
| Other non-operating income (expense), net | 12 | 5 | 7 | |||||||||||||||||
| Income (Loss) Before Income Taxes | 81 | (187) | 268 | |||||||||||||||||
| Income tax benefit (expense) (Note 4) | (18) | 52 | (70) | |||||||||||||||||
| Net Income (Loss) | $ | 63 | $ | (135) | $ | 198 | ||||||||||||||
Three Months Ended March 31, 2026 compared to Three Months Ended March 31, 2025
Net Income (Loss) increased by $198 million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $345 million favorable increase, primarily due to the following:
◦Energy and Other Revenues, net of Fuel and Energy Purchases. $157 million favorable increase. This is primarily related to the combined effects of: (i) $432 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 (ii) higher generation volumes at Freedom and Guernsey. Such amounts are partially offset by $(271) million decrease in realized hedge results.
◦Capacity Revenues. $158 million favorable increase. This is primarily driven by higher cleared capacity prices, partially offset by lower volumes cleared through the 2025/2026 PJM BRA compared to the 2024/2025 PJM BRA.
◦Unrealized Gain (Loss) on Derivative Instruments, net. $28 million favorable increase. This is primarily related to the combined effects of: (i) $142 million increase due to the reversal of positions previously recognized as mark-to-market liabilities which settled during the period, partially offset by $(114) million decrease in net short power positions resulting from higher forward power prices.
•Interest Expense and Other Finance Charges. $(45) million unfavorable increase. This primarily consisted of: (i) a $(60) million increase in cash interest expense on the TLB-3 and Unsecured Notes due 2034 and 2036, each issued in October 2025 in connection with the Freedom and Guernsey Acquisitions, offset by (ii) a $15 million decrease in non-cash interest expense resulting from changes in unrealized positions on interest rate swaps.
•Income Tax Benefit (Expense). $(70) million unfavorable increase. This is primarily related to an increase in pre-tax income for the three months ended March 31, 2026.
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 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
|
March 31, 2026 |
December 31, 2025 |
|||||||||||||
| Cash and cash equivalents, unrestricted | $ | 1,025 | $ | 689 | ||||||||||
|
Unutilized RCF capacity (a)
|
900 | 900 | ||||||||||||
|
Total available liquidity
|
$ | 1,925 | $ | 1,589 | ||||||||||
|
Additional unutilized LC capacity (b)
|
$ | 655 | $ | 652 | ||||||||||
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
(b)Includes LC capacity under the LCF and excludes LC capacity available under the RCF.
Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 10 to the Interim Financial Statements for additional information on the RCF and LCF.
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.
|
March 31, 2026 |
December 31, 2025 |
|||||||||||||
| Outstanding surety bonds | $ | 211 | $ | 228 | ||||||||||
Cash Flow Activities
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
| Three Months Ended March 31, | Favorable (Unfavorable) Variance | |||||||||||||||||||
| 2026 | 2025 | |||||||||||||||||||
| Operating activities | $ | 461 | $ | 119 | $ | 342 | ||||||||||||||
| Investing activities | (72) | (68) | (4) | |||||||||||||||||
| Financing activities | (114) | (96) | (18) | |||||||||||||||||
Operating activities
A change of $342 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 $(4) million in net cash provided by (used in) investing activities was primarily due to normal course of business activity related to NDT fund investment sales and purchases, and capital expenditures.
Financing activities
A change of $(18) million in net cash provided by (used in) financing activities was primarily due to normal course of business activity related to debt repayments, RCF borrowing and repayments, and 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.
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 March 31, | ||||||||||||||
| (Millions of Dollars) | 2026 | 2025 | ||||||||||||
| Net Income (Loss) | $ | 63 | $ | (135) | ||||||||||
| Adjustments | ||||||||||||||
| Interest expense and other finance charges | 119 | 74 | ||||||||||||
| Income tax (benefit) expense | 18 | (52) | ||||||||||||
|
Depreciation, amortization and accretion (a)
|
63 | 70 | ||||||||||||
|
Nuclear fuel amortization (a)
|
24 | 26 | ||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 154 | 182 | ||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | 22 | 12 | ||||||||||||
|
Stock-based and other long-term incentive compensation expense
|
2 | 13 | ||||||||||||
|
Acquisition and divestiture activities (b)
|
1 | 7 | ||||||||||||
|
Operational and other restructuring activities (c)
|
9 | 2 | ||||||||||||
| Other | (2) | 1 | ||||||||||||
| Total Adjusted EBITDA | $ | 473 | $ | 200 | ||||||||||
__________________
(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.
(c)Non-recurring severance and retention costs and strategic initiative costs.
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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