| PROSPECTUS SUPPLEMENT NO. 1 | Filed pursuant to Rule 424(b)(3) | ||||
| (To prospectus dated July 9, 2024) | Registration No. 333-280341 | ||||
TALEN ENERGY CORPORATION
36,825,683 SHARES OF COMMON STOCK
This prospectus supplement is being filed to update and supplement the information contained in the prospectus dated July 9, 2024 (the “Prospectus”), with the information contained in our Quarterly Report on Form 10-Q filed with the Securities and Exchange Commission (the “SEC”) on August 13, 2024 (the “Quarterly Report”). Accordingly, we have attached the Quarterly Report to this prospectus supplement.
The Prospectus and this prospectus supplement relate to the resale from time to time of up to 36,825,683 shares of our common stock, par value $0.001 per share (the “Common Stock”), by the selling stockholders named in the Prospectus or their permitted transferees.
This prospectus supplement updates and supplements the information in the Prospectus and is not complete without, and may not be delivered or utilized except in combination with, the Prospectus, including any other amendments or supplements thereto. This prospectus supplement should be read in conjunction with the Prospectus, and if there is any inconsistency between the information in the Prospectus and this prospectus supplement, you should rely on the information in this prospectus supplement. The information in this prospectus supplement modifies and supersedes, in part, the information in the Prospectus. Any information in the Prospectus that is modified or superseded shall not be deemed to constitute a part of the Prospectus except as modified or superseded by this prospectus supplement.
You should not assume that the information provided in this prospectus supplement or the Prospectus is accurate as of any date other than their respective dates. Neither the delivery of this prospectus supplement and Prospectus, nor any sale made hereunder, shall under any circumstances create any implication that there has been no change in our affairs since the date of this prospectus supplement or that the information contained in this prospectus supplement or the Prospectus is correct as of any time after the date of that information.
The Common Stock is listed on The Nasdaq Global Select Market (“Nasdaq”) under the symbol “TLN”. On August 12, 2023, the last sale price of the Common Stock as reported on Nasdaq was $119.76 per share.
Investing in our securities involves certain risks, including those that are described in the section titled “Risk Factors” beginning on page 19 of the Prospectus.
Neither the SEC nor any state securities commission has approved or disapproved of the securities to be issued under the Prospectus or determined if the Prospectus or this prospectus supplement is truthful or complete. Any representation to the contrary is a criminal offense.
The date of this prospectus supplement is August 13, 2024.
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
(Mark One)
| ☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the quarterly period ended June 30, 2024
OR
| ☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 | ||||
For the transition period from __________ to __________
Commission File Number: 001-37388
Talen Energy Corporation
(Exact name of registrant as specified in its charter)
| Delaware | 47-1197305 | ||||
(State or other jurisdiction of incorporation or organization) | (IRS Employer Identification No.) | ||||
2929 Allen Pkwy, Suite 2200 Houston, TX | 77019 | ||||
(Address of principal executive offices) | (Zip Code) | ||||
(888) 211-6011
(Registrant’s telephone number, including area code)
Not applicable
(Former name, former address and former fiscal year, if changed since last report)
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
| Common stock, par value $0.001 per share | TLN | The Nasdaq Global Select Market | ||||||||||||
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☐ No ☒
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
| ☐ | Large accelerated filer | ☐ | Accelerated filer | ☐ | Emerging growth company | ||||||||||||
| ☒ | Non-accelerated filer | ☐ | Smaller reporting company | ||||||||||||||
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court. Yes ☐ No ☒
As of August 13, 2024, the registrant had 51,001,450 shares outstanding of common stock, par value $0.001 per share.
TALEN ENERGY CORPORATION AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
TABLE OF CONTENTS
| Page | |||||||||||
CAUTIONARY NOTE REGARDING FORWARD-LOOKING INFORMATION
This Quarterly Report (this “Report”) contains forward-looking statements concerning expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not statements of historical fact. These statements often include words such as “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “target,” “project,” “forecast,” “seek,” “will,” “may,” “should,” “could,” “would” or similar expressions. Although we believe that the expectations and assumptions reflected in these forward-looking statements are reasonable, there can be no assurance that these expectations and assumptions will prove to be correct. Forward-looking statements are subject to many risks and uncertainties. The results, events or circumstances reflected in forward-looking statements may not be achieved or occur, and actual results, events or circumstances may differ materially from those discussed in forward-looking statements.
The risks, uncertainties and other factors that could cause actual results to differ materially from the forward-looking statements made by us include those discussed in this Report, as well as the items discussed in our Registration Statement and the included Annual Financial Statements. Moreover, we operate in a very competitive and rapidly changing environment. New risks and uncertainties emerge from time to time, and it is not possible for us to predict all risks and uncertainties that could have an impact on the forward-looking statements contained in this Report.
You should not rely on forward-looking statements as predictions of future events. We have based the forward-looking statements contained in this Report primarily on our current expectations and assumptions about future events. Furthermore, statements that “we believe” and similar statements reflect our beliefs and opinions on the relevant subject. These statements are based on information available to us as of the date of this Report. While we believe such information provides a reasonable basis for these statements, such information may be limited or incomplete, and there can be no assurance that any expectations, assumptions, beliefs or opinions will prove to be correct. Our statements should not be read to indicate that we have conducted an exhaustive inquiry into, or review of, all relevant information. These statements are inherently uncertain, and investors are cautioned not to unduly rely on these statements.
The forward-looking statements made in this Report relate only to events as of the date on which the statements are made. We undertake no obligation to update any forward-looking statements made in this Report to reflect events or circumstances after the date of this Report or to reflect new information, actual results, revised expectations or the occurrence of unanticipated events, except as required by law. We may not actually achieve the plans, intentions or expectations described in our forward-looking statements, and you should not place undue reliance on our forward-looking statements. Our forward-looking statements do not reflect the potential impact of any future acquisitions, mergers, dispositions, joint ventures or investments.
1
PART I. FINANCIAL INFORMATION
ITEM 1. FINANCIAL STATEMENTS
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED)
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars, except share data) | Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 46 | $ | 26 | $ | 42 | $ | 91 | $ | 26 | $ | 108 | ||||||||||||||||||||||||||||||||
| Energy and other revenues | 367 | 188 | 180 | 939 | 188 | 1,042 | ||||||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 76 | 87 | (85) | (32) | 87 | 60 | ||||||||||||||||||||||||||||||||||||||
| Operating Revenues | 489 | 301 | 137 | 998 | 301 | 1,210 | ||||||||||||||||||||||||||||||||||||||
| Fuel and energy purchases | (163) | (57) | (69) | (313) | (57) | (176) | ||||||||||||||||||||||||||||||||||||||
| Nuclear fuel amortization | (28) | (25) | (9) | (63) | (25) | (33) | ||||||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 15 | (46) | (9) | (12) | (46) | (123) | ||||||||||||||||||||||||||||||||||||||
| Energy Expenses | (176) | (128) | (87) | (388) | (128) | (332) | ||||||||||||||||||||||||||||||||||||||
| Operating Expenses | ||||||||||||||||||||||||||||||||||||||||||||
| Operation, maintenance and development | (164) | (69) | (108) | (318) | (69) | (285) | ||||||||||||||||||||||||||||||||||||||
| General and administrative | (40) | (18) | (22) | (83) | (18) | (51) | ||||||||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | (75) | (28) | (68) | (150) | (28) | (200) | ||||||||||||||||||||||||||||||||||||||
| Impairments | — | — | (16) | — | — | (381) | ||||||||||||||||||||||||||||||||||||||
| Operational restructuring | (1) | — | — | (1) | — | — | ||||||||||||||||||||||||||||||||||||||
| Other operating income (expense), net | (6) | (3) | (28) | (6) | (3) | (37) | ||||||||||||||||||||||||||||||||||||||
| Operating Income (Loss) | 27 | 55 | (192) | 52 | 55 | (76) | ||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 27 | 39 | 11 | 102 | 39 | 57 | ||||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | (62) | (33) | (59) | (121) | (33) | (163) | ||||||||||||||||||||||||||||||||||||||
| Reorganization income (expense), net | — | — | 838 | — | — | 799 | ||||||||||||||||||||||||||||||||||||||
| Gain (loss) on sale of assets, net (Note 17) | 561 | — | 15 | 885 | — | 50 | ||||||||||||||||||||||||||||||||||||||
| Other non-operating income (expense), net | 17 | (11) | 4 | 40 | (11) | 10 | ||||||||||||||||||||||||||||||||||||||
| Income (Loss) Before Income Taxes | 570 | 50 | 617 | 958 | 50 | 677 | ||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (112) | (19) | (198) | (181) | (19) | (212) | ||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | 458 | 31 | 419 | 777 | 31 | 465 | ||||||||||||||||||||||||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 4 | 2 | (12) | 29 | 2 | (14) | ||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 454 | $ | 29 | $ | 431 | $ | 748 | $ | 29 | $ | 479 | ||||||||||||||||||||||||||||||||
| Per Common Share (Successor) | ||||||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Basic | $ | 7.90 | $ | 0.49 | N/A | $ | 12.87 | $ | 0.49 | N/A | ||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders - Diluted | 7.60 | 0.49 | N/A | 12.41 | 0.49 | N/A | ||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic (in thousands) | 57,434 | 59,029 | N/A | 58,119 | 59,029 | N/A | ||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted (in thousands) | 59,775 | 59,088 | N/A | 60,269 | 59,088 | N/A | ||||||||||||||||||||||||||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
2
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) (UNAUDITED)
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| (Millions of Dollars) | Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 458 | $ | 31 | $ | 419 | $ | 777 | $ | 31 | $ | 465 | ||||||||||||||||||||||||||||||||
| Other Comprehensive Income (Loss) | ||||||||||||||||||||||||||||||||||||||||||||
| Available-for-sale securities unrealized gain (loss), net | 2 | (6) | (4) | 1 | (6) | 6 | ||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (1) | 2 | 2 | — | 2 | (2) | ||||||||||||||||||||||||||||||||||||||
| Gains (losses) arising during the period, net of tax | 1 | (4) | (2) | 1 | (4) | 4 | ||||||||||||||||||||||||||||||||||||||
| Available-for-sale securities unrealized (gain) loss, net | (5) | 1 | (2) | (12) | 1 | 4 | ||||||||||||||||||||||||||||||||||||||
| Qualifying derivatives unrealized (gain) loss, net | — | — | — | — | — | (1) | ||||||||||||||||||||||||||||||||||||||
| Postretirement benefit actuarial (gain) loss, net | — | — | 1 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||
| Income tax (benefit) expense | 2 | — | — | 5 | — | (3) | ||||||||||||||||||||||||||||||||||||||
| Reclassifications from AOCI, net of tax | (3) | 1 | (1) | (7) | 1 | 2 | ||||||||||||||||||||||||||||||||||||||
| Total Other Comprehensive Income (Loss) | (2) | (3) | (3) | (6) | (3) | 6 | ||||||||||||||||||||||||||||||||||||||
| Comprehensive Income (Loss) | 456 | 28 | 416 | 771 | 28 | 471 | ||||||||||||||||||||||||||||||||||||||
| Less: Comprehensive income (loss) attributable to noncontrolling interest | 4 | 2 | (12) | 29 | 2 | (14) | ||||||||||||||||||||||||||||||||||||||
| Comprehensive Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 452 | $ | 26 | $ | 428 | $ | 742 | $ | 26 | $ | 485 | ||||||||||||||||||||||||||||||||
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
3
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS (UNAUDITED)
| Successor | |||||||||||
| (Millions of Dollars, except share data) | June 30, 2024 | December 31, 2023 | |||||||||
| Assets | |||||||||||
| Cash and cash equivalents | $ | 632 | $ | 400 | |||||||
| Restricted cash and cash equivalents (Note 16) | 483 | 501 | |||||||||
| Accounts receivable, net (Note 4) | 151 | 137 | |||||||||
| Inventory, net (Note 6) | 280 | 375 | |||||||||
| Derivative instruments (Notes 3 and 12) | 27 | 89 | |||||||||
Other current assets (a) | 380 | 52 | |||||||||
| Total current assets | 1,953 | 1,554 | |||||||||
| Property, plant and equipment, net (Note 8) | 3,250 | 3,839 | |||||||||
| Nuclear decommissioning trust funds (Notes 7 and 12) | 1,659 | 1,575 | |||||||||
| Derivative instruments (Notes 3 and 12) | 13 | 6 | |||||||||
| Other noncurrent assets | 207 | 147 | |||||||||
| Total Assets | $ | 7,082 | $ | 7,121 | |||||||
| Liabilities and Equity | |||||||||||
| Long-term debt, due within one year (Notes 11 and 12) | $ | 9 | $ | 9 | |||||||
| Accrued interest | 31 | 32 | |||||||||
| Accounts payable and other accrued liabilities | 212 | 344 | |||||||||
| Derivative instruments (Notes 3 and 12) | 63 | 32 | |||||||||
| Other current liabilities | 118 | 69 | |||||||||
| Total current liabilities | 433 | 486 | |||||||||
| Long-term debt (Notes 11 and 12) | 2,617 | 2,811 | |||||||||
| Derivative instruments (Notes 3 and 12) | 1 | 11 | |||||||||
| Postretirement benefit obligations (Note 13) | 364 | 368 | |||||||||
| Asset retirement obligations and accrued environmental costs (Note 9) | 473 | 469 | |||||||||
| Deferred income taxes (Note 5) | 495 | 407 | |||||||||
| Other noncurrent liabilities | 127 | 35 | |||||||||
| Total Liabilities | $ | 4,510 | $ | 4,587 | |||||||
| Commitments and Contingencies (Note 10) | |||||||||||
Stockholders’ Equity | |||||||||||
Common stock ($0.001 par value 350,000,000 shares authorized) (b) (c) | $ | — | $ | — | |||||||
| Additional paid-in capital | 2,092 | 2,346 | |||||||||
| Accumulated retained earnings (deficit) | 448 | 134 | |||||||||
| Accumulated other comprehensive income (loss) | (29) | (23) | |||||||||
Total Stockholders’ Equity | 2,511 | 2,457 | |||||||||
| Noncontrolling interests | 61 | 77 | |||||||||
| Total Equity | 2,572 | 2,534 | |||||||||
| Total Liabilities and Equity | $ | 7,082 | $ | 7,121 | |||||||
__________________
(a)Includes $300 million of proceeds from the Cumulus Data Campus Sale held in escrow.
(b)As of June 30, 2024 (Successor): 53,259,981 shares issued, 53,254,954 shares outstanding, and 5,027 shares held as treasury stock.
(c)As of December 31, 2023 (Successor): 59,028,843 shares issued and outstanding.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
4
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||
| (Millions of Dollars) | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||
| Operating Activities | ||||||||||||||||||||
| Net income (loss) | $ | 777 | $ | 31 | $ | 465 | ||||||||||||||
| Non-cash reconciliation adjustments: | ||||||||||||||||||||
| Unrealized (gains) losses on derivative instruments | 36 | (39) | 65 | |||||||||||||||||
| (Gain) loss on Cumulus Data Campus Sale and ERCOT Sale | (886) | — | — | |||||||||||||||||
| (Gain) loss on sales of assets, net | — | — | (50) | |||||||||||||||||
| Nuclear fuel amortization | 63 | 25 | 33 | |||||||||||||||||
| Depreciation, amortization and accretion | 144 | 27 | 208 | |||||||||||||||||
| Impairments | — | — | 381 | |||||||||||||||||
| NDT funds (gain) loss, net (excluding interest and fees) | (80) | (33) | (43) | |||||||||||||||||
| Deferred income taxes | 94 | 16 | 195 | |||||||||||||||||
| Reorganization (income) expense, net | — | — | (933) | |||||||||||||||||
| Other | (58) | 17 | 7 | |||||||||||||||||
| Changes in assets and liabilities: | ||||||||||||||||||||
| Accounts receivable, net | (14) | (5) | 261 | |||||||||||||||||
| Inventory, net | 90 | (11) | 10 | |||||||||||||||||
| Other assets | 34 | 22 | 98 | |||||||||||||||||
| Accounts payable and accrued liabilities | (114) | (89) | (69) | |||||||||||||||||
| Accrued interest | (1) | 25 | (124) | |||||||||||||||||
| Other liabilities | 65 | 13 | (42) | |||||||||||||||||
| Net cash provided by (used in) operating activities | 150 | (1) | 462 | |||||||||||||||||
| Investing Activities | ||||||||||||||||||||
| Property, plant and equipment expenditures | (45) | (20) | (138) | |||||||||||||||||
| Nuclear fuel expenditures | (44) | (14) | (49) | |||||||||||||||||
| NDT funds investment sale proceeds | 1,095 | 273 | 949 | |||||||||||||||||
| NDT funds investment purchases | (1,110) | (279) | (959) | |||||||||||||||||
| Equity investments in affiliates | (5) | — | (8) | |||||||||||||||||
| Proceeds from Cumulus Data Campus Sale and ERCOT Sale (Note 17) | 1,089 | — | — | |||||||||||||||||
| Proceeds from the sale of assets | 1 | — | 46 | |||||||||||||||||
| Other investing activities | (2) | 2 | 2 | |||||||||||||||||
| Net cash provided by (used in) investing activities | 979 | (38) | (157) | |||||||||||||||||
5
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED)
| Successor | Predecessor | |||||||||||||||||||
| (Millions of Dollars) | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||
| Financing Activities | ||||||||||||||||||||
| Contributions from member | — | — | 1,393 | |||||||||||||||||
| Financing proceeds at Emergence, net of discount | — | — | 2,219 | |||||||||||||||||
| Repayment of Prepetition Secured Indebtedness | — | — | (3,898) | |||||||||||||||||
| Payment of make-whole premiums on Prepetition Secured Indebtedness | — | — | (152) | |||||||||||||||||
| LMBE-MC TLB payments | — | (1) | (7) | |||||||||||||||||
| Cumulus Digital TLF repayment | (182) | — | — | |||||||||||||||||
| Share repurchases (Note 15) | (654) | — | — | |||||||||||||||||
| Repurchase of noncontrolling interest | (39) | — | — | |||||||||||||||||
| Cash settlement of restricted stock units | (28) | — | — | |||||||||||||||||
| Deferred finance costs | — | — | (74) | |||||||||||||||||
| Derivatives with financing elements | — | — | (20) | |||||||||||||||||
| Other | (12) | 1 | — | |||||||||||||||||
| Net cash provided by (used in) financing activities | (915) | — | (539) | |||||||||||||||||
| Net Increase (Decrease) in Cash and Cash Equivalents and Restricted Cash and Cash Equivalents | 214 | (39) | (234) | |||||||||||||||||
| Beginning of period cash and cash equivalents and restricted cash and cash equivalents | 901 | 754 | 988 | |||||||||||||||||
| End of period cash and cash equivalents and restricted cash and cash equivalents | $ | 1,115 | $ | 715 | $ | 754 | ||||||||||||||
See Note 16 for supplemental cash flow information.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
6
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Treasury Stock | Non controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||
| December 31, 2023 (Successor) | 59,029 | $ | 2,346 | $ | 134 | $ | (23) | $ | — | $ | 77 | $ | 2,534 | ||||||||||||||||||||||||||||
| Net income (loss) | — | — | 294 | — | — | 25 | 319 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | (4) | — | — | (4) | ||||||||||||||||||||||||||||||||||
| Share repurchase | (493) | — | — | — | (39) | — | (39) | ||||||||||||||||||||||||||||||||||
Purchase of noncontrolling interest (c) | — | (15) | — | — | — | (24) | (39) | ||||||||||||||||||||||||||||||||||
Cash distributions (d) | — | — | — | — | — | (1) | (1) | ||||||||||||||||||||||||||||||||||
Non-cash distributions (b) | — | — | — | — | — | (12) | (12) | ||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | 8 | — | — | — | — | 8 | ||||||||||||||||||||||||||||||||||
| March 31, 2024 (Successor) | 58,536 | $ | 2,339 | $ | 428 | $ | (27) | $ | (39) | $ | 65 | $ | 2,766 | ||||||||||||||||||||||||||||
| Net income (loss) | — | — | 454 | — | — | 4 | 458 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | (2) | — | — | (2) | ||||||||||||||||||||||||||||||||||
| Share repurchases | (5,281) | — | — | — | (622) | — | (622) | ||||||||||||||||||||||||||||||||||
| Retirement of treasury stock | — | (227) | (434) | — | 661 | — | — | ||||||||||||||||||||||||||||||||||
| Cash settlement of restricted stock units | — | (28) | — | — | — | — | (28) | ||||||||||||||||||||||||||||||||||
Non-cash distributions (b) | — | — | — | — | — | (8) | (8) | ||||||||||||||||||||||||||||||||||
| Stock-based compensation | — | 8 | — | — | — | — | 8 | ||||||||||||||||||||||||||||||||||
| June 30, 2024 (Successor) | 53,255 | $ | 2,092 | $ | 448 | $ | (29) | $ | — | $ | 61 | $ | 2,572 | ||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Related primarily to distribution of Bitcoin to TeraWulf.
(c)TES acquisition of remaining noncontrolling interests in Cumulus Digital Holdings. See Note 17 for additional information.
(d)Distribution to noncontrolling interest owners of Cumulus Digital Holdings.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
7
TALEN ENERGY CORPORATION AND SUBSIDIARIES
CONDENSED CONSOLIDATED STATEMENTS OF EQUITY (UNAUDITED)
| (Millions of Dollars, except share data) | Common stock shares (a) | Additional paid-in capital | Accumulated earnings (deficit) | AOCI | Member's Equity | Non controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||
| December 31, 2022 (Predecessor) | $ | — | $ | — | $ | — | $ | — | $ | (573) | $ | 91 | $ | (482) | |||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 48 | (2) | 46 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | 9 | — | 9 | ||||||||||||||||||||||||||||||||||
Non-cash contributions (c) | — | — | — | — | — | 38 | 38 | ||||||||||||||||||||||||||||||||||
Non-cash distribution, net (d) | — | — | — | — | — | (2) | (2) | ||||||||||||||||||||||||||||||||||
| March 31, 2023 (Predecessor) | $ | — | $ | — | $ | — | $ | — | $ | (516) | $ | 125 | $ | (391) | |||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | 431 | (12) | 419 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | — | (3) | — | (3) | ||||||||||||||||||||||||||||||||||
Cancellation of member’s equity (b) | — | — | — | — | 88 | — | 88 | ||||||||||||||||||||||||||||||||||
Issuance of member’s equity (b) | — | — | — | — | 2,313 | — | 2,313 | ||||||||||||||||||||||||||||||||||
Issuance of warrants (b) | — | — | — | — | 8 | — | 8 | ||||||||||||||||||||||||||||||||||
| Common equity from member's equity exchange | — | 2,321 | — | — | (2,321) | — | — | ||||||||||||||||||||||||||||||||||
Non-cash distributions (d) | — | — | — | — | — | (3) | (3) | ||||||||||||||||||||||||||||||||||
| May 17, 2023 (Predecessor) | $ | — | $ | 2,321 | $ | — | $ | — | $ | — | $ | 110 | $ | 2,431 | |||||||||||||||||||||||||||
| May 18, 2023 (Successor) | 59,029 | $ | 2,321 | $ | — | $ | — | $ | — | $ | 110 | $ | 2,431 | ||||||||||||||||||||||||||||
| Net income (loss) | — | — | 29 | — | — | 2 | 31 | ||||||||||||||||||||||||||||||||||
| Other comprehensive income (loss) | — | — | — | (3) | — | — | (3) | ||||||||||||||||||||||||||||||||||
Non-cash distribution (d) | — | — | — | — | — | (3) | (3) | ||||||||||||||||||||||||||||||||||
| Other | — | 4 | — | — | — | — | 4 | ||||||||||||||||||||||||||||||||||
| June 30, 2023 (Successor) | 59,029 | $ | 2,325 | $ | 29 | $ | (3) | $ | — | $ | 109 | $ | 2,460 | ||||||||||||||||||||||||||||
__________________
(a)Shares in thousands.
(b)Pursuant to the Plan of Reorganization: (i) existing equity interests were canceled; and (ii) new equity interests and equity-classified warrants were issued.
(c)Relates to contributions of cryptocurrency mining machines by TeraWulf to Nautilus.
(d)Relates primarily to distributions of cryptocurrency mining machines or Bitcoin to TeraWulf.
The accompanying Notes to the Interim Financial Statements are an integral part of the financial statements.
8
TALEN ENERGY CORPORATION AND SUBSIDIARIES
NOTES TO THE INTERIM FINANCIAL STATEMENTS (UNAUDITED)
Capitalized terms and abbreviations appearing in these Notes to the Interim Financial Statements are defined in the glossary. Dollars are in millions, unless otherwise noted. References to the “Annual Financial Statements” are to the audited Talen Energy Corporation 2023 Annual Financial Statements and Notes thereto, which are attached to the Registration Statement.
“TEC” refers to Talen Energy Corporation. “TES” refers to Talen Energy Supply, LLC. For periods after May 17, 2023, the terms “Talen,” “Successor,” the “Company,” “we,” “us” and “our” refer to TEC and its consolidated subsidiaries (including TES), unless the context clearly indicates otherwise. For periods on or before May 17, 2023, the terms “Talen,” “Predecessor,” the “Company,” “we,” “us” and “our” refer to TES and its consolidated subsidiaries, unless the context clearly indicates otherwise. See “Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition” in Note 2 for information on an accounting reverse acquisition that occurred at Emergence.
This presentation has been applied where identification of subsidiaries is not material to the matter being disclosed, and to conform narrative disclosures to the presentation of financial information on a consolidated basis. When identification of a subsidiary is considered important to understanding the matter being disclosed, the specific entity’s name is used. Each disclosure referring to a subsidiary also applies to TEC insofar as such subsidiary’s financial information is included in TEC’s consolidated financial information. TEC and each of its subsidiaries and affiliates are separate legal entities and, except by operation of law, are not liable for the debts or obligations of one another absent an express contractual undertaking to the contrary.
1. Organization and Operations
Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity, and ancillary services into wholesale power markets in the United States primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic region of the United States and Montana. The majority of our generation is produced at our zero-carbon nuclear and lower-carbon gas-fired facilities. As of June 30, 2024 (Successor), our generation capacity was 10,665 MW (summer rating). Talen is headquartered in Houston, Texas.
2. Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
Our Interim Financial Statements, which are prepared in accordance with GAAP and pursuant to the rules and regulations of the SEC for Quarterly Reports on Form 10-Q, include: (i) the accounts of all controlled subsidiaries; (ii) elimination adjustments for intercompany transactions between controlled subsidiaries; (iii) any undivided interests in jointly owned facilities consolidated on a proportionate basis; and (iv) all adjustments considered necessary for a fair statement of the information set forth. All adjustments are of a normal recurring nature except as otherwise disclosed. Certain information and note disclosures have been condensed or omitted from the Interim Financial Statements in accordance with GAAP. The Consolidated Balance Sheet as of December 31, 2023 (Successor) is derived from the 2023 Consolidated Balance Sheet in the Annual Financial Statements. The Interim Financial Statements and Notes thereto should be read in conjunction with the Annual Financial Statements and Notes thereto. The results of operations presented in our Interim Financial Statements are not necessarily indicative of the results to be expected for the full year or for other future periods because interim period results can be disproportionately influenced by operational developments, seasonality, and other various factors.
9
Emergence from Restructuring, Fresh Start Accounting, and Reverse Acquisition. In May 2022, TES and 71 of its subsidiaries filed voluntary petitions seeking relief under Chapter 11 of the U.S. Bankruptcy Code. In December 2022, TEC became a debtor in the Restructuring in order to facilitate certain transactions contemplated by the Plan of Reorganization. The Plan of Reorganization was approved by the requisite parties in November 2022, was confirmed by the U.S. Bankruptcy Court in December 2022, and became effective in May 2023, when TEC, TES and the other debtors emerged from the Restructuring.
Upon commencement of the Restructuring, TES was deconsolidated from TEC for financial reporting purposes because TEC no longer controlled TES. TEC regained control of TES at Emergence, which resulted in TEC’s reconsolidation of TES. The combination was accounted for as a reverse acquisition in which TEC was the legal acquirer and TES was the accounting acquirer. Accordingly, our Interim Financial Statements are issued under the name of TEC, the legal parent of TES and accounting acquiree, but represent the continuation of the financial statements of TES, the accounting acquirer.
After Emergence, TES applied fresh start accounting, which resulted in a new basis of accounting as the Company became a new financial reporting entity. As a result of the application of fresh start accounting and the implementation of the Plan of Reorganization, our financial position and results of operations beginning after Emergence are not comparable to our financial position or results of operations prior to that date. The financial results are presented for: (i) the Predecessor period from January 1 through May 17, 2023; and (ii) the Successor periods from May 18 through June 30, 2023, and from January 1 through June 30, 2024. The Interim Financial Statements and Notes thereto have been presented with a black line division to delineate the lack of comparability between the Predecessor and Successor.
See Notes 2, 3 and 4 in Notes to the Annual Financial Statements for additional information on the reverse acquisition, the legal structure of the Restructuring transactions, and the impacts of fresh start accounting.
Summary of Significant Accounting Policies
Reclassifications. Certain amounts in the prior period financial statements were reclassified to conform to the current period’s presentation. The reclassifications did not affect operating income, net income, total assets, total liabilities, net equity or cash flows.
Use of Estimates. The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.
Treasury Stock and Retirement of Treasury Shares. Share repurchases are accounted for under the cost method, which recognizes the entire cost of the acquired stock, including transaction costs and excise tax, as a reduction in additional paid-in-capital and are presented as “Treasury stock” on the Consolidated Balance Sheets. Share repurchases are recognized on a trade date basis when we are contractually obligated to purchase the shares. At retirement, the common stock balance is reduced for the par value of the shares. The excess of the acquisition cost of treasury shares over the par value is recognized in additional paid-in capital (up to the amount credited to additional paid-in capital upon original issuance of the shares), with any remaining cost deducted from retained earnings.
10
Nuclear PTCs. The Nuclear PTC program provides qualified nuclear power generation facilities with transferable credits for electricity produced and sold to an unrelated party during each tax year. These credits, which are accounted for by analogy to income-based grants under international accounting standards for government grants and disclosure of government assistance, are recognized when there is reasonable assurance that the Company will comply with the applicable conditions and that the credit will be received, which is generally over the period of production. As the credits that are generated each tax year are based on annual gross receipts and production volumes, the measurement of the credit value is estimated at each period until the final value can be determined at the end of the year, which may be different than the estimated amount. The credit value includes a five-times multiplier (up to $15 per MWh) for meeting prevailing wage requirements. Accordingly, Nuclear PTCs are recognized based on production volumes generated during the period and measured at the credit value for the tax year. See Note 4 for amounts recognized, which are presented as “Energy and other revenues” on the Consolidated Statements of Operations and “Other current assets” on the Consolidated Balance Sheets. Credits that are utilized to reduce federal income taxes payable are presented as a reduction of “Other current liabilities” on the Consolidated Balance Sheets. There have been no transfers of Nuclear PTCs to third parties during the six months ended June 30, 2024 (Successor). Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value received.
See Note 2 in Notes to the Annual Financial Statements for additional information on significant accounting policies.
3. Risk Management, Derivative Instruments and Hedging Activities
Risk Management Objectives
We are exposed to risks arising from our business, including, but not limited to, market and commodity price risk, credit and liquidity risk and interest rate risk. The hedging strategies deployed by our commercial organization manage and (or) balance these risks within a structured risk management program in order to minimize near-term future cash flow volatility. Our risk management committee, comprised of certain senior management members across the organization, oversees the management of these risks in accordance with our risk policy. In turn, the risk management committee is overseen by the risk committee of the Board of Directors.
The Board of Directors (including the risk committee) and management have established procedures to monitor, measure and manage hedging activities and credit risk in accordance with the risk policy.
Key risk control activities, which are designed to ensure compliance with the risk policy, include, among other activities, credit review and approval, validation of transactions and market prices, verification of risk and transaction limits, portfolio stress tests, analysis and monitoring of margin at risk and daily portfolio reporting.
Market and Commodity Price Risk. Volatility in the wholesale power markets provides uncertainty in the future performance and cash flows of the business. The price risk Talen is exposed to includes the price variability associated with future sales and (or) purchases of power, natural gas, coal, uranium, oil products, environmental products and other energy commodities in competitive wholesale markets. Several factors influence price volatility, including: seasonal changes in demand; weather conditions; available regional load-serving supply; regional transportation and (or) transmission availability; market liquidity; and federal, regional and state regulations.
Within the parameters of our risk policy, we generally utilize conventional first lien, exchange-traded and over-the-counter traded derivative instruments and, in certain instances, structured products, to economically hedge the commodity price risk of the forecasted future sales and purchases of commodities associated with our generation portfolio.
11
Open commodity purchase (sales) derivatives as of June 30, 2024 (Successor) range in maturity through 2026. The net notional volumes of open commodity derivatives were:
| Successor | |||||||||||
June 30, 2024 (a) | December 31, 2023 (a) | ||||||||||
| Power (MWh) | (38,172,764) | (27,557,871) | |||||||||
| Natural gas (MMBtu) | 70,334,960 | 8,314,060 | |||||||||
| Emission allowances (tons) | 75,000 | 500,000 | |||||||||
__________________
(a)The volumes may be less than the contractual volumes, as the probability that option contracts will be exercised is considered in the volumes displayed.
Interest Rate Risk. Talen is exposed to interest rate risk from the possibility that changes in interest rates will affect future cash flows associated with existing floating rate debt issuances. To reduce interest rate risk, derivative instruments are utilized to economically hedge the interest rates for a predetermined contractual notional amount, which results in a cash settlement between counterparties. To the extent possible, first lien interest rate fixed-for-floating swaps are utilized to hedge this risk.
Open interest rate derivatives are related to the TLB indebtedness and range in maturity dates through 2026. The net notional volumes of open interest rate derivatives were:
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
Interest rate (in millions) | $ | 290 | $ | 290 | |||||||
Credit Risk. Credit risk, which is the risk of financial loss if a customer, counterparty or financial institution is unable to perform or pay amounts due, is applicable to cash and cash equivalents, restricted cash and cash equivalents, derivative instruments and accounts receivable. The maximum amount of credit exposure associated with financial assets is equal to the carrying value. Credit risk, which cannot be completely eliminated, is managed through a number of practices such as ongoing reviews of counterparty creditworthiness, prepayment, inclusion of termination rights in contracts which are triggered by certain events of default and executing master netting arrangements which permit amounts between parties to be offset. Additionally, credit enhancements such as cash deposits, LCs and credit insurance may be employed to mitigate credit risk.
Cash and cash equivalents are placed in depository accounts or high-quality, short-term investments with major international banks and financial institutions. Individual counterparty exposure from over-the-counter derivative instruments is managed within predetermined credit limits and includes the use of master netting arrangements and cash-call margins, when appropriate, to reduce credit risk. Exchange-traded commodity contracts, which are executed through futures commission merchants, have minimal credit risk because they are subject to mandatory margin requirements and are cleared with an exchange. However, Talen is exposed to the credit risk of the futures commission merchants arising from daily variation margin cash calls. Restricted cash and cash equivalents deposited to meet initial margin requirements are held by futures commission merchants in segregated accounts for the benefit of Talen.
Outstanding accounts receivable include those from sales of capacity, generated electricity and ancillary services through contracts directly with ISOs and RTOs and realized settlements of physical and financial derivative instruments with commodity marketers. Additionally, Talen carries accounts receivable due from joint owners for their portion of operating and capital costs for certain jointly owned facilities that are operated by the Company. The majority of outstanding receivables, which are continually monitored, have customary payment terms. The allowance for doubtful accounts was a non-material amount as of June 30, 2024 (Successor) and December 31, 2023 (Successor).
12
As of June 30, 2024 (Successor), Talen’s aggregate credit exposure, which excludes the effects of netting arrangements, cash collateral, LCs and any allowances for doubtful collections, was $437 million and its credit exposure net of such effects was $66 million. Excluding ISO and RTO counterparties, whose accounts receivable settlements are subject to applicable market controls, the ten largest single net credit exposures account for approximately 54% of Talen’s total net credit exposure, which are primarily with entities assigned investment grade credit ratings.
Certain derivative instruments contain credit risk-related contingent features, which may require us to provide cash collateral, LCs or guarantees from a creditworthy entity if the fair value of a liability eclipses a certain threshold or upon a decline in Talen’s credit rating. The fair values of derivative instruments in a net liability position, and that contain credit risk-related contingent features, were non-material as of June 30, 2024 (Successor) and December 31, 2023 (Successor).
Derivative Instrument Presentation
Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
| Successor | |||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||
| Assets | Liabilities | Assets | Liabilities | ||||||||||||||||||||
| Commodity contracts | $ | 24 | $ | 63 | $ | 88 | $ | 32 | |||||||||||||||
| Interest rate contracts | 3 | — | 1 | — | |||||||||||||||||||
| Total current derivative instruments | 27 | 63 | 89 | 32 | |||||||||||||||||||
| Commodity contracts | 13 | 1 | 6 | 5 | |||||||||||||||||||
| Interest rate contracts | — | — | — | 6 | |||||||||||||||||||
| Total non-current derivative instruments | $ | 13 | $ | 1 | $ | 6 | $ | 11 | |||||||||||||||
All commodity and interest rate derivatives are economic hedges where the changes in fair value are presented immediately in income as unrealized gains and losses. Changes in the fair value and realized settlements on commodity derivative instruments are presented as separate components of “Energy revenues” and “Fuel and energy purchases” on the Consolidated Statements of Operations. See Note 12 for additional information on fair value.
Effect of Netting. Generally, the right of setoff within master netting arrangements permits the fair value of derivative assets to be offset with derivative liabilities. As an election, derivative assets and derivative liabilities are presented on the Consolidated Balance Sheets with the effect of such permitted netting as of June 30, 2024 (Successor) and December 31, 2023 (Successor).
The net amounts of “Derivative instruments” presented as assets and liabilities on the Consolidated Balance Sheets considering the effect of permitted netting and where cash collateral is pledged in accordance with the underlying agreement were:
| Gross Derivative Instruments | Eligible for Offset | Net Derivative Instruments | Collateral (Posted) Received | Net Amounts | |||||||||||||||||||||||||
| June 30, 2024 (Successor) | |||||||||||||||||||||||||||||
Assets | $ | 286 | $ | (246) | $ | 40 | $ | — | $ | 40 | |||||||||||||||||||
| Liabilities | 332 | (246) | 86 | (22) | 64 | ||||||||||||||||||||||||
| December 31, 2023 (Successor) | |||||||||||||||||||||||||||||
| Assets | $ | 295 | $ | (198) | $ | 97 | $ | (2) | $ | 95 | |||||||||||||||||||
| Liabilities | 300 | (198) | 102 | (59) | 43 | ||||||||||||||||||||||||
13
Statements of Operations Presentation. The location and pre-tax effect of “Derivative instruments” presented on the Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Realized gain (loss) on commodity contracts | ||||||||||||||||||||||||||||||||||||||||||||
Energy revenues (a) | $ | 38 | $ | 70 | $ | 65 | $ | 196 | $ | 70 | $ | 644 | ||||||||||||||||||||||||||||||||
Fuel and energy purchases (a) | (8) | (20) | (13) | (7) | (20) | (34) | ||||||||||||||||||||||||||||||||||||||
| Unrealized gain (loss) on commodity contracts | ||||||||||||||||||||||||||||||||||||||||||||
Operating revenues (b) | 76 | 87 | (85) | (32) | 87 | 60 | ||||||||||||||||||||||||||||||||||||||
Energy expenses (b) | 15 | (46) | (9) | (12) | (46) | (123) | ||||||||||||||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on interest rate contracts | ||||||||||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | 1 | 1 | — | 9 | 1 | — | ||||||||||||||||||||||||||||||||||||||
__________________
(a)Does not include those derivative instruments that settle through physical delivery.
(b)Presented as “Unrealized gain (loss) on derivative instruments” on the Consolidated Statements of Operations.
4. Revenue
The disaggregation of our operating revenues for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Capacity revenues | $ | 46 | $ | 26 | $ | 42 | $ | 91 | $ | 26 | $ | 108 | ||||||||||||||||||||||||||||||||
| Electricity sales and ancillary services, ISO/RTO | 249 | 130 | 85 | 514 | 130 | 281 | ||||||||||||||||||||||||||||||||||||||
| Physical electricity sales, bilateral contracts, other | 22 | 6 | 13 | 86 | 6 | 62 | ||||||||||||||||||||||||||||||||||||||
| Other revenue from customers | 29 | 15 | 18 | 71 | 15 | 27 | ||||||||||||||||||||||||||||||||||||||
| Total revenue from contracts with customers | 346 | 177 | 158 | 762 | 177 | 478 | ||||||||||||||||||||||||||||||||||||||
| Realized and unrealized gain (loss) on derivative instruments | 100 | 124 | (21) | 157 | 124 | 732 | ||||||||||||||||||||||||||||||||||||||
Nuclear PTC and other revenue (a) | 43 | — | — | 79 | — | — | ||||||||||||||||||||||||||||||||||||||
| Operating revenues | $ | 489 | $ | 301 | $ | 137 | $ | 998 | $ | 301 | $ | 1,210 | ||||||||||||||||||||||||||||||||
(a)During the six months ended June 30, 2024, $51 million of estimated Nuclear PTCs were utilized as a credit against our federal income tax payable. See Note 5 for additional information on the tax impact of the Nuclear PTC.
14
Accounts Receivable
“Accounts receivable, net” presented on the Consolidated Balance Sheets were:
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Customer accounts receivable | $ | 104 | $ | 52 | |||||||
| Other accounts receivable | 47 | 85 | |||||||||
| Accounts receivable, net | $ | 151 | $ | 137 | |||||||
During the six months ended June 30, 2024 (Successor), the period from May 18 through June 30, 2023 (Successor), and the period from January 1 through May 17, 2023 (Predecessor), there were no significant changes in accounts receivable other than normal receivable recognition and collection transactions. See Note 3 for additional information on Talen’s credit risk on the carrying value of its receivables.
Future Performance Obligations
In the normal course of business, Talen has future performance obligations for capacity sales awarded through market-based capacity auctions and (or) for capacity sales under bilateral contractual arrangements.
As of June 30, 2024 (Successor), the expected future period capacity revenues subject to unsatisfied or partially unsatisfied performance obligations were:
2024 (a) | 2025 | 2026 | 2027 | 2028 | |||||||||||||||||||||||||
| Expected capacity revenues | $ | 101 | $ | 85 | $ | 3 | $ | 3 | $ | 1 | |||||||||||||||||||
__________________
(a)For the period from July 1 through December 31, 2024.
The PJM capacity auction for the 2025/2026 PJM Capacity Year was held in July 2024. Talen cleared a total of 6,820 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas. The PJM capacity auctions for any years thereafter have not yet been held. See Note 10 for additional information on the PJM RPM and auctions.
15
5. Income Taxes
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Income (loss) before income taxes | $ | 570 | $ | 50 | $ | 617 | $ | 958 | $ | 50 | $ | 677 | ||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (112) | (19) | (198) | (181) | (19) | (212) | ||||||||||||||||||||||||||||||||||||||
Effective tax rate | 19.6% | 38.0% | 32.1% | 18.9% | 38.0% | 31.3% | ||||||||||||||||||||||||||||||||||||||
| Federal income tax statutory tax rate | 21 % | 21 % | 21 % | 21 % | 21 % | 21 % | ||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) computed at the federal income tax statutory tax rate | (120) | (10) | (130) | (201) | (10) | (143) | ||||||||||||||||||||||||||||||||||||||
| Income tax increase (decrease) due to: | ||||||||||||||||||||||||||||||||||||||||||||
| State income taxes, net of federal benefit | (17) | (2) | (32) | (29) | (2) | (34) | ||||||||||||||||||||||||||||||||||||||
| Change in valuation allowance | 14 | 2 | 116 | 34 | 2 | 129 | ||||||||||||||||||||||||||||||||||||||
| Production tax credits | 9 | — | — | 18 | — | — | ||||||||||||||||||||||||||||||||||||||
| Other permanent differences | 6 | (3) | (11) | 12 | (3) | (16) | ||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust taxes | (4) | (6) | (2) | (15) | (6) | (9) | ||||||||||||||||||||||||||||||||||||||
| Reorganization adjustments | — | — | (138) | — | — | (138) | ||||||||||||||||||||||||||||||||||||||
| Other | — | — | (1) | — | — | (1) | ||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | $ | (112) | $ | (19) | $ | (198) | $ | (181) | $ | (19) | $ | (212) | ||||||||||||||||||||||||||||||||
Valuation Allowance
Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to permit use of existing deferred tax assets. The assessment of future taxable income includes the scheduled reversal of taxable temporary differences, projected future taxable income, tax planning strategies and results of recent operations. For the six months ended June 30, 2024 (Successor), Talen recognized a $34 million tax benefit for the reduction in federal and state valuation allowances, primarily related to year-to-date divestitures which increase the amount of tax attributes that can be utilized. See Note 17 for information on the sale transactions. At each period, management will continue to assess the available positive and negative evidence to determine the need for a valuation allowance.
6. Inventory
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Coal | $ | 113 | $ | 152 | |||||||
| Oil products | 70 | 75 | |||||||||
| Fuel inventory for electric generation | 183 | 227 | |||||||||
| Materials and supplies, net | 77 | 72 | |||||||||
| Environmental products | 20 | 76 | |||||||||
| Inventory, net | $ | 280 | $ | 375 | |||||||
16
Inventory net realizable value and obsolescence charges on coal and fuel oil inventories are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations. Such non-cash charges were non-material for the six months ended June 30, 2024 (Successor), non-material for the period from May 18 through June 30, 2023 (Successor), and $37 million for the period from January 1 through May 17, 2023 (Predecessor)
Of the above charges incurred during the period from January 1 through May 17, 2023 (Predecessor), $24 million is related to Brandon Shores inventories. See Note 8 for additional information on the Brandon Shores recoverability assessment.
7. Nuclear Decommissioning Trust Funds
| Successor | |||||||||||||||||||||||||||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||
| Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | Amortized Cost | Unrealized Gains | Unrealized Losses | Fair Value | ||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | 13 | $ | — | $ | — | $ | 13 | $ | 9 | $ | — | $ | — | $ | 9 | |||||||||||||||||||||||||||||||
| Equity securities | 498 | 636 | 56 | 1,078 | 491 | 575 | 53 | 1,013 | |||||||||||||||||||||||||||||||||||||||
| Debt securities | 600 | 3 | 5 | 598 | 570 | 10 | 1 | 579 | |||||||||||||||||||||||||||||||||||||||
| Receivables (payables), net | (30) | — | — | (30) | (26) | — | — | (26) | |||||||||||||||||||||||||||||||||||||||
| NDT funds | $ | 1,081 | $ | 639 | $ | 61 | $ | 1,659 | $ | 1,044 | $ | 585 | $ | 54 | $ | 1,575 | |||||||||||||||||||||||||||||||
See Note 12 for additional information on the NDT fair value. There were no available-for-sale debt securities with credit losses as of June 30, 2024 (Successor) and December 31, 2023 (Successor).
As of June 30, 2024 (Successor), there was no intent to sell available-for-sale debt securities with unrealized losses, and it is not more likely than not that each of these investments will be required to be sold before the recovery of its amortized cost. The aggregate related fair value of available-for-sale debt securities with unrealized losses as of June 30, 2024 (Successor) were:
| Fair Value | Unrealized Losses | ||||||||||
| Corporate debt securities | $ | 78 | $ | (1) | |||||||
| Municipal debt securities | 64 | (1) | |||||||||
| U.S. Government debt securities | 183 | (3) | |||||||||
Total debt securities in unrealized loss position | $ | 325 | $ | (5) | |||||||
Securities in an unrealized loss position for a duration of one year or longer as of June 30, 2024 (Successor):
| Fair Value | Unrealized Losses | ||||||||||
| Municipal debt securities | $ | 49 | $ | (1) | |||||||
| U.S. Government debt securities | 105 | (2) | |||||||||
Total debt securities in unrealized loss position for one year or longer (a) | $ | 154 | $ | (3) | |||||||
__________________
(a)Excludes corporate debt securities which, in the aggregate, had a fair value of $23 million, as the unrealized losses were non-material.
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The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Maturities within one year | $ | 75 | $ | 105 | |||||||
| Maturities within two to five years | 177 | 194 | |||||||||
| Maturities thereafter | 346 | 280 | |||||||||
| Debt securities, fair value | $ | 598 | $ | 579 | |||||||
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
Sales proceeds of NDT funds investments (a) | $ | 535 | $ | 271 | $ | 243 | $ | 1,034 | $ | 271 | $ | 839 | ||||||||||||||||||||||||||||||||
| Gross realized gains | 2 | — | 2 | 5 | — | 7 | ||||||||||||||||||||||||||||||||||||||
| Gross realized losses | (3) | (2) | (2) | (6) | (2) | (12) | ||||||||||||||||||||||||||||||||||||||
__________________
(a)Sales proceeds are used to pay income taxes and trust management fees. Remaining proceeds are reinvested in the NDT.
8. Property, Plant and Equipment
| Successor | |||||||||||||||||||||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||
| Estimated Useful Life (years) | Gross Value | Accumulated Provision | Carrying Value | Gross Value | Accumulated Provision | Carrying Value | |||||||||||||||||||||||||||||||||||
| Electric generation | 3-27 | $ | 3,015 | $ | (197) | $ | 2,818 | $ | 3,178 | $ | (109) | $ | 3,069 | ||||||||||||||||||||||||||||
| Nuclear fuel | 1-6 | 322 | (107) | 215 | 228 | (55) | 173 | ||||||||||||||||||||||||||||||||||
| Other property and equipment | 1-20 | 146 | (30) | 116 | 357 | (21) | 336 | ||||||||||||||||||||||||||||||||||
| Intangible assets | 2-26 | 1 | — | 1 | 1 | — | 1 | ||||||||||||||||||||||||||||||||||
| Capitalized software | 1-5 | 6 | (2) | 4 | 6 | (1) | 5 | ||||||||||||||||||||||||||||||||||
| Construction work in progress | 96 | — | 96 | 255 | — | 255 | |||||||||||||||||||||||||||||||||||
| Property, plant and equipment, net | $ | 3,586 | $ | (336) | $ | 3,250 | $ | 4,025 | $ | (186) | $ | 3,839 | |||||||||||||||||||||||||||||
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The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the periods were:
| Successor | Predecessor | Successor | Predecessor | ||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||||||||||||||||||||
Depreciation expense (a) | $ | 56 | $ | 23 | $ | 58 | $ | 116 | $ | 23 | $ | 173 | |||||||||||||||||||||||||||||
Amortization expense (b) | 4 | 1 | 1 | 6 | 1 | 4 | |||||||||||||||||||||||||||||||||||
Accretion expense (c) | 15 | 4 | 9 | 28 | 4 | 24 | |||||||||||||||||||||||||||||||||||
Other | — | — | — | — | — | (1) | |||||||||||||||||||||||||||||||||||
| Depreciation, amortization, and accretion | $ | 75 | $ | 28 | $ | 68 | $ | 150 | $ | 28 | $ | 200 | |||||||||||||||||||||||||||||
__________________
(a)Electric generation and other property and equipment.
(b)Intangible assets and capitalized software.
(c)ARO and accrued environmental cost accretion. See Note 9 for additional information.
The cost of nuclear fuel is presented as “Nuclear fuel amortization” on the Consolidated Statements of Operations.
Reliability Impact Assessments
Reliability Impact Assessments. In 2023, Talen provided notifications to PJM it intends to deactivate electric generation at both Brandon Shores and H.A. Wagner on June 1, 2025. PJM has notified Talen that the generation units at each facility are needed for reliability. In April 2024, cost-of-service rate schedules covering the period of June 1, 2025 through December 31, 2028 were filed at FERC for the continued Reliability-Must-Run operation and provision of service from Brandon Shores Units 1 and 2 and H.A Wagner Units 3 and 4. Each of the filed rate schedules sets forth the terms, conditions, and cost-based rates under which the applicable generation facility will agree to continue to operate its generation units. In June 2024: (i) FERC accepted each rate schedule, subject to refund; (ii) an administrative settlement judge was appointed; and (iii) settlement proceedings commenced. No assurance can be provided as to when, if at all, final rate schedules for each generation facility will be approved by FERC or how the rate schedules and resulting revenues may ultimately be modified in the course of settlement judge procedures, or, should they be necessary, in the course of any subsequent evidentiary hearing procedures.
2023 Impairment
Brandon Shores Asset Group. Brandon Shores is required by contract and permit to cease coal combustion by December 31, 2025. In the first quarter of 2023, Talen canceled its plan to convert Brandon Shores to an oil combustion facility due to an increase in expected conversion costs. This decision triggered a recoverability assessment of the carrying value of the Brandon Shores asset group.
The recoverability analysis indicated that the Brandon Shores asset group carrying value exceeded its future estimated undiscounted cash flows, which required an impairment charge to amend the asset group’s carrying value of its property, plant and equipment to its estimated fair value. Accordingly, for the period from January 1 through May 17, 2023 (Predecessor), a $361 million non-cash pre-tax impairment charge on the asset group’s undepreciated property, plant and equipment is presented as “Impairments” on the Consolidated Statements of Operations.
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9. Asset Retirement Obligations and Accrued Environmental Costs
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Asset retirement obligations | $ | 484 | $ | 464 | |||||||
| Accrued environmental costs | 23 | 23 | |||||||||
| Total asset retirement obligations and accrued environmental costs | 507 | 487 | |||||||||
Less: asset retirement obligations and accrued environmental costs due within one year (a) | 34 | 18 | |||||||||
| Asset retirement obligations and accrued environmental costs due after one year | $ | 473 | $ | 469 | |||||||
__________________
(a)Presented as “Other current liabilities” on the Consolidated Statements of Operations.
Asset Retirement Obligations
The changes of the ARO carrying value were:
| ARO Rollforward | |||||
| Carrying value, December 31, 2023 (Successor) | $ | 464 | |||
| Obligations settled | (7) | ||||
| Accretion expense | 27 | ||||
| Carrying value, June 30, 2024 (Successor) | $ | 484 | |||
Supplemental information for the ARO:
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Supplemental Information | |||||||||||
Nuclear (a) | $ | 227 | $ | 214 | |||||||
Non-Nuclear (b) | 257 | 250 | |||||||||
| Carrying value | $ | 484 | $ | 464 | |||||||
__________________
(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning.
(b)Certain obligations are: (i) partially supported by surety bonds, some of which have been collateralized with cash and (or) LCs; or (ii) partially prefunded under phased installment agreements.
See Note 12 for additional information on Susquehanna’s NDT.
See “Talen Montana Financial Assurance” in Note 10 for additional information on Talen Montana’s requirement to provide financial assurance related to certain environmental decommissioning and remediation liabilities related to the Colstrip Units.
10. Commitments and Contingencies
Legal Matters
Talen is involved in certain legal proceedings, claims and litigation. While we believe that we have meritorious positions and will continue to defend our positions vigorously in these matters, we may not be successful in our efforts. If an unfavorable outcome is probable and can be reasonably estimated, a liability is recognized. In the event of an unfavorable outcome, the liability may be in excess of amounts currently accrued. Because of the inherently unpredictable nature of legal proceedings and the wide range of potential outcomes for any such matter, no estimate of the possible losses in excess of amounts accrued, if any, can be made at this time regarding the matters specifically described below. As a result, additional losses actually incurred in excess of amounts accrued could be substantial.
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Pending Legal Matters
ERCOT Weather Event Lawsuits. Beginning in March 2021, many power generation facility market participants, including the former Talen subsidiaries that at the time owned the Barney Davis, Nueces Bay and Laredo generation facilities, were sued in multiple Texas courts. In these suits, the plaintiffs: (i) allege, among other things, that they suffered losses due to the generation defendants’ failure to properly prepare their facilities to withstand extreme winter weather and other operational failures during Winter Storm Uri in February 2021, and (ii) seek unspecified compensatory, punitive and other damages. The lawsuits were consolidated into a multi-district litigation (“MDL”) pre-trial court. In January 2023, the court denied a motion to dismiss the MDL filed by the generation defendants. In December 2023, the Texas First Court of Appeals granted the generation defendants’ request for mandamus relief and ordered dismissal of the claims against the generation defendants. The plaintiffs have filed a motion seeking rehearing en banc with the First Court of Appeals. If unsuccessful, the plaintiffs are expected to petition the Texas Supreme Court to review the decision. Plaintiffs asserting prepetition Winter Storm Uri claims are limited to recovering any damages solely from the Talen defendants’ insurers pursuant to the Plan of Reorganization. Certain plaintiffs filed lawsuits asserting Winter Storm Uri claims after commencement of the Restructuring. If any of these post-commencement plaintiffs did not receive effective notice of the Restructuring under applicable bankruptcy law, they may not be subject to the terms of the Plan of Reorganization. Talen cannot predict the outcome of this matter for any such claims or its effect on Talen, which has retained these potential liabilities. See Note 17 for information on Talen’s sale of ERCOT generation assets.
In June 2021, TEC intervened in five cases in which certain market participants are challenging the validity of two Public Utility Commission of Texas (“PUCT”) orders directing ERCOT to ensure energy prices were at their maximum of $9,000 per MWh during Winter Storm Uri. One case has since been dismissed, one case is pending in the Texas Third Court of Appeals and two cases are pending in State District Court in Travis County, Texas. In March 2023, the Third Court of Appeals issued an opinion in Luminant v. PUCT that, in part, reversed and remanded the PUCT orders directing ERCOT to ensure prices were at their maximum of $9,000 per MWh during Winter Storm Uri. The PUCT (along with TEC and others) filed petitions for review with the Texas Supreme Court, which were granted in September 2023. In June 2024, the Texas Supreme Court reversed the judgment of the Texas Third Court of Appeals and affirmed the orders of the PUCT. The Court held that, in issuing its orders, the PUCT substantially complied with the Administrative Procedure Act’s procedural rulemaking requirements. Subject to any successful motion for rehearing in the Texas Supreme Court, this matter is effectively concluded in the Company’s favor.
Resolved Legal Matters
Pension Litigation. In November 2020, four former Talen employees filed a lawsuit in the U.S. District Court for the Eastern District of Pennsylvania against TES, TEC, the TERP, the TERP committee, and (as amended) ten former retirement plan committee members alleging that they are owed enhanced benefits under the TERP. In September 2023, the parties reached an agreement to settle all claims on a class-wide basis, inclusive of attorneys’ fees, in exchange for $20 million. The settlement was approved by the court and became final by its terms in July 2024. Approximately $14 million of the settlement will be paid by the TERP to class members, with the remainder paid by the Company, net of insurance recoveries, to the plaintiffs’ attorneys and for certain administrative costs of the settlement. TES, at its discretion, may elect to fund a contribution into the TERP to cover settlement payments paid by the TERP. The settlement amounts and the expected insurance recoveries are presented on the Consolidated Balance Sheets as of June 30, 2024.
See Note 12 in Notes to the Annual Financial Statements for additional resolved legal matters.
21
Regulatory Matters
Talen is subject to regulation by federal and state agencies and other bodies that exercise regulatory authority in the various regions where we conduct business, including but not limited to: FERC; the Department of Energy; the Federal Communications Commission; the NRC; NERC; public utility commissions in various states in which we conduct business; and RTOs and ISOs in the regions in which we conduct business. Talen is party to proceedings before such agencies arising in the ordinary course of business and has other regulatory exposure due to new or amended regulations promulgated by such agencies from time to time. While the outcome of these regulatory matters and proceedings is uncertain, the likely results are not expected, either individually or in the aggregate, to have a material adverse effect on our financial condition or results of operations, although the effect could be material to our results of operations in any interim reporting period.
Susquehanna ISA Amendment. In June 2024, PJM filed at FERC an Amended Interconnection Service Agreement (“Amended ISA”) executed by PJM, PPL Electric Utilities Corporation (“PPL Electric,” a subsidiary of PPL), and Susquehanna, to enable Susquehanna to decrease the amount of power it will provide to the grid and thus increase, up to 480 MW, power that can be sold and provided directly to load via transmission owned by that load and connected directly to Susquehanna (and not to the power grid). The current Interconnection Service Agreement, previously accepted by FERC and similarly approved and executed by PJM and PPL Electric, already allows Susquehanna to decrease power to the grid by up to 300 MW in order to sell and provide that power to load. The increase to 480 MW was studied by PJM, which confirmed that such increase would have no reliability impacts on the grid. PJM requested an effective date of August 3, 2024 for the Amended ISA filing. In June 2024, Exelon Corporation and AEP filed a protest, despite the Amended ISA not being in their service territories and despite PPL Electric’s agreement to the terms. The protest raised generic issues about the service of load behind generators and requests that FERC set the Amended ISA proceeding for hearing or, in the alternative, reject the filing. Talen believes nearly all issues raised by Exelon Corporation and AEP are not within FERC’s limited jurisdictional review and lack merit, and Talen intends to defend against them quickly and vigorously. In July 2024, Talen filed responses at FERC opposing the aforementioned protest and urging FERC to accept the Amended ISA. In August 2024, FERC issued a deficiency letter seeking a more information about the Amended ISA. Talen will work closely with PJM and PPL to respond quickly to the deficiency letter. Additionally, in a separate order, FERC opened a new proceeding through which it will hold a commissioner-led technical conference in Fall 2024 to discuss generic issues related to the co-location of large loads. Talen intends to fully participate in that process.
PJM MOPR. In July 2021, PJM filed proposed tariff language to significantly reduce the application of the existing PJM MOPR by applying it only when the state requires an entity to act in a certain manner in the capacity market in exchange for receiving a subsidy. FERC did not act on PJM’s July 2021 filing, and the PJM MOPR tariff language went into effect in September 2021. In December 2023, the U.S. Court of Appeals for the Third Circuit denied the petitions for review of the MOPR tariff language. In March 2024, the Public Utilities Commission of Ohio filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the Third Circuit’s December 2023 order, which the U.S. Supreme Court denied in May 2024. The final impacts on Talen’s financial condition, results of operations and liquidity are not known at this time.
PJM Market Seller Offer Cap. In March 2021, FERC responded to complaints filed by the PJM IMM on behalf of PJM and various consumer advocates alleging that the PJM MSOC was above a competitive offer level and was, therefore, unjust and unreasonable. In September 2021, FERC issued an order requiring the PJM ACR for each generator to be determined administratively by the PJM IMM. In August 2023, the U.S. Court of Appeals for the District of Columbia Circuit denied petitions by Talen and others for review of FERC’s order. In January 2024, the Electric Power Supply Association filed at the U.S. Supreme Court a petition for certiorari asking the Court to review the D.C. Circuit’s August 2023 order, which the U.S. Supreme Court denied in May 2024. The final impacts of this order on Talen’s financial condition, results of operations and liquidity are not known at this time.
22
PJM Capacity Market Reform. In February 2023, the PJM Board of Managers directed PJM and its stakeholders to resolve: (i) key issues that address the energy transition taking place in PJM; and (ii) issues observed from Winter Storm Elliott. The PJM Board of Managers directive included reliability risks, risk drivers and resource availability. The stakeholder process is referred to as Critical Issue Fast Path (“CIFP”) on resource adequacy. In October 2023, PJM made two filings at FERC regarding certain capacity market reforms developed through the CIFP process. In January 2024, FERC accepted one of PJM’s filings, subject to the condition that PJM submit a compliance filing within 30 days. However, in February 2024, FERC rejected the second of PJM’s capacity market reform filings and approved a request from PJM for a 35-day delay of Base Residual Auction. PJM held the Base Residual Auction for the 2025/2026 Delivery Year in July 2024. At this time, Talen cannot fully predict the impacts of PJM’s reforms on its operations and liquidity.
In June 2023, FERC accepted a request by PJM to delay certain PJM Base Residual Auctions in order to propose additional changes to the PJM RPM. The delay scheduled the PJM Base Residual Auctions for 2026/2027 in December 2024, for 2027/2028 in June 2025, and for 2028/2029 in December 2025. Although PJM has established dates for the next three auctions, there is no guarantee that the auctions will take place on those dates or at all. Depending on the ultimate outcome of matters related to PJM’s capacity auctions, capacity revenues in PJM could be affected, but the final impacts on Talen’s financial condition, results of operations and liquidity are not known at this time.
Environmental Matters
Extensive federal, state and local environmental laws and regulations are applicable to our business, including those related to air emissions, water discharges, and hazardous and solid waste management. From time to time, in the ordinary course of our business, Talen may become involved in other environmental matters or become subject to other, new or revised environmental statutes, regulations or requirements. It may be necessary for us to modify, curtail, replace or cease operation of certain facilities or performance of certain operations to comply with statutes, regulations and other requirements imposed by regulatory bodies, courts or environmental groups. We may incur costs to comply with environmental laws and regulations, including increased capital expenditures or operation and maintenance expenses, monetary fines, penalties or other restrictions, which could be material. Legal challenges to environmental permits or rules add to the uncertainty of estimating the future cost of complying with these permits and rules. In addition, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed.
Water and Waste. Changes made by the EPA to the EPA CCR Rule and the EPA ELG Rule in 2020 allow coal generation facility operators to request an extension to compliance deadlines if the facility commits to cessation of coal-fired generation by the end of 2028. Pursuant to Talen’s plans to cease wholly owned coal operations, Talen requested extensions for compliance under these rules for certain of its generation facilities; some have been approved and some are still under review. The most significant extension under review is the EPA CCR Rule Part A extension request for Montour Ash Impoundment 1, and a negative result would have a significant impact on the closure plan for this impoundment.
In 2023, the EPA proposed additional changes to the EPA ELG Rule and the EPA CCR Rule and finalized those changes in May 2024. The new EPA ELG Rule does not add treatment requirements to Talen’s coal-fired power generation facilities planning to cease burning coal by 2028, but it does establish discharge limits for waters collected from CCR units. Under the revised EPA CCR Rule, the EPA developed new categories of CCR units which are areas that were previously unregulated. These new CCR units, which are subject to the closure performance standards set by the EPA, are: (i) legacy CCR impoundments; and (ii) areas where CCR was disposed of or managed on land outside of regulated units called CCR management units (subject to a minimum threshold). Furthermore, the EPA’s interpretations of the EPA CCR Rule continue to evolve through litigation, enforcement, and other regulatory actions.
23
Talen submitted formal comments on both proposed rules citing their flaws. A number of challenges against the EPA ELG Rule have been filed in multiple U.S. Courts of Appeals. The various challenges have been filed by 15 state attorneys general, environmental groups, and industry parties and groups, including the Utility Water Act Group (“UWAG”), of which Talen is a member. In June 2024, the U.S. Court of Appeals for the Eighth Circuit was selected to hear the consolidated petitions for review and UWAG filed a motion to stay the EPA ELG Rule during the pendency of the litigation.
Multiple parties have filed challenges to the EPA CCR Rule in the U.S. Court of Appeals for the District of Columbia, including USWAG”), of which Talen is a member. It is uncertain at this time whether the revised Rules will withstand the filed and anticipated legal challenges by power producers, industry groups, state attorneys general, and others.
The Company continues to review the rule’s provisions, perform the required applicability assessments, and await additional information and guidance from the EPA in order to sufficiently interpret the rule’s requirements. Accordingly, as of June 30, 2024 (Successor), the Company did not have sufficient information to determine the scope of work required under the rule’s provisions and associated estimates. As the Company completes its assessment and determines the scope of work on its properties imposed by the new rule, new AROs and (or) revisions to existing AROs could be required. Such AROs could be material, and as a result, may have a material impact on our results of operations and financial condition.
Air. Since 2016, the coal-fired generation facilities in which Talen has ownership, including Brunner Island, Montour, Keystone and Conemaugh, have been the subject of various efforts under the Clean Air Act to strengthen applicable nitrogen oxides (“NOx”) emission limits. These include Section 126 petitions by downwind states, recommendations by the Ozone Transport Commission, and a ruling on Pennsylvania’s Reasonably Available Control Technology (“RACT”) 2 program by the U.S. District Court for the Southern District of New York. Although the petitions and recommendations are not withdrawn, open concerns appear to have been addressed by the EPA’s issuance of a federal implementation plan with short-term RACT2 NOx limits at these plants in 2022 (resulting from the above court case) (“2022 NOx RACT2 FIP”) and the EPA’s “Good Neighbor Plan FIP” issued in June 2023. Both the 2022 NOx RACT2 FIP and the Good Neighbor Plan FIP are further discussed below. Concerns by upwind states regarding NOx controls were not limited to coal plants owned by Talen.
Although EPA’s 2022 NOx RACT2 FIP for Pennsylvania, which Talen supported, was challenged by other parties, on May 2, 2024, the U.S. Court of Appeals for the Third Circuit upheld the 2022 NOx RACT2 FIP, and the Pennsylvania DEP has now proposed a new state implementation plan (“SIP”) that is consistent with the 2022 NOx RACT2 FIP. In November 2022, Pennsylvania finalized its NOx RACT3 standards for all power generation facilities to address the EPA’s 2015 Ozone Standard. Affected Talen facilities have submitted permit applications demonstrating their compliance methods. At this time, Talen cannot predict the outcome of these potential rule changes on the operations of its generation facilities and its results of operations.
Further, to address the EPA’s 2015 Ozone Standard, in June 2023, the EPA published a final rule covering the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond. The final rule is known as the Good Neighbor Plan FIP. The EPA made some reductions in allowance allocations, among other changes, to minimize NOx emissions during the Ozone Season. Talen’s plants in Texas had originally been covered by the Good Neighbor Plan FIP; however, Talen sold its Texas facilities in the second quarter of 2024 and therefore is no longer impacted by the rule in Texas. Talen’s facilities in Maryland, Pennsylvania and New Jersey remain subject to the new rule; however, the entire rule has been challenged by multiple parties, and the Good Neighbor Plan FIP was stayed in its entirety by the U.S. Supreme Court in June 2024 pending a complete review of the rule by the U.S. Court of Appeals for the D.C. Circuit. At this time, Talen cannot predict the long-term outcome of these rule changes on the operations of its generation facilities and its results of operations.
24
The EPA MATS Rule, which is the original EPA NESHAP for coal plants, has been in effect since 2012. In April 2023, the EPA proposed, and in May 2024, finalized, its Risk and Technology Review for coal-fired generation facilities under the EPA NESHAP. The final rule most notably requires coal plants to reduce particulate matter (“PM”) emissions by the end of 2027 (or 2028 in certain circumstances). Colstrip cannot meet the new PM standard without substantial upgrades to its control equipment; therefore, Talen and the Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the plant. That decision must be made in conjunction with compliance requirements under EPA’s new GHG Rule, finalized in May 2024.
Talen submitted formal comments on the new PM standard and revisions to the EPA MATS Rule, citing the rule’s flaws. A number of challenges to the EPA MATS Rule have been filed in the U.S. Court of Appeals for the D.C. Circuit, including challenges by Talen and by 23 state attorneys general. Multiple motions to stay the EPA MATS Rule during the pendency of the litigation have been filed by Talen and other parties, and in August 2024 the stay motions were denied. In light of the on-going legal challenges, Talen cannot predict the full impact of the revised EPA MATS Rule on the operations of its coal-fired generation facilities and its results of operations.
RGGI. In April 2022, Pennsylvania formally entered the RGGI program, with compliance set to begin on July 1, 2022. However, certain third parties filed lawsuits and appeals questioning the legality of the regulation and the implementation of RGGI in Pennsylvania was stayed. In November 2023, the Commonwealth Court of Pennsylvania ruled RGGI was an invalid tax and voided the rulemaking. The Pennsylvania Department of Environmental Protection appealed this decision to the Pennsylvania Supreme Court in November 2023, and the following day filed notice with the court that the RGGI program would not be implemented while the appeal is pending. In July 2024, the Pennsylvania Supreme Court permitted certain non-profit environmental groups (including Citizens for Pennsylvania’s Future, Clean Air Council, Sierra Club, and the Environmental Defense Fund) to intervene in the litigation. At this time, Talen is unable to determine the full impact of the RGGI program, when and if implemented, on its results of operations and liquidity.
Federal Climate Change Actions. The current federal administration has identified climate change policy as a priority that includes, but is not limited to, greenhouse gas (“GHG”) emission reductions. In May 2024, the EPA issued a new rule under the Clean Air Act that establishes New Source Performance Standards for new electric generating units and GHG Emissions Guidelines for existing electric generating units (“EGUs”) for state implementation. The guidelines would allow all existing EGUs to continue to operate until at least the end of 2031 without having to meet new GHG limits. Existing oil/gas steam EGUs (for example, Martins Creek) will not require additional controls at this time. However, if existing coal-fired EGUs (for example, Colstrip) are to be able to operate beyond 2031, they must install a GHG reduction technology, like carbon capture and sequestration (CCS), by the end of 2031. Talen will need to evaluate the viability and costs of additional controls and decide whether to invest in those controls at Colstrip or retire the units. That decision may be influenced by the cost of compliance with the revised EPA MATS Rule. The EPA stated that it chose not to finalize emission guidelines for existing fossil fuel-fired combustion turbines (for example, Lower Mt. Bethel); however, the EPA intends to take further action on such emission guidelines at a later date.
In 2023, Talen submitted formal comments on the proposed EPA GHG Rule, citing the rule’s flaws. A number of petitions for review of the EPA GHG Rule have been filed in the U.S. Court of Appeals for the D.C. Circuit, including by coalitions representing 27 states and an ad hoc coalition of power producers, of which Talen is a member. Various parties, including the ad hoc coalition of power producers that includes Talen, filed motions to stay the EPA GHG Rule during the pendency of the litigation; however, in July 2024, the D.C. Circuit denied the motions to stay the rule. Shortly thereafter, the coalition of West Virginia and 24 other states and other petitioners, including the ad hoc coalition of power producers that includes Talen, filed at the U.S. Supreme Court requests for an emergency stay of the EPA GHG Rule. If the rule withstands these legal challenges by power producers (including Talen), industry groups, state attorneys general, and others, the EPA GHG Rule could materially impact Colstrip and Talen. Talen is currently evaluating that potential impact. At this time, Talen cannot predict the full impact of the EPA GHG Rule on the operations of its coal-fired generation facilities and its results of operations.
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Environmental Remediation. From time-to-time, Talen undertakes investigative or remedial actions in response to notices of violations, spills or other releases at various on-site and off-site locations, negotiates with the EPA and state and local agencies regarding actions necessary for compliance with applicable requirements, negotiates with property owners and other third parties alleging impacts from our operations and undertakes similar actions necessary to resolve environmental matters that arise in the course of normal operations.
Future investigation or remediation work at sites currently under review, or at sites not currently identified, may result in additional costs, but at this time we are unable to determine if such investigation or remediation work will have a material adverse effect on our financial condition or results of operations.
Guarantees and Other Assurances
In the normal course of business, Talen enters into agreements that provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the creditworthiness attributed to a subsidiary on a stand-alone basis or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs issued by financial institutions, surety bonds issued by insurance companies, and indemnifications. In addition, they may include customary indemnifications to third parties related to asset sales and other transactions. Based on our current knowledge, the probability of expected material payment/performance for the guarantees and other assurances is considered remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain subsidiaries for obligations including, but not limited to, environmental obligations and AROs. In the event of nonperformance by the applicable subsidiary, the beneficiary would make a claim to the surety, and the Company would be required to reimburse any payment by the surety. Talen’s liability with respect to any surety bond is released once the obligations secured by the surety bond are performed. Surety bond providers generally have the right to request additional collateral or request that such bonds be replaced by alternate surety providers, in each case upon the occurrence of certain events. As of June 30, 2024 (Successor) and December 31, 2023 (Successor), the aggregate amount of surety bonds outstanding was $235 million and $240 million, respectively, including surety bonds posted on behalf of Talen Montana as discussed below.
Talen Montana Financial Assurance. Pursuant to the Colstrip AOC, Talen Montana, in its capacity as the Colstrip operator, is obligated to close and remediate coal ash disposal impoundments at Colstrip. The Colstrip AOC specifies an evaluation process between Talen Montana and the Montana Department of Environmental Quality (“the MDEQ”) on the scope of remediation and closure activities, requires the MDEQ to approve such scope, and requires financial assurance to be provided to the MDEQ on approved plans. Each of the co-owners of the Colstrip Units have provided their proportional share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
TES has posted an aggregate $125 million of surety bonds to the MDEQ on behalf of Talen Montana’s proportional share of remediation and closure activities as of June 30, 2024 (Successor) and $115 million as of December 31, 2023 (Successor). In April 2024, the MDEQ approved a modified work scope that required Talen Montana to post an additional $7 million of surety bonds or other financial assurance in the second quarter 2024. Talen Montana has agreed to reimburse TES and its affiliates in the event that these surety bonds are called. Talen Montana’s surety bond requirements may increase due to scope changes, cost revisions and (or) other factors when the MDEQ conducts annual reviews of approved remediation and closure plans as required under the Colstrip AOC. The surety bond requirements will decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed.
Cumulus Digital Assurances. As of December 31, 2023 (Successor), TES had issued LCs in the aggregate amount of $50 million to the lenders of the Cumulus Digital TLF, which LCs could be drawn upon, among other events, the acceleration of the loan due to a bankruptcy or other event of default by Cumulus Digital. The LCs were cancelled upon the repayment in full of the Cumulus Digital TLF in March 2024.
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Additionally, TEC had provided a guarantee to the lenders under the Cumulus Digital TLF for certain shortfalls in interest and principal payments by Cumulus Digital (up to a maximum of 23% of the principal amount of outstanding loans thereunder). The guarantee was cancelled upon the payment in full of the Cumulus Digital TLF in March 2024.
Other Commitments and Contingencies
Nuclear Insurance. The Price-Anderson Act is a United States federal law that governs liability-related issues and ensures the availability of funds for public liability claims arising from a nuclear incident at any U.S. licensed nuclear facility. It also seeks to limit the liability of nuclear reactor owners for such claims from any single incident. As of June 30, 2024 (Successor), the liability limit per incident is $16.3 billion for such claims, which is funded by insurance coverage from American Nuclear Insurers (approximately $500 million in coverage), with the remainder covered by an industry retrospective assessment program.
As of June 30, 2024 (Successor), under the industry retrospective assessment program, in the event of a nuclear incident at any of the reactors covered by the Price-Anderson Act, Susquehanna could be assessed deferred premiums of up to $332 million per incident, payable at a maximum of $49 million per year.
Additionally, Susquehanna purchases property insurance programs from Nuclear Electric Insurance Limited (“NEIL”), an industry mutual insurance company of which Susquehanna is a member. As of June 30, 2024 (Successor), facilities at Susquehanna are insured against nuclear property damage losses up to $2 billion and non-nuclear property damage losses up to $1 billion. Susquehanna also purchases an insurance program that provides coverage for the cost of replacement power during prolonged outages of nuclear units caused by certain specified conditions.
Under the NEIL property and replacement power insurance programs, Susquehanna could be assessed retrospective premiums in the event of the insurers’ adverse loss experience. The maximum assessment for this premium is $48 million as of June 30, 2024 (Successor). Talen has additional coverage that, under certain conditions, may reduce this exposure.
Talen Montana Fuel Supply. Talen Montana purchases coal from the Rosebud Mine for its interest in Colstrip Units 3 and 4 under a full requirements contract with an unaffiliated coal mine operator. In 2015, the MDEQ issued the mine operator an amendment to one of its mine permits expanding the area authorized for mining. Certain parties challenged the permit amendment in a proceeding at the Montana Board of Environmental Review (“the MBER”) and, after the MBER issued a decision upholding the permit amendment, in a lawsuit in Montana state district court. In January 2022, the district court entered an order vacating the permit amendment effective April 1, 2022. Rosebud Mining ceased mining in the expansion area prior to the April 1, 2022 deadline. The mine operator and the MDEQ appealed the district court’s decisions to the Montana Supreme Court and filed motions seeking to stay the order vacating the permit. In August 2022, the Montana Supreme Court entered an order staying the district court’s order pending resolution of the appeal. In November 2023, the Montana Supreme Court remanded the case to the MBER to reanalyze the administrative record, resolve factual questions, and re-examine its prior conclusion. The MBER is awaiting remand. In the meantime, however, the Montana Supreme Court reinstated vacatur of the permit amendment pending MBER review.
In May 2022, the MDEQ issued a second permit amendment expanding the area authorized for mining by the coal-mine operator. A group of complainants initiated proceedings at the MBER and in Montana state district court challenging the second permit amendment. Summary judgment briefing was completed in the MBER case as of January 2024. In December 2023 the Montana state district court challenge was stayed for six months pending a ruling from the Montana Supreme Court in analogous cases.
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In September 2022, the Montana Federal District Court entered an order upholding challenges to a third permit amendment expanding the area authorized for mining by the mine operator. The plaintiffs asserted that the U.S. Office of Surface Mining Reclamation and Enforcement (the “OSM”) violated the National Environmental Policy Act (“NEPA”) when preparing the Environmental Impact Statement (“the EIS”) for the permit amendment. The court ordered the OSM to complete an updated the EIS in accordance with NEPA’s requirements. The permit amendment will be vacated unless the OSM completes the updated the EIS within 19 months from the date of the court’s order. The federal defendants did not appeal and expect to issue a revised decision on the permit amendment within the 19-month deadline, but in November 2022, intervenor-defendants, Westmoreland Rosebud and International Union, appealed the ruling to the Ninth Circuit Court of Appeals. Montana Environmental Information Center and the other plaintiffs moved to dismiss the appeal for lack of jurisdiction, and the federal defendants did not oppose the motion to dismiss. The appeal was dismissed in November 2023, and the federal defendants requested an extension of the deadline to complete the updated EIS until June 30, 2025. In April 2024, the District Court granted an extension, but only to January 31, 2025.
At this time, Talen cannot predict the outcome of these matters or their effect on Talen Montana’s operations, results of operations or liquidity.
11. Long-Term Debt and Other Credit Facilities
Long-Term Debt
| Successor | |||||||||||||||||
Interest Rate (a) | June 30, 2024 | December 31, 2023 | |||||||||||||||
TLB | 8.83 % | $ | 861 | $ | 866 | ||||||||||||
TLC | 8.83 % | 470 | 470 | ||||||||||||||
| Secured Notes | 8.63 % | 1,200 | 1,200 | ||||||||||||||
PEDFA 2009B Bonds | 5.25 % | 50 | 50 | ||||||||||||||
PEDFA 2009C Bonds | 5.25 % | 81 | 81 | ||||||||||||||
Cumulus Digital TLF, including paid-in-kind interest (b) | — % | — | 182 | ||||||||||||||
| Total principal | 2,662 | 2,849 | |||||||||||||||
| Unamortized deferred finance costs and original issuance discounts | (36) | (29) | |||||||||||||||
| Total carrying value | 2,626 | 2,820 | |||||||||||||||
| Less: long-term debt, due within one year | 9 | 9 | |||||||||||||||
| Long-term debt | $ | 2,617 | $ | 2,811 | |||||||||||||
__________________
(a)Computed interest rate as of June 30, 2024 (Successor).
(b)Limited recourse to TES and TEC. See “Guarantees and Other Assurances - Cumulus Digital Assurances” in Note 10 for additional information. The Cumulus Digital TLF was repaid and extinguished in March 2024. See “2024 Transactions – Cumulus Digital TLF Repayment” below for additional information.
The aggregate long-term debt maturities, including amortization and early redemption provisions, as of June 30, 2024 (Successor) were:
2024 (a) | 2025 | 2026 | 2027 | 2028 | Thereafter | Total | |||||||||||||||||||||||||||||||||||
| Total maturities | $ | 4 | $ | 9 | $ | 9 | $ | 9 | $ | 9 | $ | 2,622 | $ | 2,662 | |||||||||||||||||||||||||||
__________________
(a) For the period from July 1 through December 31, 2024.
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Revolving Credit and Other Facilities
| Successor | |||||||||||||||||||||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||
| Expiration | Committed Capacity | Direct Cash Borrowings | LCs Issued | Unused Capacity | Direct Cash Borrowings | LCs Issued | |||||||||||||||||||||||||||||||||||
RCF (a) | May 2028 | $ | 700 | $ | — | $ | 60 | $ | 640 | $ | — | $ | 62 | ||||||||||||||||||||||||||||
TLC LCF (b)(c) | May 2030 | 470 | — | 310 | 160 | — | 404 | ||||||||||||||||||||||||||||||||||
Bilateral LCF (b) | May 2028 | 75 | — | 46 | 29 | — | 74 | ||||||||||||||||||||||||||||||||||
| Total | $ | 1,245 | $ | — | $ | 416 | $ | 829 | $ | — | $ | 540 | |||||||||||||||||||||||||||||
__________________
(a)Committed capacity includes $475 million of LC commitments. Outstanding direct cash borrowings under the RCF, when applicable, are presented as “Revolving credit facilities” on the Consolidated Balance Sheets.
(b)Direct cash borrowings are not permitted under the facility.
(c)These LCs are cash collateralized by $472 million as of June 30, 2024 (Successor) and December 31, 2023 (Successor), which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.
2024 Transactions
Cumulus Digital TLF Repayment. In connection with the Cumulus Data Campus Sale, the Cumulus Digital TLF was paid in full in March 2024, together with all accrued interest and other outstanding amounts. See “Non-Recourse Debt and Other Credit Facilities – Cumulus Digital TLF” in Note 13 in Notes to the Annual Financial Statements for additional information on the related release of liens, termination of guarantees, and cancellation of LCs. See Note 17 for additional information on the Cumulus Data Campus Sale.
Long-Term Debt Repricing. In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is the Standard Overnight Financing Rate (SOFR) plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale; and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement. See Note 17 for additional information on the ERCOT Sale. The repricing transaction is excluded from the Consolidated Statements of Cash Flows as a non-cash item.
Remarketing of PEDFA Bonds. In June 2024, the Company completed the remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $81 million in aggregate principal amount of its PEDFA 2009C Bonds. The bonds will now bear interest at 5.25% until the end of the new term rate period on June 1, 2027. In connection with the remarketing, $133 million of LCs issued under the TLC LCF that had previously supported the bonds were terminated, providing the Company with increased LC capacity under the TLC LCF. The remarketing transaction is excluded from the Consolidated Statements of Cash Flows as a non-cash item.
Talen Energy Supply Long-Term Debt, Revolving Credit and Other Facilities
As of June 30, 2024 (Successor), Talen was not in default under any of its debt agreements.
See “Talen Energy Supply Post-Emergence Long-Term Debt, Revolving Credit and Other Facilities” in Note 13 in Notes to the Annual Financial Statements for a description of the material terms of our Credit Facilities, Secured Notes, PEDFA Bonds and Secured ISDAs.
See “Security Interests, Guarantees, and Cross-Defaults on TES Post-Emergence Obligations” in Note 13 in Notes to the Annual Financial Statements for additional information on the security interests and guarantees supporting these obligations. In addition to the obligations outlined under “Long-Term Debt” and “Revolving Credit and Other Facilities” above, secured obligations included approximately $66 million under Secured ISDAs as of June 30, 2024 (Successor).
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12. Fair Value
Recurring Fair Value Measurements
Financial assets and liabilities reported at fair value on a recurring basis primarily include energy commodity derivatives, interest rate derivatives, and investments held within the NDT.
The classifications of recurring fair value measurements within the fair value hierarchy were:
| Successor | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Level 1 | Level 2 | NAV | Netting (a) | Total | Level 1 | Level 2 | NAV | Netting (a) | Total | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Assets | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Cash equivalents | $ | — | $ | — | $ | 13 | $ | — | $ | 13 | $ | — | $ | — | $ | 9 | $ | — | $ | 9 | |||||||||||||||||||||||||||||||||||||||
Equity securities (b) | 718 | — | 360 | — | 1,078 | 629 | — | 384 | — | 1,013 | |||||||||||||||||||||||||||||||||||||||||||||||||
| U.S. Government debt securities | 336 | — | — | — | 336 | 337 | — | — | — | 337 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Municipal debt securities | — | 83 | — | — | 83 | — | 86 | — | — | 86 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Corporate debt securities | — | 179 | — | — | 179 | — | 156 | — | — | 156 | |||||||||||||||||||||||||||||||||||||||||||||||||
Receivables (payables), net (c) | — | — | — | — | (30) | — | — | — | — | (26) | |||||||||||||||||||||||||||||||||||||||||||||||||
| NDT funds | 1,054 | 262 | 373 | — | 1,659 | 966 | 242 | 393 | — | 1,575 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Commodity derivatives | 167 | 116 | — | (246) | 37 | 98 | 196 | — | (200) | 94 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | 3 | — | — | 3 | — | 1 | — | — | 1 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total assets | $ | 1,221 | $ | 381 | $ | 373 | $ | (246) | $ | 1,699 | $ | 1,064 | $ | 439 | $ | 393 | $ | (200) | $ | 1,670 | |||||||||||||||||||||||||||||||||||||||
| Liabilities | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
Commodity derivatives | 190 | 142 | — | (268) | 64 | 155 | 139 | — | (257) | 37 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Interest rate derivatives | — | — | — | — | — | — | 6 | — | — | 6 | |||||||||||||||||||||||||||||||||||||||||||||||||
| Less: other | — | — | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||||
| Total liabilities | $ | 190 | $ | 142 | $ | — | $ | (268) | $ | 64 | $ | 155 | $ | 145 | $ | — | $ | (257) | $ | 43 | |||||||||||||||||||||||||||||||||||||||
(a)Amounts represent netting pursuant to master netting arrangements and cash collateral held or placed with the same counterparty.
(b)Includes commingled equity and fixed income funds and real estate investment trusts.
(c)Represents: (i) interest and dividends earned but not received; and (ii) net sold or purchased investments, but not settled.
There were no recurring fair value measurements classified as Level 3 as of June 30, 2024 (Successor) and December 31, 2023 (Successor).
Nonrecurring Fair Value Measurements
There were no nonrecurring fair value measurements related to impairments of long-lived assets during the six months ended June 30, 2024 (Successor). See Note 8 for information on the nonrecurring fair value measurement of Brandon Shores during the period from January 1 through May 17, 2023 (Predecessor).
Reported Fair Value
The carrying value of certain financial assets and liabilities on the Consolidated Balance Sheets, including “Cash and cash equivalents,” “Restricted cash and cash equivalents,” “Accounts receivable, net,” and “Accounts payable and other accrued liabilities” approximate fair value.
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The fair value measurements of indebtedness are classified as Level 2 within the fair value hierarchy. The fair value of fixed rate debt was estimated primarily by utilizing an income approach whereby the future cash flows of the obligations are discounted at the estimated current cost of funding rates, which incorporates the credit risk associated with the obligations. The carrying value of variable rate indebtedness approximates fair value.
The carrying value and fair value of indebtedness presented on the Consolidated Balance Sheets were:
| Successor | |||||||||||||||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||||||||||||||
| Carrying Value | Fair Value | Carrying Value | Fair Value | ||||||||||||||||||||
Long-term debt (a) | $ | 2,626 | $ | 2,662 | $ | 2,820 | $ | 2,934 | |||||||||||||||
Other short-term indebtedness (b) | — | — | 6 | 6 | |||||||||||||||||||
______________
(a)Aggregate value of “Long-term debt” and “Long-term debt, due within one year” presented on the Consolidated Balance Sheets.
(b)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
13. Postretirement Benefit Obligations
TES and certain subsidiaries sponsor postemployment benefits which include defined benefit pension plans, health and welfare postretirement plans (other postretirement benefit plans), and defined contribution plans.
The components of net periodic benefit costs for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
Postretirement benefits service cost (a) | $ | 1 | $ | — | $ | — | $ | 2 | $ | — | $ | 1 | ||||||||||||||||||||||||||||||||
| Interest cost | 17 | 8 | 9 | 33 | 8 | 27 | ||||||||||||||||||||||||||||||||||||||
| Expected return on plan assets | (17) | (8) | (11) | (35) | (8) | (33) | ||||||||||||||||||||||||||||||||||||||
| Amortization of: | ||||||||||||||||||||||||||||||||||||||||||||
| Net loss | — | — | 1 | — | — | 2 | ||||||||||||||||||||||||||||||||||||||
Postretirement benefit (gain) loss, net (b) | — | — | (1) | (2) | — | (4) | ||||||||||||||||||||||||||||||||||||||
| Net periodic defined benefit cost (credit) | $ | 1 | $ | — | $ | (1) | $ | — | $ | — | $ | (3) | ||||||||||||||||||||||||||||||||
_____________
(a)Activity presented as “Operation, maintenance and development” on the Consolidated Statements of Operations.
(b)Activity presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
See Note 10 for additional information on recently resolved litigation regarding certain of our defined benefit pension obligations.
In March 2024, $10 million of excess assets from the PA Mines UMWA Plan VEBA were transferred to a separate VEBA which provides benefits for participants in Talen’s health and welfare “wrap plan.” As such assets were not presented on the Consolidated Balance Sheets prior to the transfer of the assets from the VEBA, a transfer gain of $10 million was recognized for the six months ended June 30, 2024 (Successor) and presented as “Other non-operating income (expense), net” on the Consolidated of Operations.
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14. Earnings Per Share
Basic EPS is computed by dividing net income (loss) by the weighted average number of shares of common stock outstanding during the applicable period. Diluted EPS is computed by dividing income by the weighted-average number of shares of common stock outstanding, increased by incremental shares that would be outstanding if potentially dilutive non-participating securities were converted to common stock as calculated using the treasury stock method. EPS for the periods were:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Numerator: (Millions of Dollars) | ||||||||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 458 | $ | 31 | $ | 419 | $ | 777 | $ | 31 | $ | 465 | ||||||||||||||||||||||||||||||||
| Less: | ||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) attributable to noncontrolling interest | 4 | 2 | (12) | 29 | 2 | (14) | ||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 454 | $ | 29 | $ | 431 | $ | 748 | $ | 29 | $ | 479 | ||||||||||||||||||||||||||||||||
| Denominator: (Thousands) | ||||||||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Basic | 57,434 | 59,029 | — | 58,119 | 59,029 | — | ||||||||||||||||||||||||||||||||||||||
| Warrants | 268 | 32 | — | 234 | 32 | — | ||||||||||||||||||||||||||||||||||||||
| Restricted stock units | 332 | 28 | — | 262 | 28 | — | ||||||||||||||||||||||||||||||||||||||
| Performance stock units | 1,741 | — | — | 1,654 | — | — | ||||||||||||||||||||||||||||||||||||||
| Weighted-Average Number of Common Shares Outstanding - Diluted | 59,775 | 59,088 | — | 60,269 | 59,088 | — | ||||||||||||||||||||||||||||||||||||||
| Earnings per Share - Basic | $ | 7.90 | $ | 0.49 | N/A | $ | 12.87 | $ | 0.49 | N/A | ||||||||||||||||||||||||||||||||||
| Earnings per Share - Diluted | 7.60 | 0.49 | N/A | 12.41 | 0.49 | N/A | ||||||||||||||||||||||||||||||||||||||
15. Stockholders' Equity
Common Stock Transactions
In May 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion. See Note 16 in Notes to the Annual Financial Statement for more information on the Company’s share repurchase program.
In the six months ended June 30, 2024, the Company repurchased a total of 5,773,889 shares of the Company’s common stock, of which 5,275,862 shares were repurchased in a tender offer, at a weighted average price of $114.48 per share, for an aggregate purchase price of $661 million, inclusive of transaction costs and excise taxes. The shares repurchased in the tender offer represented 9% of the Company’s outstanding common stock.
In June 2024, the Company retired 5,768,862 shares of treasury stock at a weighted average price of $114.58 per share with a carrying value of $661 million. The retired shares are now included in the pool of authorized but unissued shares. As of June 30, 2024 (Successor), the company had 53,254,954 shares outstanding.
In July 2024, the Company repurchased 2,413,793 shares of the Company’s common stock from affiliates of Rubric Capital Management LP at a price of $116.00 per share, for an aggregate purchase price of $280 million and retired the shares. There were de minimis transaction costs associated with this repurchase.
In July 2024, a former executive exercised equity-classified warrants to 457,142 shares of the Company’s common stock in a non-cash transaction. After giving effect to the non-cash exercise and related tax withholding, the Company issued 160,289 shares of the Company’s common stock.
32
Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||
| Beginning balance | $ | (23) | $ | — | $ | (167) | ||||||||||||||
| Gains (losses) arising during the period | 1 | (6) | 6 | |||||||||||||||||
Reclassifications to Consolidated Statements of Operations (a) | (12) | 1 | 5 | |||||||||||||||||
| Income tax benefit (expense) | 5 | 2 | (5) | |||||||||||||||||
| Other comprehensive income (loss) | (6) | (3) | 6 | |||||||||||||||||
| Accumulated other comprehensive income (loss) | $ | (29) | $ | (3) | $ | — | ||||||||||||||
_____________
(a)Primarily reclassification to “Nuclear decommission trust fund gain (loss), net”.
The components of AOCI, net of tax, at June 30 were:
| Successor | Predecessor | |||||||||||||
| 2024 | 2023 | |||||||||||||
| Available-for-sale securities unrealized gain (loss), net | $ | (1) | $ | (3) | ||||||||||
| Postretirement benefit actuarial gain (loss), net | (28) | — | ||||||||||||
| Accumulated other comprehensive income (loss) | $ | (29) | $ | (3) | ||||||||||
The postretirement obligations components of AOCI are not presented in their entirety on the Consolidated Statements of Operations during the periods; rather, they are included in the computation of net periodic defined benefit costs (credits). See Note 13 for additional information.
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16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods were:
| Successor | Predecessor | |||||||||||||||||||
| Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||
Cash paid (received) during the period | ||||||||||||||||||||
Interest and other finance charges, net of capitalized interest (a) | $ | 124 | $ | 2 | $ | 283 | ||||||||||||||
| Income taxes, net | 9 | 3 | 7 | |||||||||||||||||
| Non-cash investing and operating activities | ||||||||||||||||||||
| Capital expenditure accrual increase (decrease) | (16) | 1 | (28) | |||||||||||||||||
| Depreciation, amortization and accretion included on the Statements of Operations: | ||||||||||||||||||||
| Depreciation, amortization and accretion | 150 | 28 | 200 | |||||||||||||||||
Amortization of deferred finance costs and original issuance discounts (interest expense) (b) | 2 | 1 | 8 | |||||||||||||||||
| Other | (8) | (2) | — | |||||||||||||||||
| Total depreciation, amortization and accretion | $ | 144 | $ | 27 | $ | 208 | ||||||||||||||
| Non-cash financing/investing activities | ||||||||||||||||||||
Non-cash increase to PP&E and decrease to other current assets for transfer of miners by Cumulus Coin (b) | $ | — | $ | — | 14 | |||||||||||||||
| Non-cash decrease to PP&E and decrease to noncontrolling interest for transfer of miners to TeraWulf | — | — | 3 | |||||||||||||||||
Non-cash increase to PP&E and increase to noncontrolling interest for transfer of miners by TeraWulf (b) | — | — | 38 | |||||||||||||||||
| Unrealized (gain) loss on derivatives: | ||||||||||||||||||||
| Commodity contracts | 44 | (41) | 63 | |||||||||||||||||
| Interest rate swap contracts | (8) | 2 | 2 | |||||||||||||||||
| Total unrealized (gain) loss on derivatives | $ | 36 | $ | (39) | $ | 65 | ||||||||||||||
| Operating activities reconciliation adjustments, other: | ||||||||||||||||||||
| Net periodic defined benefit cost | $ | — | $ | 1 | $ | (3) | ||||||||||||||
| Stock-based compensation | 16 | — | — | |||||||||||||||||
| Derivative option premium amortization | 4 | 9 | 29 | |||||||||||||||||
| Bitcoin revenue | (71) | (15) | (27) | |||||||||||||||||
| Nonrecourse paid-in-kind interest | — | 3 | 9 | |||||||||||||||||
| Mark-to-market on warrants | — | 14 | — | |||||||||||||||||
| Debt restructuring (gain) loss, net | (8) | — | — | |||||||||||||||||
| Other | 1 | 5 | (1) | |||||||||||||||||
Total | $ | (58) | $ | 17 | $ | 7 | ||||||||||||||
(a)Capitalized interest totaled $3 million for the six months ended June 30, 2024 (Successor); $3 million for May 18 through June 30, 2023 (Successor); and $12 million for January 1 through May 17, 2023 (Predecessor).
(b)In 2023, each of the joint venture partners of Nautilus made non-cash contributions to Nautilus of cryptocurrency miners that increased PP&E.
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Cash and Restricted Cash
The following provides a reconciliation of “Cash and cash equivalents” and “Restricted cash and cash equivalents” presented on the Consolidated Statements of Cash Flows to line items within the Consolidated Balance Sheets:
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Cash and cash equivalents | $ | 632 | $ | 400 | |||||||
| Restricted cash and cash equivalents: | |||||||||||
| TES TLC debt restricted deposits | 472 | 472 | |||||||||
| Nautilus project restricted deposits | 8 | 10 | |||||||||
| Commodity exchange margin deposits | 2 | — | |||||||||
| Cumulus Digital Holdings restricted deposits | 1 | 19 | |||||||||
| Restricted cash and cash equivalents | 483 | 501 | |||||||||
Total | $ | 1,115 | $ | 901 | |||||||
17. Acquisitions and Divestitures
Completed Divestitures
ERCOT Sale. In March 2024, the Company and CPS Energy entered into an agreement for CPS Energy to acquire the Company’s 1,710 MW Texas generation portfolio located within the ERCOT market for $785 million, subject to customary net working capital adjustments. The sale closed in May 2024. A gain on sale of $563 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Cumulus Data Campus Sale. In March 2024, AWS purchased substantially all the assets of Cumulus Data and certain other assets for gross proceeds of $650 million. Gross proceeds of $350 million were initially received at closing with the remaining $300 million of variable consideration, presented as “Other current assets” on the Consolidated Balance Sheets, expected to be received from escrow at the completion of certain development milestones. Cumulus Digital Holdings distributed $109 million of the initial net proceeds from the sale to its members, including $108 million to TES.
In connection with the Cumulus Data Campus Sale, the Company entered into a power purchase agreement with AWS, pursuant to which (i) the Company agreed to supply up to 960 MW of long-term, carbon-free power to the Cumulus Data Campus from Susquehanna; (ii) the parties agreed to fixed-price power commitments that increase in 120 MW increments over several years; and (iii) AWS, under certain conditions, has the option to cap their commitments at 480 MW. AWS also became lessor under the ground lease agreement with Nautilus.
For the six months ended June 30, 2024 (Successor), a $324 million net gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Pennsylvania Minerals Divestiture. In March 2023, Talen sold certain mineral interests located in Pennsylvania for $29 million, while preserving the right to certain royalty payments from existing and future producing natural gas wells. For the period from January 1 through May 17, 2023 (Predecessor), a $29 million gain was presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Western Gas Book Divestiture. In April 2023, Talen sold certain contracts relating to the transportation of natural gas in the southwestern United States for approximately $15 million. For the period from January 1 through May 17, 2023 (Predecessor), a $15 million gain was presented as “Gain (loss) on sale of assets, net” on the Condensed Consolidated Statements of Operations.
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Acquisition of Noncontrolling Interests
In March 2024, TES acquired all of the equity units of Cumulus Digital Holdings held by affiliates of Orion and two former members of Talen senior management in exchange for an aggregate of $39 million. Following these transactions, TES owns 100% of the equity of Cumulus Digital Holdings.
18. Segments
Talen’s operating segments are based on the market areas in which our generation facilities operate and reflect the manner in which our chief operating decision maker review results and allocate resources. Adjusted EBITDA is the key profit metric used to measure financial performance of each segment. Total assets or other asset metrics are not considered a key metric or reviewed by the chief operating decision makers.
“PJM” is engaged in electricity generation, marketing activities, commodity risk and fuel management within the PJM RTO or ISO markets and is comprised of Susquehanna and Talen’s natural gas and coal generation facilities.
“Other” represents a non-reportable segment that includes the operating and marketing activities of Talen Montana’s proportionate share of the Colstrip Units in the WECC market, the operating activities of Nautilus, and other non-material operating and development activities. The Other segment also included the operating activities of our Texas power generation facilities in the ERCOT market prior to their disposal in May 2024. We have determined it appropriate to aggregate results of Talen’s remaining non-reportable segments and other operating activities.
“Corporate and Eliminations” represents a non-reportable segment represents the remaining grouping that includes: (i) General and administrative expenses incurred by our corporate and commercial functions that are not allocated to our reportable segments; (ii) other non-material components that are not regularly reviewed by our chief operating decision maker; and (iii) intercompany eliminations. This grouping is presented to reconcile the reportable segments to our consolidated results.
Financial data for the segments and reconciliation to consolidated results are:
| PJM | Other | Corporate and Eliminations | Total | ||||||||||||||||||||
| Three Months Ended June 30, 2024 (Successor) | |||||||||||||||||||||||
| Operating revenues | $ | 438 | $ | 58 | $ | (7) | $ | 489 | |||||||||||||||
| Interest expense | — | — | 62 | 62 | |||||||||||||||||||
| Capital expenditures | 14 | — | — | 14 | |||||||||||||||||||
| Adjusted EBITDA | 95 | 5 | 100 | ||||||||||||||||||||
| May 18 through June 30, 2023 (Successor) | |||||||||||||||||||||||
| Operating revenues | $ | 355 | $ | (30) | $ | (24) | $ | 301 | |||||||||||||||
| Interest expense | — | — | 33 | 33 | |||||||||||||||||||
| Capital expenditures | 23 | 10 | 1 | 34 | |||||||||||||||||||
| Adjusted EBITDA | 72 | 21 | 93 | ||||||||||||||||||||
| April 1 through May 17, 2023 (Predecessor) | |||||||||||||||||||||||
| Operating revenues | $ | 78 | $ | 81 | $ | (22) | $ | 137 | |||||||||||||||
| Interest expense | — | — | 59 | 59 | |||||||||||||||||||
| Capital expenditures | 38 | 19 | — | 57 | |||||||||||||||||||
| Adjusted EBITDA | 44 | 3 | 47 | ||||||||||||||||||||
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| PJM | Other | Corporate and Eliminations | Total | ||||||||||||||||||||
| Six Months Ended June 30, 2024 (Successor) | |||||||||||||||||||||||
| Operating revenues | $ | 871 | $ | 208 | $ | (81) | $ | 998 | |||||||||||||||
| Interest expense | — | — | 121 | 121 | |||||||||||||||||||
| Capital expenditures | 66 | 14 | — | 80 | |||||||||||||||||||
| Adjusted EBITDA | 375 | 43 | 418 | ||||||||||||||||||||
| May 18 through June 30, 2023 (Successor) | |||||||||||||||||||||||
Operating revenues | $ | 355 | $ | (30) | $ | (24) | $ | 301 | |||||||||||||||
| Interest expense | — | — | 33 | 33 | |||||||||||||||||||
| Capital expenditures | 23 | 10 | 1 | 34 | |||||||||||||||||||
Adjusted EBITDA | 72 | 21 | 93 | ||||||||||||||||||||
| January 1 through May 17, 2023 (Predecessor) | |||||||||||||||||||||||
| Operating revenues | $ | 1,054 | $ | 193 | $ | (37) | $ | 1,210 | |||||||||||||||
| Interest expense | — | — | 163 | 163 | |||||||||||||||||||
| Capital expenditures | 132 | 53 | 2 | 187 | |||||||||||||||||||
| Adjusted EBITDA | 688 | 37 | 725 | ||||||||||||||||||||
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Adjusted EBITDA: | ||||||||||||||||||||||||||||||||||||||||||||
| PJM | $ | 95 | $ | 72 | $ | 44 | $ | 375 | $ | 72 | $ | 688 | ||||||||||||||||||||||||||||||||
| Other | 5 | 21 | 3 | 43 | 21 | 37 | ||||||||||||||||||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 100 | $ | 93 | $ | 47 | $ | 418 | $ | 93 | $ | 725 | ||||||||||||||||||||||||||||||||
| Reconciling Items: | ||||||||||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | (62) | (33) | (59) | (121) | (33) | (163) | ||||||||||||||||||||||||||||||||||||||
| Income tax benefit (expense) | (112) | (19) | (198) | (181) | (19) | (212) | ||||||||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | (75) | (28) | (68) | (150) | (28) | (200) | ||||||||||||||||||||||||||||||||||||||
| Nuclear fuel amortization | (28) | (25) | (9) | (63) | (25) | (33) | ||||||||||||||||||||||||||||||||||||||
| Reorganization gain (loss), net | — | — | 838 | — | — | 799 | ||||||||||||||||||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | 91 | 41 | (94) | (44) | 41 | (63) | ||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 27 | 39 | 11 | 102 | 39 | 57 | ||||||||||||||||||||||||||||||||||||||
| Stock-based compensation expense | (8) | (16) | — | (16) | (16) | — | ||||||||||||||||||||||||||||||||||||||
| Long-term incentive compensation expense | (6) | — | — | (16) | — | — | ||||||||||||||||||||||||||||||||||||||
| Gain (loss) on asset sales, net | 561 | — | 15 | 885 | — | 50 | ||||||||||||||||||||||||||||||||||||||
| Non-cash impairments | — | — | (16) | — | — | (381) | ||||||||||||||||||||||||||||||||||||||
| Operational and other restructuring activities | (19) | (12) | (9) | (21) | (12) | (17) | ||||||||||||||||||||||||||||||||||||||
| Development expenses | — | (2) | (3) | — | (2) | (10) | ||||||||||||||||||||||||||||||||||||||
| Non-cash inventory net realizable value, obsolescence, and other charges | (2) | (3) | (32) | (3) | (3) | (56) | ||||||||||||||||||||||||||||||||||||||
| Noncontrolling interest | 7 | 8 | 9 | 18 | 8 | 14 | ||||||||||||||||||||||||||||||||||||||
| Other items | (3) | 2 | (1) | 11 | 2 | (15) | ||||||||||||||||||||||||||||||||||||||
| Corporate and Eliminations | (13) | (14) | (12) | (42) | (14) | (30) | ||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 458 | $ | 31 | $ | 419 | $ | 777 | $ | 31 | $ | 465 | ||||||||||||||||||||||||||||||||
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ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Interim Financial Statements, the Annual Financial Statements, and their accompanying notes. In addition, the following discussion contains forward-looking statements, which involve risks and uncertainties. See “Cautionary Note Regarding Forward-Looking Information” for additional information on forward-looking statements. Capitalized terms and abbreviations are defined in the glossary. Dollars are in millions, unless otherwise noted.
Overview
Talen owns and operates power infrastructure in the United States. We produce and sell electricity, capacity, and ancillary services into wholesale power markets in the United States primarily in PJM and WECC, with our generation fleet principally located in the Mid-Atlantic region of the United States and Montana. The majority of our generation is produced at our zero-carbon nuclear and lower-carbon gas-fired facilities. As of June 30, 2024 (Successor), our generation capacity was 10,665 MW (summer rating). Talen is headquartered in Houston, Texas.
Recent Developments
Common Stock Transactions
In the six months ended June 30, 2024 (Successor), the company repurchased a total of 5,773,889 shares of the Company’s common stock under the share repurchase program for an aggregate purchase price of $661 million, inclusive of transaction costs and excise taxes, at a weighted average per share price of $114.48. Of the total shares repurchased, 5,275,862 shares were the result of the tender offer executed in June 2024.
In June 2024, the Company retired 5,768,862 shares of treasury stock repurchased during the six months ended June 30, 2024 (Successor).
In July 2024, the Company repurchased 2,413,793 shares from affiliates of Rubric Capital Management LP at a purchase price of $116.00 per share for an aggregate purchase price of $280 million and retired the shares. There were de minimis transaction costs associated with this repurchase.
In July 2024, a former executive exercised equity-classified warrants to 457,142 shares of the Company’s common stock in a non-cash transaction. After giving effect to tax impacts, the Company issued 160,289 shares of the Company’s common stock.
As of August 13, 2024, the Company has 51,001,450 shares of common stock outstanding.
See Note 15 in Notes to the Interim Financial Statements for more information related to share repurchases and the retirement of treasury stock.
PJM 2025/2026 Base Residual Auction
In July 2024, PJM reported the results of the PJM Base Residual Auction for the 2025/2026 planning year. Talen cleared a total of 6,820 MW at a clearing price of $269.92 per MW-day for the MAAC, PPL, and PSEG locational deliverability areas.
Remarketing of PEDFA Bonds
In June 2024, the Company completed the remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $81 million in aggregate principal amount of its PEDFA 2009C Bonds. The bonds will bear interest at 5.25% until the end of the new term rate period on June 1, 2027. In connection with the remarketing, $133 million of LCs issued under the TLC LCF that had previously supported the bonds were terminated, providing the Company with increased LC capacity under the TLC LCF.
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Term Loan Repricing
In May 2024, the Company completed a repricing transaction with respect to the TLB and TLC. The new rate applicable to the TLB and TLC is SOFR plus 350 basis points, which reduces the interest rate margin by 100 basis points. The applicable SOFR floor was reduced from 50 to 0 basis points. Additionally, in connection with the repricing, the lenders under the TLB and TLC agreed to: (i) waive any mandatory prepayment obligations in connection with the ERCOT Sale; and (ii) certain other amendments permitting Talen additional capacity for dispositions, restricted payments and investments under the Credit Agreement.
ERCOT Sale
In March 2024, the Company and CPS Energy entered into an agreement for CPS Energy to acquire the Company’s 1,710 MW Texas generation portfolio located within the ERCOT market for $785 million, subject to customary net working capital adjustments. The sale closed in May 2024. A net gain of $563 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations.
Factors Affecting Our Financial Condition and Results of Operations
Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information” and Notes 3 and 10 in Notes to the Interim Financial Statements for additional information on our risks.
Generation Facility Updates
Reliability Impact Assessments. In the first quarter 2023, the project to convert Brandon Shores’ fuel source from coal to fuel oil was canceled for economic reasons, which resulted in non-cash impairment charges related to property, plant, and equipment and inventories. In April 2023, Brandon Shores notified PJM that it will deactivate electric generation on June 1, 2025. In June 2023, PJM notified Brandon Shores that its generation Units 1 and 2 are needed for transmission reliability. In October 2023, for economic reasons, the Company provided a notice to PJM that it intends to deactivate H.A. Wagner on June 1, 2025. In January 2024, PJM notified H.A Wagner that its generation Units 3 and 4 are needed for transmission reliability.
Each generation facility has filed a cost-of-servicer rate schedule at FERC, which was accepted in June 2024, subject to refund. Additionally, an administrative settlement judge was appointed in June 2024 and settlement proceedings have commenced. No assurance can be provided as to when, if at all, a final rate schedule will be approved by FERC or how the rate schedule and resulting revenues may be modified in the course of settlement judge procedures, or, should they be necessary, in the course of any subsequent evidential hearing. See Note 8 in Notes to the Interim Financial Statements for additional information on the reliability assessments and additional information on the Brandon Shores impairment.
Commodity Markets
The following tables summarize average on-peak power prices and natural gas prices for the PJM market for the three months ended June 30, 2024 (Successor) and 2023 (Predecessor). During the second quarter of 2024, natural gas prices for Texas Eastern M-3 settled below its ten-year average resulting from storage levels above the five-year range and ample supply. In PJM, higher than normal temperatures during the quarter contributed to increased power load resulting in higher settled on-peak power prices compared to the same period in the prior year.
PJM. The average settled market prices for the three months ended June 30 were:
| 2024 | 2023 | ||||||||||
| PJM West Hub Day Ahead Peak - $/MWh | $ | 37.67 | $ | 35.40 | |||||||
| PJM PPL Zone Day Ahead Peak - $/MWh | 28.34 | 25.97 | |||||||||
| PJM BGE Zone Day Ahead Peak - $/MWh | 45.10 | 42.70 | |||||||||
| Texas Eastern M-3 - $/MMBtu | 1.53 | 1.50 | |||||||||
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The PJM West Hub Day Ahead Peak 2024 quarter average settled prices increased approximately 6% compared to the prior year.
The weighted average forward market prices for the periods from July 1 through December 31 as of June 30:
| 2024 | 2023 | ||||||||||
| PJM West Hub ATC - $/MWh | $ | 43.64 | $ | 37.48 | |||||||
| Texas Eastern M-3 - $/MMBtu | 2.14 | 2.19 | |||||||||
PJM West Hub ATC Spark Spreads (a) | 28.64 | 22.13 | |||||||||
__________________
(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 gas prices, and a heat rate of 7 MMBtu/MWh.
Capacity Markets
Our generation capacity is located 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, ISO demand forecasts, reserve margin targets and adjustments to PJM MSOC as determined by the PJM IMM.
PJM Capacity Auctions. Under the RPM, PJM conducts a series of capacity auctions. Most capacity is procured in the auctions conducted each May for the delivery of generation capacity for the PJM Capacity Year, which is three years from the date of the auction. Capacity auctions have recently been delayed, resulting in the auctions being held with less than 3 years between the auctions and the PJM Capacity Year, with the most recent auction held in July 2024. The capacity market construct provides generation owners the opportunity for some revenue visibility on a multiyear basis. The results of each of these auctions impacts Talen's capacity revenues in the specific PJM Capacity Year.
See “Capacity Prices” below for additional information on capacity prices and see Note 10 in Notes to the Interim Financial Statements for additional information on the PJM RPM and other PJM matters.
Capacity Prices. The following table displays the PJM Base Residual Auction’s cleared capacity prices for the markets and zones in which we primarily operate:
2025/2026 (b) | 2024/2025 | 2023/2024 | 2022/2023 | ||||||||||||||||||||
PJM Capacity Performance ($/MW-day) (a) | |||||||||||||||||||||||
| MAAC | $ | 269.92 | $ | 49.49 | $ | 49.49 | $ | 95.79 | |||||||||||||||
| PPL | 269.92 | 49.49 | 49.49 | 95.79 | |||||||||||||||||||
(a)Displayed prices are from the applicable market publications.
(b)2025/2026 prices were released on July 30, 2024.
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Nuclear Production Tax Credit
The Inflation Reduction Act of 2022 was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code of 1986 to create a Nuclear PTC program.
The Nuclear PTC program provides qualified nuclear power generation facilities with a $3 per MWh transferable credit for electricity produced and sold to an unrelated party during each tax year. Electricity produced and sold by Susquehanna after December 31, 2023 through December 31, 2032 will qualify for the credit, which is subject to potential adjustments. Such adjustments include inflation escalators, a five-times increase in tax credit value (to $15 per MWh) if the qualifying generation facility meets prevailing wage requirements, and a pro-rata decrease in tax credit value once the annual gross receipts of a qualifying generation facility exceeds $25 per MWh. As the credit is eliminated when the annual gross receipts are equivalent to $43.75 per MWh (adjusted for inflation), the Nuclear PTC program is expected to create a minimum price Susquehanna is expected to receive for its generation. Susquehanna generated approximately 18 million MWh in each of the calendar years 2023, 2022 and 2021.
The credit would be:
| Annual Gross Receipts | Credit Amount | |||||||
| $25 per MWh or less | $15 per MWh | |||||||
| Greater than $25 per MWh | Ratably reduced until gross receipts equal $43.75 per MWh, $0 after that threshold | |||||||
The Inflation Reduction Act’s provisions are subject to implementation regulations, whose terms are not yet known. No assurance can be provided as to the magnitude of the benefit to Susquehanna as the Inflation Reduction Act’s provisions, including the computations of the Nuclear PTC, are subject to implementation regulations. As such, Talen cannot fully predict the realization of any minimum price for Susquehanna’s generation and (or) impacts to Talen’s liquidity or results of operations. See Note 4 in Notes 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 by weather. As a result, our operating results in the future may fluctuate substantially on a seasonal basis. For example, a lack of sustained cold weather in the Mid-Atlantic region may suppress regional natural gas prices and reduce our future capacity and energy revenues. Alternatively, above-average temperatures in the summer tend to increase summer cooling electricity demand, energy prices and revenues, and below-average temperatures in the winter tend to increase winter heating electricity demand, energy prices and revenues. Inversely, the milder weather during spring and fall tend to decrease the need for both cooling electricity demand and heating electricity demand. In addition, our operating expenses typically fluctuate on a seasonal basis, with peak power generation during the winter in the Mid-Atlantic region.
We ordinarily perform facility maintenance during lower or non-peak demand periods to ensure reliability during periods of peak usage. The pattern of the fluctuations in our operating results varies depending on the type and location of the power generation facilities being serviced, capacity markets served, the maintenance requirements of our facilities and the terms of bilateral contracts to purchase or sell electricity. The largest recurring maintenance project is the annual spring refueling outage at Susquehanna. The outages normally occur during late March and into April each year. Susquehanna Unit 1 entered its spring refueling outage on March 25, 2024 and successfully completed the outage on April 25, 2024.
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Results of Operations
The results of operations presented below should be reviewed in conjunction with the Interim Financial Statements, the Annual Financial Statements, and their respective notes. Our financial results for the three months ended June 30, 2024, the six months ended June 30, 2024, and for the period May 18 through June 30, 2023 are referred to as the “Successor” periods. Our financial results for the period April 1 through May 17, 2023 and for the period from January 1 through May 17, 2023 are referred to as the “Predecessor” periods. The operating results for the three and six months ended June 30, 2024 cannot be adequately compared with any of the previous periods reported in the Interim Financial Statements or Annual Financial Statements. 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 revenues relate to sales to an ISO or RTO, sales under wholesale bilateral contracts or realized hedging activity, 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.
In addition, unrealized gains (losses) on derivatives instruments resulting from changes in fair value during the period and are presented separately as revenues within “Operating Revenues” and expenses within “Total Energy Expenses” in the Interim Financial Statements. We evaluate them collectively because they represent the changes in fair value of Talen’s economic hedging activities.
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Results for the Three Months Ended June 30, 2024 (Successor), May 18 through June 30, 2023 (Successor), and January 1 through May 17, 2023 (Predecessor)
The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:
| Successor | Predecessor | |||||||||||||||||||
| (Millions of Dollars, except share data) | Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | |||||||||||||||||
| Capacity revenues | $ | 46 | $ | 26 | $ | 42 | ||||||||||||||
| Energy and other revenues | 367 | 188 | 180 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 76 | 87 | (85) | |||||||||||||||||
| Operating Revenues | 489 | 301 | 137 | |||||||||||||||||
| Fuel and energy purchases | (163) | (57) | (69) | |||||||||||||||||
| Nuclear fuel amortization | (28) | (25) | (9) | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | 15 | (46) | (9) | |||||||||||||||||
| Energy Expenses | (176) | (128) | (87) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (164) | (69) | (108) | |||||||||||||||||
| General and administrative | (40) | (18) | (22) | |||||||||||||||||
| Depreciation, amortization and accretion | (75) | (28) | (68) | |||||||||||||||||
| Impairments | — | — | (16) | |||||||||||||||||
| Operational restructuring | (1) | — | — | |||||||||||||||||
| Other operating income (expense), net | (6) | (3) | (28) | |||||||||||||||||
| Operating Income (Loss) | 27 | 55 | (192) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 27 | 39 | 11 | |||||||||||||||||
| Interest expense and other finance charges | (62) | (33) | (59) | |||||||||||||||||
| Reorganization income (expense), net | — | — | 838 | |||||||||||||||||
| Gain (loss) on sale of assets, net | 561 | — | 15 | |||||||||||||||||
| Other non-operating income (expense), net | 17 | (11) | 4 | |||||||||||||||||
| Income (Loss) Before Income Taxes | 570 | 50 | 617 | |||||||||||||||||
| Income tax benefit (expense) | (112) | (19) | (198) | |||||||||||||||||
| Net Income (Loss) | 458 | 31 | 419 | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 4 | 2 | (12) | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 454 | $ | 29 | $ | 431 | ||||||||||||||
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Successor Period — Three Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders totaled $454 million for the three months ended June 30, 2024 (Successor). Results were driven by:
•Capacity Revenues totaled $46 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2024/2025 and 2023/2024 delivery periods.
•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $204 million. This primarily consisted of: (i) $271 million in third-party wholesale electricity sales and ancillary revenues; (ii) $72 million in other revenue primarily related to Nautilus operations and Nuclear PTC; and (iii) $17 million in net realized gains from hedging activities. Such amounts were partially offset by $(155) million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $91 million gain, net. This consisted of: (i) unrealized gains incurred as a result of decreases in forward power prices; and (ii) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
•Nuclear Fuel Amortization totaled $(28) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $8 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence.
•Operation, Maintenance, and Development totaled $(164) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies costs.
•Depreciation, Amortization and Accretion totaled $(75) million. This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $27 million. This consisted of realized gains and losses on debt and equity securities, unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Interest Expense and Other Finance Charges totaled $(62) million. This primarily consisted of interest expense incurred on the Secured Notes and Term Loans.
•Gain (loss) on Sale of Assets, net totaled $561 million This is primarily related to the ERCOT Sale that closed in May 2024. See Note 17 in Notes to the Interim Financial Statements for additional information.
•Other Non-operating Income (Expense), net totaled $17 million. This is primarily related to interest income.
•Income Tax Benefit (Expense) totaled $(112) million. This primarily consisted of federal and state income taxes, effects of permanent nondeductible items, trust tax on the nuclear decommissioning trust income, and changes in the valuation allowance.
Successor Period — May 18 through June 30, 2023
See “Successor Period - May 18 through June 30, 2023” within “Results for the Six Months Ended June 30, 2024 (Successor)” below for a discussion of the results of operations for the above period.
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Predecessor Period — April 1 through May 17, 2023
Net Income (Loss) Attributable to Member totaled $431 million for the period April 1 through May 17, 2023. Results were driven by:
•Capacity Revenues totaled $42 million for the period and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $111 million. This consisted of: (i) $98 million in third-party wholesale electricity sales and ancillary revenues; (ii) $52 million in net realized gains from hedging activities; and (iii) $18 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(57) million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $(94) million. This consisted of: (i) unrealized losses incurred as a result of increases in forward power prices; coupled with (ii) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
•Nuclear Fuel Amortization totaled $(9) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment.
•Operation, Maintenance, and Development totaled $(108) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies costs.
•Depreciation, Amortization and Accretion totaled $(68) million. This consisted of the periodic expense of long-lived property, plant and equipment, and ARO accretion.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $11 million. This consisted of realized gains on debt and equity securities, unrealized losses on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Other Operating Income (Expense), net, totaled $(28) million, primarily due to fuel inventory net realizable value adjustment expense. See Note 6 in Notes to the Interim Financial Statements for additional information.
•Reorganization Income (Expense), net, totaled $838 million for the period, primarily due to the $1,459 million gain on debt discharge recognized upon Emergence, partially offset by a $460 million loss on revaluation adjustments. See Note 2 in Notes to the Interim Financial Statements for additional information.
•Interest Expense and Other Finance Charges totaled $(59) million. This primarily consisted of interest expense incurred on prepetition debt and certain LC fees.
•Gain (loss) on Sale of Assets, net, totaled $15 million. This is primarily due to non-recurring sales during the period. See Note 17 in Notes to the Interim Financial Statements for additional information.
•Income Tax Benefit (Expense) totaled $(198) million. This primarily consisted of federal and state income taxes, changes in the valuation allowance, and reorganization adjustments.
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Results for the Six Months Ended June 30, 2024 (Successor), May 18 through June 30, 2023 (Successor), and January 1 through May 17, 2023 (Predecessor)
The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:
| Successor | Predecessor | |||||||||||||||||||
| (Millions of Dollars, except share data) | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||
| Capacity revenues | $ | 91 | $ | 26 | $ | 108 | ||||||||||||||
| Energy and other revenues | 939 | 188 | 1,042 | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (32) | 87 | 60 | |||||||||||||||||
| Operating Revenues | 998 | 301 | 1,210 | |||||||||||||||||
| Fuel and energy purchases | (313) | (57) | (176) | |||||||||||||||||
| Nuclear fuel amortization | (63) | (25) | (33) | |||||||||||||||||
| Unrealized gain (loss) on derivative instruments | (12) | (46) | (123) | |||||||||||||||||
| Energy Expenses | (388) | (128) | (332) | |||||||||||||||||
| Operating Expenses | ||||||||||||||||||||
| Operation, maintenance and development | (318) | (69) | (285) | |||||||||||||||||
| General and administrative | (83) | (18) | (51) | |||||||||||||||||
| Depreciation, amortization and accretion | (150) | (28) | (200) | |||||||||||||||||
| Impairments | — | — | (381) | |||||||||||||||||
| Operational restructuring | (1) | — | — | |||||||||||||||||
| Other operating income (expense), net | (6) | (3) | (37) | |||||||||||||||||
| Operating Income (Loss) | 52 | 55 | (76) | |||||||||||||||||
| Nuclear decommissioning trust funds gain (loss), net | 102 | 39 | 57 | |||||||||||||||||
| Interest expense and other finance charges | (121) | (33) | (163) | |||||||||||||||||
| Reorganization income (expense), net | — | — | 799 | |||||||||||||||||
| Gain (loss) on sale of assets, net | 885 | — | 50 | |||||||||||||||||
| Other non-operating income (expense), net | 40 | (11) | 10 | |||||||||||||||||
| Income (Loss) Before Income Taxes | 958 | 50 | 677 | |||||||||||||||||
| Income tax benefit (expense) | (181) | (19) | (212) | |||||||||||||||||
| Net Income (Loss) | 777 | 31 | 465 | |||||||||||||||||
| Less: Net income (loss) attributable to noncontrolling interest | 29 | 2 | (14) | |||||||||||||||||
| Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor) | $ | 748 | $ | 29 | $ | 479 | ||||||||||||||
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Successor Period — Six Months Ended June 30, 2024
Net Income (Loss) Attributable to Stockholders totaled $748 million for the six months ended June 30, 2024. Results were driven by:
•Capacity Revenues totaled $91 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 and 2024/2025 delivery period.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $626 million. This consisted of: (i) $600 million in third-party wholesale electricity sales and ancillary revenues; (ii) $150 million in other revenue primarily related to Nautilus operations and Nuclear PTC; and (iii) $182 million in net realized gains from hedging activities. Such amounts were partially offset by $(306) million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $(44) million loss, net. This consisted of: (i) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period; partially offset by (ii) unrealized gains incurred as a result of decreases in forward power prices.
•Nuclear Fuel Amortization totaled $(63) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $19 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence.
•Operation, Maintenance, and Development totaled $(318) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
•Depreciation, Amortization and Accretion totaled $(150) million This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $102 million. This consisted of realized gains and losses on debt and equity securities, unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Interest Expense and Other Finance Charges totaled $(121) million. This primarily consisted of interest expense incurred on the Secured Notes and Term Loans.
•Gain (Loss) on Sale of Assets, net totaled $885 million. This is primarily comprised of the $563 million gain from the ERCOT Sale that closed in May 2024 and the $324 million gain from the Cumulus Data Campus Sale that closed in March 2024. See Note 17 in Notes to the Interim Financial Statements for additional information.
•Other Non-operating Income (Expense), net, totaled $40 million. This is primarily due to interest income.
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Successor Period — May 18 through June 30, 2023
Net Income (Loss) Attributable to Stockholders totaled $29 million for the period from May 18 through June 30, 2023. Results were driven by:
•Capacity Revenues totaled $26 million and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2023/2024 and 2022/2023 delivery periods.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $131 million. This consisted of: (i) $136 million in third-party wholesale electricity sales and ancillary revenues; (ii) $16 million in net realized gains from hedging activities; and (iii) $15 million in other revenue primarily related to Nautilus operations. Such amounts were partially offset by $(36) million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $41 million gain, net. This consisted of unrealized gains incurred as a result of decreases in forward power prices.
•Nuclear Fuel Amortization totaled $(25) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $(14) million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence.
•Operation, Maintenance, and Development totaled $(69) million. This consisted of generation facility operating costs, including wages and benefits for employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies costs.
•Depreciation, Amortization and Accretion totaled $(28) million. This consisted of the periodic expense of long-lived property, plant and equipment and ARO accretion.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, totaled $39 million. This consisted of realized losses on debt and equity securities, unrealized gains on equity securities, dividends, and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Interest Expense and Other Finance Charges totaled $(33) million. This primarily consisted of interest expense incurred on prepetition debt and certain LC fees.
•Other Non-operating Income (Expense), net, totaled $(11) million, primarily due to mark-to-market adjustments for warrants issued in 2023.
•Income Tax Benefit (Expense) totaled $(19) million. This primarily consisted of federal and state income taxes and trust tax on nuclear decommissioning trust income.
Predecessor Period — January 1 through May 17, 2023
Net Income (Loss) Attributable to Member totaled $479 million for the period from January 1 through May 17, 2023. Results were driven by:
•Capacity Revenues totaled $108 million for the period and were primarily based on resource clearing prices received from the PJM Base Residual Auction for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $(13) million of net PJM capacity penalties related to Winter Storm Elliot.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $866 million for the period and consisted of $637 million in net realized gains from hedging activities, coupled with $343 million in third-party wholesale electricity sales and ancillary revenues and $27 million in other revenue, partially offset by $(141) million in fuel and purchased power costs. Other revenues relate to operations of Nautilus that commenced operations in February 2023.
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•Unrealized Gain (Loss) on Derivative Instruments totaled $(63) million loss, net. This consisted of (i) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period; partially offset by (ii) unrealized gains incurred as a result of decreases in forward power prices.
•Nuclear Fuel Amortization totaled $(33) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment.
•Operation, Maintenance, and Development totaled $(285) million for the period. This consisted of generation facility operating costs, including salary and benefit costs, the costs of removal, repairs and maintenance that are not capitalized, contractor costs and certain materials and supplies.
•Depreciation, Amortization and Accretion totaled $(200) million for the period and consisted of depreciation of long-lived property, plant and equipment, intangibles and accretion related to AROs. The period was impacted by new depreciation rates related to a change in useful lives for the generation facilities.
•Impairments totaled $(381) million in the period and primarily consisted of the assessment of Brandon Shores asset group recoverability associated with a decision to deactivate Brandon Shores on June 1, 2025. See Note 8 in Notes to the Interim Financial Statements for additional information.
•Other Operating Income (Expense), net, totaled $(37) million for the period, reflecting fuel inventory net realizable value adjustment expense. See Note 6 in Notes to the Interim Financial Statements for additional information.
•Nuclear Decommissioning Trust Funds Gain (Loss), net, was $57 million for the period. This consisted of realized gains and losses on debt and equity securities, unrealized gains on equity securities, dividends and interest income on investments in the NDT. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Interest Expense and Other Finance Charges totaled $(163) million for the period and primarily consisted of interest expense incurred on the Prepetition Secured Notes, Prepetition RCF, Prepetition TLB, LMBE-MC TLB and certain LC fees.
•Reorganization Income (Expense), net, totaled $799 million for the period, primarily due to the $1,459 million gain on debt discharge recognized upon Emergence partially offset by a $460 million loss on revaluation adjustments, $70 million in backstop commitment letters and $57 million in professional fees. See Note 2 in Notes to the Interim Financial Statements for additional information.
•Gain (loss) on Sale of Assets, net, totaled $50 million, primarily due to non-recurring sales during the period. See Note 17 in Notes to the Interim Financial Statements for additional information.
•Income Tax Benefit (Expense) totaled $(212) million for the period and was primarily related to federal/state income taxes, reorganization adjustments and changes in the valuation allowance. See Note 5 in Notes to the Interim Financial Statements for additional information.
49
Liquidity and Capital Resources
Our liquidity and capital requirements are generally a function of: (i) debt service requirements; (ii) capital expenditures; (iii) maintenance activities; (iv) liquidity requirements for our commercial and hedging activities, including cash collateral and other forms of credit support; (v) legacy environmental obligations; and (vi) other working capital requirements.
Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt 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 establishing 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 does not require cash collateral posting. 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. This strategy limits the use of exchange-based hedging and the associated margin requirements, which helps minimize collateral posting requirements. Additionally, there are lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC and significantly reduced debt service 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.
In June 2024, using available cash deposits, the Company completed a tender offer which resulted in the purchase of 5,275,862 shares of its common stock for $612 million, exclusive of transaction costs.
In July 2024, the Company repurchased $2,413,793 shares from affiliates of Rubric Capital Management LP for an aggregate purchase price of $280 million. There were de minimis transaction costs associated with this repurchase.
See Notes 3, 9 and 16 in Notes to the Interim Financial Statements for additional information regarding various liquidity topics discussed below.
Talen Liquidity
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Cash and cash equivalents, unrestricted | $ | 632 | $ | 400 | |||||||
| RCF | 640 | 638 | |||||||||
| Available liquidity | $ | 1,272 | $ | 1,038 | |||||||
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.
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Financial Performance Assurances
| Successor | |||||||||||
| June 30, 2024 | December 31, 2023 | ||||||||||
| Outstanding surety bonds | $ | 235 | $ | 240 | |||||||
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.
Forecasted Uses of Cash
See Management’s Discussion and Analysis of Financial Condition and Results of Operations in the Annual Financial Statements attached to the Registration Statement for information regarding forecasted uses of cash related to capital expenditures and forecasted spending on AROs and accrued environmental liabilities.
Indebtedness
Long-Term Debt Repricing. In May 2024, the Company completed a repricing of the TLB and TLC. The lenders agreed to, among other things lower the interest charges by 100 basis points and waive the prepayment obligation in connection with the ERCOT Sale.
Remarketing of PEDFA Bonds. In June 2024, the Company completed the remarketing of $50 million in aggregate principal amount of its PEDFA 2009B and $81 million in aggregate principal amount of its PEDFA 2009C Bonds. The bonds will bear interest at 5.25% until the end of the new term rate period on June 2027. In connection with the remarketing, $133 million of LCs issued under the TLC LCF that had previously supported the bonds were terminated, providing the Company with increased LC capacity under the TLC LCF.
See Note 11 in Notes to the Interim Financial Statements for additional information on the repricing and Talen’s indebtedness.
Cash Flow Activities
The net cash provided by (used in) operating, investing and financing activities for the six months ended June 30 were:
| Successor | Predecessor | |||||||||||||||||||
| Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | ||||||||||||||||||
| Operating activities | $ | 150 | $ | (1) | $ | 462 | ||||||||||||||
| Investing activities | 979 | (38) | (157) | |||||||||||||||||
| Financing activities | (915) | — | (539) | |||||||||||||||||
Successor Period — Six Months Ended June 30, 2024
•Operating Cash Flows. Cash provided by (used in) operating activities totaled $150 million. This primarily consisted of cash provided from operations of the Company.
•Investing Cash Flows. Cash provided by (used in) investing activities totaled $979 million. Talen received $339 million of initial net proceeds from the Cumulus Data Campus Sale in the first quarter of 2024 and $754 million of initial net proceeds from the ERCOT Sale in the second quarter of 2024. Partially offsetting these inflows were capital expenditures of $(90) million that primarily consisted of $(45) million for nuclear fuel expenditures. See Note 17 in Notes to the Interim Financial Statements for additional information on the Cumulus Data Campus Sale and the ERCOT Sale.
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•Financing Cash Flows. Cash provided by (used in) financing activities totaled $(915) million. This primarily consisted of $(182) million for the repayment of the Cumulus Digital TLF in the first quarter of 2024 using a portion of the proceeds from the Cumulus Data Campus Sale; $(39) million in the first quarter of 2024 for the repurchase of noncontrolling interests held by affiliates of Orion and two former members of Talen senior management; and $(654) million in the six months ended June 30, 2024 (Successor) to repurchase common stock shares. See “Recent Developments - Shares Repurchases” above for additional information on share repurchases. In addition, an outflow of $(28) million occurred to cash settle restricted stock units upon vesting.
Successor Period — May 18 through June 30, 2023
•Investing Cash Flows. Cash provided by (used in) investing activities totaled $(38) million and primarily consisted of capital expenditures. Capital expenditures outflows, including those for nuclear fuel, totaled $(34) million and consisted of: $(20) million for fuel conversion projects and Cumulus Data Campus project; and $(14) million related to nuclear fuel expenditures.
Predecessor Period — January 1 through May 17, 2023
•Operating Cash Flows. Cash provided by (used in) operating activities totaled $462 million and consisted of cash provided from the operations of the Company, including declines in accounts receivable, partially offset by payments made for accrued interest and other claims at Emergence.
•Investing Cash Flows. Cash provided by (used in) investing activities totaled $(157) million and consisted of capital expenditures offset by $46 million in proceeds from the sale of assets.
•Capital expenditures, including those for nuclear fuel, totaled $(187) million and consisted of: $(138) million across the Company for current projects including the Montour gas conversion project, the Cumulus Data Campus and Nautilus crypto mining projects and projects at Susquehanna; and $(49) million related to nuclear fuel expenditures.
•Financing Cash Flows. Cash provided by (used in) financing activities totaled $(539) million and consisted of the net effect of issuances and repayments of prepetition debt and make-whole premiums of about $(1.9) billion net cash outflow partially offset by $1.4 billion cash inflow for a contribution from member.
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 Note 10 in Notes to the Interim Financial Statements for additional information regarding guarantees.
Non-GAAP Financial Measure
We include Adjusted EBITDA, which the Company uses as a measure of its performance and is not a financial measure prepared under GAAP, in these Interim Financial Statements. 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, non-GAAP financial measures are numerical measures of financial performance, financial position, or cash flows that exclude (or include) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers of this financial information not to place undue reliance on this non-GAAP financial measure, but to also consider them along with their most directly comparable GAAP financial measure. Non-GAAP measures have limitations as an analytical tool and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.
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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 the Company’s 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; 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 credit facility 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 the 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.
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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:
| Successor | Predecessor | Successor | Predecessor | |||||||||||||||||||||||||||||||||||||||||
| Three Months Ended June 30, 2024 | May 18 through June 30, 2023 | April 1 through May 17, 2023 | Six Months Ended June 30, 2024 | May 18 through June 30, 2023 | January 1 through May 17, 2023 | |||||||||||||||||||||||||||||||||||||||
| Net Income (Loss) | $ | 458 | $ | 31 | $ | 419 | $ | 777 | $ | 31 | $ | 465 | ||||||||||||||||||||||||||||||||
Adjustments | ||||||||||||||||||||||||||||||||||||||||||||
| Interest expense and other finance charges | 62 | 33 | 59 | 121 | 33 | 163 | ||||||||||||||||||||||||||||||||||||||
| Income tax (benefit) expense | 112 | 19 | 198 | 181 | 19 | 212 | ||||||||||||||||||||||||||||||||||||||
| Depreciation, amortization and accretion | 75 | 28 | 68 | 150 | 28 | 200 | ||||||||||||||||||||||||||||||||||||||
| Nuclear fuel amortization | 28 | 25 | 9 | 63 | 25 | 33 | ||||||||||||||||||||||||||||||||||||||
Reorganization (gain) loss, net (a) | — | — | (838) | — | — | (799) | ||||||||||||||||||||||||||||||||||||||
| Unrealized (gain) loss on commodity derivative contracts | (91) | (41) | 94 | 44 | (41) | 63 | ||||||||||||||||||||||||||||||||||||||
| Nuclear decommissioning trust funds (gain) loss, net | (27) | (39) | (11) | (102) | (39) | (57) | ||||||||||||||||||||||||||||||||||||||
Stock-based compensation expense | 8 | 16 | — | 16 | 16 | — | ||||||||||||||||||||||||||||||||||||||
| Long-term incentive compensation expense | 6 | — | — | 16 | — | — | ||||||||||||||||||||||||||||||||||||||
(Gain) loss on asset sales, net (b) | (561) | — | (15) | (885) | — | (50) | ||||||||||||||||||||||||||||||||||||||
Non-cash impairments (c) | — | — | 16 | — | — | 381 | ||||||||||||||||||||||||||||||||||||||
Operational and other restructuring activities | 19 | 12 | 9 | 21 | 12 | 17 | ||||||||||||||||||||||||||||||||||||||
| Development expenses | — | 2 | 3 | — | 2 | 10 | ||||||||||||||||||||||||||||||||||||||
Non-cash inventory net realizable value, obsolescence, and other charges (d) | 2 | 3 | 32 | 3 | 3 | 56 | ||||||||||||||||||||||||||||||||||||||
Noncontrolling interest | (7) | (8) | (9) | (18) | (8) | (14) | ||||||||||||||||||||||||||||||||||||||
| Other | 3 | (2) | 1 | (11) | (2) | 15 | ||||||||||||||||||||||||||||||||||||||
| Total Adjusted EBITDA | $ | 87 | $ | 79 | $ | 35 | $ | 376 | $ | 79 | $ | 695 | ||||||||||||||||||||||||||||||||
(a)See Note 2 in Notes to the Interim Financial Statements for additional information.
(b)See Note 17 in Notes to the Interim Financial Statements for additional information.
(c)See Note 8 in Notes to the Interim Financial Statements for additional information.
(d)See Note 6 in Notes 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 require 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 attached to the Registration Statement for a description of our critical accounting policies and estimates.
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ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
See Note 3 in Notes to the Interim Financial Statements for a description of our market risk.
ITEM 4. CONTROLS AND PROCEDURES
As required by Rule 13a-15(b) under the Exchange Act, we have evaluated, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of the end of the period covered by this Report.
Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file or submit under the Exchange Act is accumulated and communicated to management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 30, 2024 (Successor).
Changes in Internal Control over Financial Reporting
There were no changes in our internal control over financial reporting that occurred during the three months ended June 30, 2024 (Successor) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
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PART II. OTHER INFORMATION
ITEM 1. LEGAL PROCEEDINGS
For information regarding pending administrative and judicial proceedings involving regulatory, environmental and other matters, which information is incorporated by reference into this Part II, see Note 10 in Notes to the Interim Financial Statements for information.
ITEM 1A. RISK FACTORS
There have been no material changes to the Company’s risk factors as described in the section titled “Risk Factors” in the Registration Statement.
ITEM 2. UNREGISTERED SALES OF EQUITY AND USE OF PROCEEDS
Tender Offer
In May 2024, the Company commenced a modified “Dutch auction” tender offer (the “Tender Offer”) to purchase shares of the Company’s common stock for cash. The Tender Offer resulted in the purchase for cash of 5,275,862 shares of its common stock, representing 9.0% of the Company’s outstanding common stock, at a clearing price per share of $116.00, or an aggregate of $612 million, exclusive of transaction costs. The Tender Offer was part of the Company’s share repurchase program discussed below.
Upsizing of Share Repurchase Program
In October 2023, the Board of Directors approved a share repurchase program initially authorizing the Company to repurchase up to $300 million of the Company’s outstanding common stock through December 31, 2025. In May 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1 billion through the end of 2025. Repurchases may be made from time to time, at the Company’s discretion, in open market transactions at prevailing market prices, negotiated transactions, or other means in accordance with federal securities laws, and may be repurchased pursuant to a Rule 10b5-1 trading plan. The Company intends to fund repurchases from cash on hand. Repurchases by the Company will be subject to a number of factors, including the market price of the Company’s common stock, alternative uses of capital, general market and economic conditions, and applicable legal requirements, and the repurchase program may be suspended, modified or discontinued by the Board of Directors at any time without prior notice. The Company has no obligation to repurchase any amount of its common stock under the repurchase program.
The following table contains information regarding our purchases of our common stock during the three months ended June 30, 2024:
| Period | Total Number of Shares Purchased (a) | Average Share Price (b) | Approximate Dollar Value of Shares that May Yet be Purchased Under the Plans or Programs (millions) (c) | ||||||||||||||
| April 1 to April 30, 2024 | — | $ | — | $ | 262 | ||||||||||||
| May 1 to May 31, 2024 | — | — | 1,000 | ||||||||||||||
| June 1 to June 30, 2024 | 5,280,889 | 115.99 | 387 | ||||||||||||||
| Total | 5,280,889 | $ | 115.99 | $ | 387 | ||||||||||||
__________________
(a)All open-market purchases were made under authorization from our Board of Directors to purchase up to $1 billion of additional shares of our common stock.
(b)Average price paid per share for open market transactions excludes transaction costs and excise taxes.
(c)Represents the approximate dollar value (in millions) of the remaining capacity under the Company’s share repurchase program.
For a description of limitations on the payment of our dividends, see Note 2 to the Annual Financial Statements attached to the Registration Statement
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ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
During the three months ended June 30, 2024, none of our directors or “officers” (as such term is defined in Rule 16(a)-1(f) under the Exchange Act) adopted or terminated a “Rule 10b5-1 trading agreement” or “non-Rule 10b5-1 trading arrangement” (each as defined in Item 408(a) and (c) of Regulation S-K).
ITEM 6. EXHIBITS
| Exhibit No. | Description | |||||||
3.1*** | ||||||||
3.2*** | ||||||||
10.1***# | ||||||||
| 31.1* | ||||||||
| 31.2* | ||||||||
| 32.1** | ||||||||
| 101.INS* | Inline XBRL Instance Document. | |||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | |||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | |||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
| 104* | Cover Page Interactive Data File (embedded within the Inline XBRL document). | |||||||
| * | Filed herewith. | |||||||
| ** | Furnished herewith. | |||||||
*** | Incorporated by reference herein. | |||||||
| # | Certain of the schedules and exhibits to the agreement have been omitted pursuant to Item 601(a)(5) of Regulation S-K. A copy of any omitted schedule or exhibit will be furnished to the SEC upon request. | |||||||
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GLOSSARY OF TERMS AND ABBREVIATIONS
Adjusted EBITDA. 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; (xi) income taxes; (xii) legal settlements, liquidated damages and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests; 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 credit facility and associated cash flow sweep.
Annual Financial Statements. The audited Consolidated Balance Sheets of TEC as of December 31, 2023 (Successor) and TES as of December 31, 2022 (Predecessor); the related audited consolidated statements of operations, statements of comprehensive income, statements of cash flows, and statements of equity for the period from May 18, 2023 through December 31, 2023 (Successor), and for the period from January 1, 2023 through May 17, 2023 and the years ended 2022 and 2021 (Predecessor); and the related notes. The Annual Financial Statements are attached to the Registration Statement.
AOCI. Accumulated other comprehensive income or loss, which is a component of stockholder’s equity on the Consolidated Balance Sheets.
ARO. Asset retirement obligation.
AWS. Amazon Web Services, Inc. and its affiliates.
Bankruptcy Court. The United States Bankruptcy Court for the Southern District of Texas, Houston Division.
Bilateral LC Agreement. The Letter of Credit Facility Agreement, dated as of May 17, 2023, by and among TES, as borrower, Barclays Bank PLC, as administrative agent and LC issuer, and Citibank, N.A., as collateral agent, which governs the Bilateral LCF, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time.
Bilateral LCF. The senior secured bilateral letter of credit facility in an aggregate committed amount of $75 million under the Bilateral LC Agreement, which is available for the issuance of standby LCs. Obligations under the Bilateral LCF are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
Board of Directors. The board of directors of Talen Energy Corporation.
Brandon Shores. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Brunner Island. A Talen-owned and operated generation facility in York Haven, Pennsylvania.
Camden. A Talen-owned and operated generation facility in Camden, New Jersey.
Capacity Performance. The sole class of capacity product that electricity providers within PJM can offer to satisfy PJM’s capacity obligation and thereby receive capacity payments from PJM. Auctions for this opportunity, generally referred to as capacity auctions, are scheduled by PJM periodically, up to three years in advance of the applicable PJM Capacity Year and in accordance with the terms of PJM’s Tariff and FERC’s orders. Capacity Performance providers assume higher performance requirements during system emergencies and are subject to penalties for non-performance.
CCR. Coal Combustion Residuals, including but not limited to fly ash, bottom ash and gypsum, that are produced from coal-fired electric generation facilities.
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Colstrip. A generation facility comprised of four coal-fired generation units located in Colstrip, Montana (collectively, the “Colstrip Units”). Talen Montana operates the Colstrip Units, owns an undivided interest in Colstrip Unit 3, and has an economic interest in Colstrip Unit 4. Colstrip Units 1 and 2 were permanently retired in January 2020. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities and Talen Montana’s ownership interests in the Colstrip Units.
Colstrip AOC. The “Administrative Order on Consent” entered into in 2012 (with minor amendments in 2017) between Talen Montana (on behalf of the co-owners of the Colstrip Units and in its capacity as the operator of Colstrip) and the Montana Department of Environmental Quality.
Conemaugh. A generation facility located in New Florence, Pennsylvania, in which Talen Generation, through a direct subsidiary, owns a 22.22% undivided interest. Conemaugh is operated by an unaffiliated party. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities.
Credit Agreement. The Credit Agreement, dated as of May 17, 2023, by and among TES, as borrower, the lending institutions from time to time parties thereto, Citibank, N.A., as administrative agent and collateral agent, and the joint lead arrangers and joint bookrunners parties thereto, which governs the RCF, the Term Loans and the TLC LCF, as the same may be amended, amended and restated, supplemented or otherwise modified from time-to-time.
Credit Facilities. Collectively, the RCF, the Term Loans, the TLC LCF and the Bilateral LCF.
Cumulus Coin. Cumulus Coin LLC, an indirect subsidiary of Cumulus Digital Holdings that owns a 75% equity interest in Nautilus as of June 30, 2024.
Cumulus Data. Cumulus Data LLC, an indirect subsidiary of Cumulus Digital Holdings that initially developed the Cumulus Data Campus. See Note 17 for information on the sale of the Cumulus Data Campus to AWS.
Cumulus Data Campus. The zero-carbon data center campus initially developed by Cumulus Data adjacent to Susquehanna See Note 17 for information on the sale of the Cumulus Data Campus to AWS.
Cumulus Data Campus Sale. The Company’s sale, in March 2024, of certain assets of Cumulus Data, which included all of the land, power infrastructure, powered shell and intangibles of Cumulus Data Campus, to AWS for gross proceeds of $650 million, $300 million of which is to be released from escrow upon achievement of certain development milestones. See Note 17 for more information.
Cumulus Digital. Cumulus Digital LLC, a direct subsidiary of Cumulus Digital Holdings and the indirect parent of Cumulus Data and Cumulus Coin.
Cumulus Digital Holdings. Cumulus Digital Holdings LLC, a subsidiary of TES and the direct parent of Cumulus Digital.
Cumulus Digital TLF. The Cumulus Digital term loan facility, due September 2027, under which Cumulus Digital borrowed $175 million from affiliates of Orion to support Cumulus Coin’s required contributions to Nautilus, as well as Cumulus Data’s construction of certain shared infrastructure supporting both Nautilus and the Cumulus Data Campus. The Cumulus Digital TLF was repaid in full and terminated in March 2024.
Dartmouth. A Talen-owned and operated generation facility in Dartmouth, Massachusetts.
Emergence. May 17, 2023, the date that the Plan of Reorganization became effective in accordance with the terms thereof and TEC, TES and the other debtors emerged from the Restructuring.
EPA. U.S. Environmental Protection Agency.
EPA 2015 Ozone Standard. The EPA’s 2015 revision to the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion, based on extensive scientific evidence about ozone’s effects on public health and welfare.
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EPA CCR Rule. National regulatory standards required by the EPA for the management of CCRs in landfills and surface impoundments.
EPA CSAPR. The Cross-State Air Pollution Rule, which requires 28 states in the eastern half of the U.S. to reduce power plant emissions that cross state lines and contribute to ground-level ozone and fine particle pollution in other states. A cap-and-trade system is used to reduce the target pollutants — sulfur dioxide and nitrogen oxides.
EPA ELG Rule. Effluent limitation guidelines, which are national regulatory standards required by the EPA for wastewater discharged from specific industrial categories, including but not limited to coal-fired electric generation facilities, to surface waters and municipal sewage treatment plants.
EPA GHG Rule. New Source Performance Standards (NSPS) and emission guidelines for certain electric generating units established by the EPA to address greenhouse gas (GHG) emissions.
EPA MATS Rule. Mercury and Air Toxics Standards, EPA technology-based emissions standards for mercury and other hazardous air pollutants emitted by generation units with a capacity of more than 25 megawatts.
EPA NESHAP. National Emissions Standards for Hazardous Air Pollutants, an EPA standard that is applicable to the emissions of hazardous air pollutants produced by corporations, institutions and government agencies.
EPS. Earnings per share.
ERCOT. The Electric Reliability Council of Texas, operator of the electricity transmission network and electricity energy market in most of Texas, which is responsible for, among other things, scheduling electric deliveries and performing financial settlements for the competitive wholesale bulk-power market.
ERCOT Sale. The sale of our ERCOT fleet to CPS Energy in May 2024.
Exchange Act. The Securities Exchange Act of 1934, as amended.
FERC. U.S. Federal Energy Regulatory Commission. FERC regulates interstate transmission and wholesale sales of electricity, interstate transportation of natural gas and oil, hydropower projects and natural gas terminals.
GAAP. Generally Accepted Accounting Principles in the United States.
H.A. Wagner. A Talen-owned and operated generation facility in Curtis Bay, Maryland.
Inflation Reduction Act. The Inflation Reduction Act of 2022, which was signed into law in August 2022. Among the Inflation Reduction Act’s provisions are: (i) amendments to the Internal Revenue Code of 1986 to create a nuclear production tax credit program; (ii) the creation, extension and modification of tax credit programs for certain clean energy projects, such as solar, wind and battery storage; and (iii) adjustments to corporate tax rates.
ISO. Independent System Operator.
Keystone. A generation facility located in Shelocta, Pennsylvania, in which Talen Generation, through a direct subsidiary, owns a 12.34% undivided interest. Keystone is operated by an unaffiliated party. See Note 10 in Notes to the Annual Financial Statements for additional information on jointly owned facilities.
LC. Letter of credit.
LMBE-MC TLB. The term loan B facility, due December 2025, under which certain subsidiaries holding the Lower Mt. Bethel and Martins Creek facilities borrowed $777 from affiliates of MUFG. Obligations under the LMBE-MC TLB were guaranteed by those subsidiaries and secured by a first priority lien and security interest in substantially all of their assets. The LMBE-MC TLB was repaid in full and terminated in August 2023. See Note 13 in Notes to the Annual Financial Statements for additional information.
Lower Mt. Bethel. A Talen-owned and operated generation facility in Bangor, Pennsylvania.
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Martins Creek. A Talen-owned and operated generation facility in Bangor, Pennsylvania.
MMBtu. One million British Thermal Units.
Montour. A Talen-owned and operated generation facility in Washingtonville, Pennsylvania.
MW. Megawatt, one thousand kilowatts (one million watts) of electric power.
MWh. Megawatt hour, or megawatts of electric power per hour.
Nautilus. Nautilus Cryptomine LLC, a joint venture owned, as of June 30, 2024, 75% by Cumulus Coin and 25% by TeraWulf, which owns and operates a cryptomining project on land leased from AWS at the Cumulus Data Campus.
NAV. Net asset value.
NCI. Noncontrolling interest.
NDT. Nuclear facility decommissioning trust for Susquehanna.
NERC. North American Electric Reliability Corporation, a not-for-profit international regulatory authority whose mission is to assure the effective and efficient reduction of risks to the reliability and security of the grid.
NRC. U.S. Nuclear Regulatory Commission, which was created as an independent agency by Congress in 1974 to ensure the safe use of radioactive materials for beneficial civilian purposes while protecting people and the environment. The NRC regulates commercial nuclear power plants and other uses of nuclear materials, such as in nuclear medicine, through licensing, inspection and enforcement of its requirements.
Nuclear PTC. The nuclear production tax credit under the Inflation Reduction Act.
Orion. Orion Energy Partners, whose affiliates were third-party lenders under the Cumulus Digital TLF.
Ozone Season. A period of time in which ground-level ozone reaches its highest concentrations in the air.
Ozone Transport Commission. A multi-state organization created under the Clean Air Act responsible for advising the EPA and implementing regional solutions to ground-level ozone issues.
PEDFA Bonds. The following series of Pennsylvania Economic Development Financing Authority (“PEDFA”) Exempt Facilities Revenue Refunding Bonds: Series 2009A due December 2038 (“PEDFA 2009A Bonds”); Series 2009B due December 2038 (“PEDFA 2009B Bonds”); and Series 2009C due December 2037 (“PEDFA 2009C Bonds”). Holders of the PEDFA 2009A Bonds received TEC common stock in connection with the Restructuring in satisfaction of their claims. The PEDFA 2009B Bonds and PEDFA 2009C Bonds currently remain outstanding and are guaranteed by certain of the Subsidiary Guarantors.
PJM. PJM Interconnection, L.L.C., the RTO that operates the electricity transmission network and wholesale power market in all or parts of Delaware, Illinois, Indiana, Kentucky, Maryland, Michigan, New Jersey, North Carolina, Ohio, Pennsylvania, Tennessee, Virginia, West Virginia and the District of Columbia.
PJM ACR. PJM’s “Avoidable Cost Rate” defined under the PJM Open Access Transmission Tariff, if the formula that serves as the PJM MSOC.
PJM Base Residual Auction. A component of the PJM RPM, the PJM Base Residual Auction, is intended to secure power supply resources from market participants in advance of the PJM Capacity Year. It is usually held during the month of May three years prior to the start of the PJM Capacity Year.
PJM Capacity Year. PJM capacity revenues delivery years cover the period from June 1 to May 31.
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PJM IMM. Independent Market Monitor for PJM, who is intended to operate independently from PJM staff and members to objectively monitor, investigate, evaluate and report on PJM’s markets and is responsible for guarding against the exercise of market power.
PJM MOPR. Minimum Offer Price Rule, which limits the minimum price at which certain units can bid into the auction due to certain external subsidization.
PJM MSOC. PJM Market Seller Offer Cap, which is the price ceiling applied by PJM to certain capacity sell offers and is based on the PJM ACR.
PJM RPM. PJM’s capacity market, or the Reliable Pricing Model, formed under PJM’s Open Access Transmission Tariff, which is intended to ensure long-term grid reliability by securing the appropriate amount of power supply resources needed to meet predicted energy demand in the future. Under PJM’s “pay-for-performance” model, generation resources are required to deliver on demand during system emergencies or owe a payment for non-performance.
Plan of Reorganization. The Joint Chapter 11 Plan of Reorganization of Talen Energy Supply, LLC and Its Affiliated Debtors (Docket No. 1206), as subsequently amended, supplemented or otherwise modified, and any exhibits or schedules thereto.
PP&E. Property, plant and equipment.
PPL. PPL Corporation, the former indirect parent holding company of Talen Energy Supply and Talen Energy Corporation until 2015.
Predecessor. Relates to the financial position or results of operations of Talen Energy Supply for periods prior to Emergence, or May 17, 2023.
Prepetition RCF. The Credit Agreement dated as of June 1, 2015, as subsequently amended, supplemented or otherwise modified, among Talen Energy Supply, as borrower, Citibank, N.A., as administrative agent and collateral trustee, and the lenders party thereto, which established a senior secured revolving credit facility, including an LC sub-facility, which was subsequently amended to an LC-only facility.
Prepetition Secured Indebtedness. Collectively, the Prepetition RCF, Prepetition TLB, Prepetition CAF and Prepetition Secured Notes.
Prepetition Secured Notes. The following series of prepetition senior secured notes issued by Talen Energy Supply: (i) 7.25% Senior Secured Notes due 2027; (ii) 6.625% Senior Secured Notes due 2028; and (iii) 7.625% Senior Secured Notes due 2028.
Prepetition TLB. The Term Loan Credit Agreement, dated as of July 8, 2019, as subsequently amended, supplemented or otherwise modified, among Talen Energy Supply, as borrower, JPMorgan Chase Bank, N.A., as administrative agent, and the lenders party thereto, which established a senior secured term loan B facility.
RCF. The senior secured revolving credit facility that provides aggregate revolving commitments of $700 million, including letter of credit commitments of $475 million, under the Credit Agreement. Obligations under the RCF are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
Registration Statement. The TEC registration statement on Form S-1 pursuant to the Securities Exchange Act of 1933 as filed with the SEC on June 20, 2024 (file number 333-280341).
Reliability-Must-Run. Refers to a generating unit that is slated to be retired by its owners but is needed to be available for reasons of reliability. It is typically requested to remain operational beyond its proposed retirement date until transmission upgrades are completed. These arrangements have been used to keep certain power plants operating past their planned retirement dates in order to prevent reliability problems.
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Restructuring. The voluntary cases commenced by TEC, TES and the other debtors under Chapter 11 of the U.S Bankruptcy Code, together with the related financial restructuring of the existing debt, existing equity interests and certain other obligations pursuant to the Plan of Reorganization.
RGGI. The Regional Greenhouse Gas Initiative, a mandatory market-based program among certain states, including Maryland, New Jersey and Massachusetts, to cap and reduce carbon dioxide emissions from the power sector. RGGI requires certain electric power generators to hold allowances equal to their carbon dioxide emissions over a three-year control period. RGGI allowances, as issued by each participating state, represent an authorization for a power generation facility to emit one short ton of carbon dioxide. Allowances may be acquired by auction or through secondary markets. Pennsylvania has proposed joining this market-based program.
Riverstone. Riverstone Holdings LLC and certain of its affiliates.
Rosebud Mine. A coal mine in Montana owned by Westmoreland Rosebud Mining, LLC that supplies coal to the Colstrip Units.
RTO. Regional Transmission Organization.
Secured ISDAs. Certain bilateral secured International Swaps and Derivatives Association (“ISDA”) agreements and Base Contracts for Sale and Purchase of Natural Gas as published by the North American Energy Standards Board (“NAESB”) of Talen Energy Marketing. Obligations under the Secured ISDAs are secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
Secured Notes. The 8.625% Senior Secured Notes due 2030 issued by Talen Energy Supply. Obligations under the Secured Notes are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of Talen Energy Supply and the Subsidiary Guarantors.
Subsidiary Guarantors. The subsidiaries of TES that guarantee: (i) the obligations of TES under the Credit Facilities and the Secured Notes; and (ii) the obligations of Talen Energy Marketing under the Secured ISDAs.
Successor. Relates to the financial position or results of operations of Talen Energy Corporation for periods after Emergence, or May 18, 2023.
Susquehanna. A nuclear-powered generation facility located near Berwick, Pennsylvania. Talen Energy Supply operates and owns a 90% undivided interest in Susquehanna.
Talen (or the “Company,” “we,” “us,” or “our”). (i) for periods after May 17, 2023, Talen Energy Corporation and its consolidated subsidiaries, unless the context clearly indicates otherwise; and (ii) for periods on or before May 17, 2023, Talen Energy Supply and its consolidated subsidiaries, unless the context clearly indicates otherwise.
Talen Energy Corporation (or “TEC”). Talen Energy Corporation, the parent company of Talen Energy Supply, and its consolidated subsidiaries.
Talen Energy Marketing. Talen Energy Marketing, LLC, a direct subsidiary of Talen Energy Supply that provides energy management services to Talen-owned and operated generation facilities and engages in wholesale commodity marketing activities.
Talen Energy Supply (or “TES”). Talen Energy Supply, LLC, a direct subsidiary of Talen Energy Corporation that, thorough subsidiaries, indirectly holds all of Talen’s assets and operations.
Talen Generation. Talen Generation, LLC, a direct subsidiary of Talen Energy Supply that, through its subsidiaries, owns and operates generation facilities, and holds interests in other jointly owned, third-party operated generation facilities, in Pennsylvania, New Jersey and Maryland.
Talen Montana. Talen Montana, LLC, a Talen subsidiary that operates the Colstrip Units and owns an undivided interest in Colstrip Unit 3 and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
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TeraWulf. TeraWulf (Thales) LLC, a wholly owned subsidiary of TeraWulf Inc. and an unaffiliated third party.
Term Loans. Collectively, the TLB and the TLC.
TERP. The Talen Energy Retirement Plan, Talen’s principal defined-benefit pension plan.
TLB. The senior secured term loan B facility in an aggregate principal amount of $580 million (and subsequently increased to $870 million in August 2023) under the Credit Agreement. Obligations under the TLB are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
TLC. The senior secured term loan C facility in an aggregate principal amount of $470 million under the Credit Agreement, the proceeds of which are available to support the issuance of standby and trade LCs under the TLC LCF via 100% cash collateralization. Obligations under the TLC are guaranteed by the Subsidiary Guarantors and secured by a first priority lien and security interest in substantially all of the assets of TES and the Subsidiary Guarantors.
TLC LCF. The $470 term letter of credit facility established under the Credit Agreement. The TLC LCF is cash collateralized with the proceeds of the TLC, and commitments thereunder are reduced to the extent that borrowings under the TLC are prepaid.
WECC. The Western Electricity Coordinating Council, a not-for-profit entity that ensures the reliability of the electricity transmission network and energy market in all or parts of Arizona, California, Idaho, Montana, Nevada, New Mexico, Oregon, South Dakota, Texas, Utah, Washington, the Canadian provinces of Alberta and British Columbia and the northern portion of the Mexican state of Baja California.
Winter Storm Elliott. An extra-tropical cyclone that occurred in December 2022 that created a storm of snow, rain and wind across the country. The winter cyclone had widespread impacts across the United States and caused PJM to declare a Maximum Generation Emergency Action.
Winter Storm Uri. A major winter and ice storm that occurred in February 2021 that had widespread impacts across the United States, including systemic energy market disruptions and price volatility throughout ERCOT.
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned hereunto duly authorized.
Date: | August 13, 2024 | By: | /s/ Terry L. Nutt | |||||||||||
Name: | Terry L. Nutt | |||||||||||||
Title: | Chief Financial Officer | |||||||||||||
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