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 September 30, 2024 (Successor), our generation capacity was 10,676 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 various other factors.
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 September 30, 2023, and from January 1 through September 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.
9
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 repurchased 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.
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 nine months ended September 30, 2024 (Successor). Additional guidance expected to be issued from the U.S. Treasury and IRS may impact the credit value recognized.
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.
10
Open commodity purchase (sales) derivatives as of September 30, 2024 (Successor) range in maturity through 2026. The net notional volumes of open commodity derivatives were:
Successor
September 30, 2024 (a)
December 31, 2023 (a)
Power (MWh)
(32,222,671)
(27,557,871)
Natural gas (MMBtu)
37,757,360
8,314,060
Emission allowances (tons)
346,000
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 mature in 2026. The net notional volumes of open interest rate derivatives were:
Successor
September 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 that 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 September 30, 2024 (Successor) and December 31, 2023 (Successor).
As of September 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 $309 million and its credit exposure net of such effects was $68 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 66% 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 September 30, 2024 (Successor) and December 31, 2023 (Successor).
11
Derivative Instrument Presentation
Balance Sheets Presentation. The fair value of derivative instruments presented within assets and liabilities on the Consolidated Balance Sheets were:
Successor
September 30, 2024
December 31, 2023
Assets
Liabilities
Assets
Liabilities
Commodity contracts
$
50
$
6
$
88
$
32
Interest rate contracts
—
—
1
—
Total current derivative instruments
50
6
89
32
Commodity contracts
22
1
6
5
Interest rate contracts
—
3
—
6
Total non-current derivative instruments
$
22
$
4
$
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 September 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
September 30, 2024 (Successor)
Assets
$
211
$
(139)
$
72
$
—
$
72
Liabilities
172
(139)
33
(23)
10
December 31, 2023 (Successor)
Assets
$
295
$
(198)
$
97
$
(2)
$
95
Liabilities
300
(198)
102
(59)
43
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
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Realized gain (loss) on commodity contracts
Energy revenues (a)
$
60
$
177
$
256
$
247
$
644
Fuel and energy purchases (a)
(24)
(49)
(31)
(70)
(34)
Unrealized gain (loss) on commodity contracts
Operating revenues (b)
95
(128)
63
(41)
60
Energy expenses (b)
7
44
(5)
(2)
(123)
Realized and unrealized gain (loss) on interest rate contracts
Interest expense and other finance charges
(6)
—
3
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.
12
4. Revenue
The disaggregation of our operating revenues for the periods were:
Successor
Predecessor
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Capacity revenues
$
50
$
44
$
141
$
70
$
108
Electricity sales and ancillary services, ISO/RTO
351
558
865
688
281
Physical electricity sales, bilateral contracts, other
38
35
124
41
62
Other revenue from customers
20
29
91
44
27
Total revenue from contracts with customers
459
666
1,221
843
478
Realized and unrealized gain (loss) on derivative instruments
119
(150)
276
(26)
732
Nuclear PTC and other revenue (a)
72
—
151
—
—
Operating revenues
$
650
$
516
$
1,648
$
817
$
1,210
__________________
(a)During the nine months ended September 30, 2024, $90 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.
Accounts Receivable
“Accounts receivable, net” presented on the Consolidated Balance Sheets were:
Successor
September 30, 2024
December 31, 2023
Customer accounts receivable
$
50
$
52
Other accounts receivable
47
85
Accounts receivable, net
$
97
$
137
During the nine months ended September 30, 2024 (Successor), the period from May 18 through September 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.
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 BRAs.
As of September 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
$
51
$
478
$
280
$
3
$
1
__________________
(a)For the period from October 1 through December 31, 2024.
13
5. Income Taxes
Effective Tax Rate Reconciliations
The reconciliations of the effective tax rate for the periods were:
Successor
Predecessor
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Income (loss) before income taxes
$
179
$
(92)
$
1,137
$
(42)
$
677
Income tax benefit (expense)
(11)
16
(192)
(3)
(212)
Effective tax rate
6.1
%
17.4
%
16.9
%
(7.1
%)
31.3
%
Federal income tax statutory tax rate
21
%
21
%
21
%
21
%
21
%
Income tax benefit (expense) computed at the federal income tax statutory tax rate
(38)
19
(239)
9
(143)
Income tax increase (decrease) due to:
State income taxes, net of federal benefit
(5)
3
(34)
1
(34)
Change in valuation allowance
29
(12)
63
(10)
129
Production tax credits
16
—
34
—
—
Other permanent differences
(3)
3
10
—
(16)
Nuclear decommissioning trust taxes
(10)
3
(26)
(3)
(9)
Reorganization adjustments
—
—
—
—
(138)
Other
—
—
—
—
(1)
Income tax benefit (expense)
$
(11)
$
16
$
(192)
$
(3)
$
(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 nine months ended September 30, 2024 (Successor), Talen recognized a $63 million tax benefit for the reduction in federal and state valuation allowances, primarily related to year-to-date divestitures and year-to-date income which increase the amount of tax attributes that can be utilized. See Note 17 for information on divestitures. At each period, management will continue to assess the available positive and negative evidence to determine the need for a valuation allowance. We believe that there is a reasonable possibility that within the next 12 months, sufficient positive evidence may become available to allow us to reach a conclusion that a significant portion of the valuation allowance may no longer be needed.
6. Inventory
Successor
September 30, 2024
December 31, 2023
Coal
$
104
$
152
Oil products
69
75
Fuel inventory for electric generation
173
227
Materials and supplies, net
83
72
Environmental products
41
76
Inventory, net
$
297
$
375
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 nine months ended September 30, 2024 (Successor), non-material for the period from May 18 through September 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.
14
7. Nuclear Decommissioning Trust Funds
Successor
September 30, 2024
December 31, 2023
Amortized Cost
Unrealized Gains
Unrealized Losses
Fair Value
Amortized Cost
Unrealized Gains
Unrealized Losses
Fair Value
Cash equivalents
$
8
$
—
$
—
$
8
$
9
$
—
$
—
$
9
Equity securities
504
672
44
1,132
491
575
53
1,013
Debt securities
581
12
—
593
570
10
1
579
Receivables (payables), net
4
—
—
4
(26)
—
—
(26)
NDT funds
$
1,097
$
684
$
44
$
1,737
$
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 September 30, 2024 (Successor) and December 31, 2023 (Successor).
The contractual maturities for available-for-sale debt securities presented on the Consolidated Balance Sheets were:
Successor
September 30, 2024
December 31, 2023
Maturities within one year
$
63
$
105
Maturities within two to five years
185
194
Maturities thereafter
345
280
Debt securities, fair value
$
593
$
579
The sales proceeds, gains, and losses for available-for-sale debt securities for the periods were:
Successor
Predecessor
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Sales proceeds of NDT funds investments (a)
$
545
$
492
$
1,578
$
763
$
839
Gross realized gains
4
1
9
1
7
Gross realized losses
(2)
(5)
(8)
(7)
(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
September 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
$
3,020
$
(246)
$
2,774
$
3,178
$
(109)
$
3,069
Nuclear fuel
1-6
322
(129)
193
228
(55)
173
Other property and equipment
1-26
148
(36)
112
358
(21)
337
Capitalized software
1-5
9
(3)
6
6
(1)
5
Construction work in progress
143
—
143
255
—
255
Property, plant and equipment, net
$
3,642
$
(414)
$
3,228
$
4,025
$
(186)
$
3,839
15
The components of “Depreciation, amortization and accretion” presented on the Consolidated Statements of Operations for the periods were:
Successor
Predecessor
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Depreciation expense (a)
$
56
$
53
$
172
$
76
$
173
Amortization expense (b)
5
—
11
1
4
Accretion expense (c)
14
13
42
17
24
Other
—
—
—
—
(1)
Depreciation, amortization, and accretion
$
75
$
66
$
225
$
94
$
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
PJM RMR 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 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 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.
9. Asset Retirement Obligations and Accrued Environmental Costs
Successor
September 30, 2024
December 31, 2023
Asset retirement obligations
$
495
$
464
Accrued environmental costs
22
23
Total asset retirement obligations and accrued environmental costs
517
487
Less: asset retirement obligations and accrued environmental costs due within one year (a)
42
18
Asset retirement obligations and accrued environmental costs due after one year
$
475
$
469
__________________
(a)Presented as “Other current liabilities” on the Consolidated Balance Sheets.
16
Asset Retirement Obligations
The changes of the ARO carrying value were:
ARO Rollforward
Carrying value, December 31, 2023 (Successor)
$
464
Obligations settled
(9)
Accretion expense
40
Carrying value, September 30, 2024 (Successor)
$
495
Supplemental information for the ARO:
Successor
September 30, 2024
December 31, 2023
Supplemental Information
Nuclear (a)
$
234
$
214
Non-Nuclear (b)
261
250
Carrying value
$
495
$
464
__________________
(a)Obligations are expected to be settled with available funds in the NDT at the time of decommissioning. See Note 12 for additional information on the NDT.
(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.
As a result of environmental regulations issued by the EPA or other rule-making entities, the Company may be required to revise and (or) recognize new AROs. See “Environmental Matters” in Note 10 for additional information. See “Talen Montana Financial Assurance” in Note 10 for information on Talen Montana’s requirement to provide financial assurance for certain environmental decommissioning and remediation liabilities related to Colstrip.
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 in these matters vigorously, 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.
Pending Legal Matters
ERCOT Weather Event (Winter Storm Uri) Lawsuits. In May 2024, the Company closed on the ERCOT Sale but retained certain potential liabilities in connection with Winter Storm Uri (see Note 17 for information on the ERCOT Sale). In December 2023, five multi-district litigation (“MDL”) bellwether suits against Talen’s former subsidiaries and other power generation facility market participants were dismissed by the MDL court. The plaintiffs allege they suffered losses due to the defendants’ failure to provide sufficient power to the grid and have been seeking unspecified damages. The plaintiffs filed a motion for rehearing on the matter and, if unsuccessful, it’s expected the plaintiffs will petition the Texas Supreme Court to review the decision. The cases dismissed and now on appeal were selected by the MDL court as representative of all 58 cases filed in the Winter Storm Uri litigation. If affirmed by the Texas Supreme Court, Talen expects the MDL court to apply its dismissal ruling broadly to all Winter Storm Uri cases involving Talen defendants. Talen’s maximum potential damages on prepetition Winter Storm Uri claims are expressly limited to payments from the Talen defendants’ insurers pursuant to the Plan of Reorganization. However, claims filed by plaintiffs after the Restructuring commenced who did not receive effective notice of the Restructuring, if any, may not be subject to the Plan of Reorganization. Talen cannot predict the effect of an adverse outcome for any such claims.
17
Resolved Legal Matters
Pension Litigation. In July 2024, the U.S. District Court for the Eastern District of Pennsylvania approved a $20 million settlement in a class action lawsuit brought by former Talen employees who alleged they were owed enhanced benefits under the TERP. Under the terms of the settlement, Talen agreed to pay: (i) approximately $6 million for administrative costs of the settlement and for plaintiff attorneys fees, which were partially offset by insurance recoveries; and (ii) approximately $14 million to class members from the TERP. Both payment obligations were substantially completed during the three months ended September 30, 2024 (Successor).
PUCT Repricing. In June 2021, Talen intervened in proceedings in which certain market participants challenged the validity of two Public Utility Commission of Texas (“PUCT”) orders directing ERCOT to price energy at the maximum of $9,000 per MWh during Winter Storm Uri. Talen opposed this relief. In June 2024, the Texas Supreme Court found 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.
See Note 12 in Notes to the Annual Financial Statements for legal matters resolved previously.
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; and state public utility commissions. The RTOs and ISOs in the regions in which we conduct business inherently have complex rules that are intended to balance the interests of market stakeholders. Proposed market structure modifications may lead to disputes among stakeholders that might not be resolved for a period of time as a result of regulatory and (or) legal proceedings. Accordingly, Talen is subject to uncertainty with respect to: (i) new or amended regulations issued by regulatory agencies; and (ii) changes in market design, tariff structure, capacity auctions, and (or) pricing rules. Unless otherwise discussed below, we are unable to predict the outcome of any regulatory matters or reasonably estimate the amount of any associated costs and (or) potential liabilities. Additionally, it is possible that any outcome to Talen with respect to such matters, including market modifications, could have a material impact on our capacity revenues, energy revenues, results of operations, liquidity, or financial condition.
PJM Capacity Market Reform. In June 2023, FERC accepted a request by PJM to delay certain PJM BRAs in order for PJM to propose market reforms. PJM filed its market reform proposals with FERC in October 2023. In early 2024, FERC accepted portions of PJM’s proposed market changes. PJM held the PJM BRA for the 2025/2026 PJM Capacity Year in July 2024 which incorporated the FERC accepted changes. The PJM BRAs for the 2026/2027, 2027/2028, and 2028/2029 PJM Capacity Years were previously scheduled for December 2024, June 2025, and December 2025, respectively; however in September 2024, the Sierra Club and other public interest organizations filed a complaint at FERC challenging PJM’s rules establishing must-offer exceptions for PJM BRA participation by PJM RMR resources and seeking to delay the 2026/2027 PJM BRA pending resolution of its complaint. In October 2024, PJM announced it has concerns about FERC considering the Sierra Club’s complaints about PJM RMR resources in isolation and therefore intends to file a Section 205 proceeding under the Federal Power Act seeking FERC’s approval of to-be-determined market reforms not limited to potential revisions to the treatment of PJM RMR resources. As a result, in October 2024 PJM formally requested that FERC approve six-month delays in the PJM BRAs for the 2026/2027, 2027/2028, 2028/2029, and 2029/2030 PJM Capacity Years and in November 2024, FERC approved the auction delays. Talen can provide no assurance that the four scheduled auctions will be held as scheduled or at all.
Susquehanna ISA Amendment. Under a prior, FERC-accepted interconnection agreement between PJM, Susquehanna, and a subsidiary of PPL Corporation (“PPL”) (collectively, the “ISA Parties”), Susquehanna is permitted to decrease by up to 300 MW the amount of power supply that it would otherwise provide to the power grid within PPL’s service area. Susquehanna currently provides that power to load via load-owned transmission directly connected to Susquehanna rather than supplying load from the power grid. In June 2024, PJM filed at FERC an Amended Interconnection Service Agreement (“Amended ISA”) executed between the ISA Parties permitting Susquehanna to decrease by up to 480 MW the amount of power supply that it would otherwise provide to the power grid and now intends to sell to AWS instead. PJM previously concluded such increase in the amount of withheld power would have no reliability impacts on the grid. In June 2024, despite the Amended ISA being applicable solely to the PPL service area, Exelon Corporation and AEP filed a protest to the Amended ISA at FERC and raised generic issues involving the direct connection of load service to generators. FERC responded by issuing a deficiency letter in August 2024 seeking more information about the arrangement described in the Amended ISA and separately setting a Technical Conference for November 2024 to discuss broader issues related to (i) co-located load connected directly to generation; and (ii) emerging reliability issues resulting from the dramatic rise in data center demand for power. In September 2024, PJM provided a response to FERC’s August 2024 deficiency letter on the Amended ISA and filed a Construction Service Agreement between the ISA Parties and Mid-Atlantic Interstate Transmission, LLC to facilitate certain network upgrades to ultimately accommodate a 960 MW decrease of power supply to the grid. Talen filed its own comments in September 2024 and written testimony in the Technical Conference proceeding in October 2024. Shortly after the conclusion of the FERC Technical Conference on November 1, 2024, FERC issued a 2-1 decision rejecting the Amended ISA. Talen may seek a rehearing of the FERC order within the 30-day deadline for such motions and, if necessary, file a subsequent appeal in a U.S. Court of Appeals.
18
The prior FERC-accepted interconnection agreement between the ISA Parties permitting Susquehanna to decrease 300 MW of its current power supply from the power grid remains in place and facilitates the initial sale of power to AWS under the AWS PPA. The Company is evaluating its commercial and legal options to provide the most efficient path to full development of the AWS data center campus. Such options include, but are not limited to, potential submission of a revised form of Amended ISA or alternate contract structures with AWS. If the Company is unable commercially or legally to resolve the Amended ISA approval impediments and realize the full development of the AWS data center campus, there may be a material impact on our future results of operations and (or) financial condition.
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 be: (i) subject to environmental remediation work at its facilities; (ii) involved in other environmental matters; or (iii) 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 significant costs to comply with these requirements, including increased capital expenditures or operation and maintenance expenses, monetary fines, remediation costs, penalties, or other restrictions. Legal challenges to environmental rules or permits add to the uncertainty of estimating future compliance costs. Additionally, costs may increase significantly if the requirements or scope of environmental laws or regulations, or similar rules, are expanded or changed. Unless otherwise discussed below, we are unable to predict the outcome of any environmental matters or reasonably estimate the amount of any associated costs and (or) potential liabilities. It is possible that any adverse outcome to Talen with respect to such matters could have a material impact on our results of operations, liquidity, and (or) financial condition.
EPA Cross-State Air Pollution Rule (“EPA CSAPR”) and Nitrogen Oxides (“NOx”) Requirements. Coal-fired generation facilities, including those in which Talen has ownership, have been the subject of EPA regulations and efforts by certain states and other parties to strengthen applicable NOx emission limits under the Clean Air Act. In 2015, the EPA’s 2015 revision to the 8-hour ozone National Ambient Air Quality Standards for ground-level ozone to 70 parts per billion (the “EPA 2015 Ozone Standard”) was issued, which triggered updates to state-specific compliance requirements as well as provisions that are intended to limit cross-state emissions. In June 2023, the EPA published a rule in connection with the EPA 2015 Ozone Standard updating the EPA CSAPR ozone season NOx allowance trading program for 2023 and beyond (“Good Neighbor Plan FIP”). Talen’s facilities in Maryland, Pennsylvania, and New Jersey are subject to the new rule; however, the entire rule has been challenged by multiple parties. 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 D.C. Circuit Court of Appeals. In the meantime, EPA has issued a direct final rule indicating it plans to provide NOx allocations and budgets from the previously applicable and less restrictive revised CSAPR rule until the Good Neighbor Plan FIP matter is resolved.
EPA Mercury and Air Toxics Standards Rule (“EPA MATS Rule”). In May 2024, the EPA published a rule that requires coal-fired generation facilities to reduce particulate matter (“PM”) emissions by the middle of 2027 (or 2028, if an extension is approved). Colstrip is not expected to meet the new PM standard without substantial upgrades to its control equipment. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive control equipment or retire the Colstrip facility. Such decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA GHG Rule due to timing and costs. Challenges to the EPA MATS Rule have been filed in the D.C. Circuit Court of Appeals, including by Talen and 23 states. After motions to stay the EPA MATS Rule during the pendency of the litigation were denied by the D.C. Circuit Court of Appeals, Talen and other parties filed emergency stay request applications with the U.S. Supreme Court in September 2024, which were denied in October 2024. The appeal on the merits of the new rule remains pending in the D.C. Circuit Court of Appeals. No assurance can be provided as to when the challenges to the EPA MATS Rule will be resolved or whether such challenges will be resolved in the Company’s favor. As the timeline for compliance with the new standards is accelerated and must be considered in tandem with the new EPA GHG Rule, it is possible the Company will need to make operating decisions about the future of Colstrip before the Company has clarity about the outcome of the litigation.
19
EPA Greenhouse Gas Rule (“EPA GHG Rule”). In May 2024, the EPA published a rule that establishes carbon dioxide limits for new electric generating units (“EGUs”) and greenhouse gas (“GHG”) emission guidelines for certain existing EGUs. Under the guidelines, if existing coal-fired EGUs operate beyond 2031, GHG reductions, such as those achieved by the addition of carbon capture and sequestration (“CCS”), are required to be implemented by the end of 2031. Colstrip is not expected to meet the new rules without substantial technology upgrades and pipeline infrastructure build-out. As a result, Talen Montana and the other Colstrip co-owners face the decision either to invest in new cost-prohibitive controls (e.g., CCS technology) or retire the Colstrip facility by the end of 2031. Such decision must be evaluated in conjunction with compliance requirements under the May 2024 EPA MATS Rule. Petitions have been filed in the D.C. Circuit Court of Appeals, including by coalitions representing 27 states and an ad hoc coalition of power producers of which Talen is a member, requesting a review of the EPA GHG Rule. Stay motions were denied by the D.C. Circuit Court of Appeals in July 2024 and the U.S. Supreme Court in October 2024. Appeals of the EPA GHG Rule remain pending in the D.C. Circuit Court of Appeals. No assurance can be provided as to when the challenges to the EPA GHG Rule will be resolved or whether such challenges will be resolved in the Company’s favor. The EPA has also stated its intent to develop GHG regulations for existing natural gas combustion turbines; however, no rule has been proposed. As the timeline for compliance with the new standards is accelerated and must be considered in tandem with the new EPA MATS Rule, it is possible the Company will need to make operating decisions about the future of Colstrip before the Company has clarity about the outcome of the litigation.
Pennsylvania RGGI. In April 2022, Pennsylvania entered the RGGI program, with compliance set to begin on July 1, 2022. However, 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 and 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 to intervene in the litigation.
EPA Effluent Limitation Guidelines Rule (“EPA ELG Rule”). In November 2015, the EPA revised the effluent limitation guidelines for certain power generation facilities, which imposed more stringent standards for wastewater streams as facility discharge permits are renewed. In 2020, the EPA issued changes that would exempt coal generation facility operators from meeting certain wastewater standards if the facility would commit to cease coal-fired generation by the end of 2028, which Talen elected for its wholly owned coal operations. In May 2024, the EPA published revisions to the EPA ELG Rule, which imposed additional requirements for legacy wastewater and combustion residual leachate. Such EPA ELG Rule revisions impact Talen’s active generation facilities that have both CCR units and hold National Pollutant Discharge Elimination System (“NPDES”) discharge permits. These sites include Brandon Shores, Brunner Island, Montour, and potentially Martins Creek. Talen is evaluating what: (i) potential discharge limits may apply; (ii) treatment may be required; and (iii) the implementation timeline may be. Obligations for installing any new wastewater treatment equipment, if necessary, will not be known until each applicable state where the active generation facilities operate makes their own determination with respect to NPDES permit renewals with new limits and associated timing. As a result of the future permit conditions, additional capital expenditures and (or) AROs may be required, which may have a material impact on our results of operations and (or) financial condition.
Multiple challenges, including stay requests, to the EPA ELG Rule have been filed in various U.S. Courts of Appeal by parties that include 15 states, environmental groups, and industry groups, including the Utility Water Act Group (“UWAG”), of which Talen is a member. The appeals have been consolidated in the U.S. Court of Appeals for the Eighth Circuit, and in October 2024, stay requests were denied. No assurance can be provided as to when the challenges to the EPA ELG Rule merits will be resolved or whether such challenges will be resolved in the Company’s favor.
EPA Coal Combustion Residuals Rule (“EPA CCR Rule”). In April 2015, the EPA established regulations under the Resource Conservation and Recovery Act to identify CCRs as nonhazardous solid waste and provided CCR management and siting requirements. The 2015 rule was modified in 2020 after a 2018 D.C. Circuit Court of Appeals ruling found that, among other things, the EPA did not adequately regulate unlined impoundments. In its 2020 rulemaking, the EPA specified procedures for owners to extend the operating timeline of certain unlined impoundments. Talen submitted an extension request under this process for an unlined impoundment at Montour, which the EPA has not yet acted upon. The 2018 D.C. Circuit Court of Appeals ruling also found that the EPA did not properly address legacy surface impoundments in the 2015 CCR rule. As a result of the finding, in May 2024, the EPA finalized additional federal CCR regulations with an effective date in November 2024, which provided new requirements for legacy CCR surface impoundments and new requirements for other CCR disposal and management areas at active power plants (“CCR Management Units” or “CCRMUs”). This rule has been challenged in the D.C. Circuit Court of Appeals by multiple parties, including two industry groups of which Talen is a member. Additionally, the EPA is being challenged by other industry parties on new regulatory interpretations that could be consequential to CCR unit closure practices and costs. No assurance can be provided at this time as to when the legal challenges to the EPA’s CCR Rule and interpretations will be resolved or whether such challenges will be decided in the Company’s favor.
Talen continues to review the 2024 EPA CCR Rule provisions, perform the required applicability assessments, and await additional information and guidance from the EPA concerning the rule’s requirements. Pursuant to the regulations, initial facility evaluation reports to identify CCR areas which may become regulated and subject to the rule’s requirements are due in February 2026. Following that, site investigation may be required to further investigate applicability and a subsequent facility report is due in February 2027. The Company has initiated reviews under the facility evaluation report requirements at locations with ash impoundments that have long since ceased coal operations as well as at locations with current coal operations. No assurance can be provided as to whether any specific ash impoundments owned by the Company may or may not be within scope of the new EPA CCR Rule until the Company completes its assessments within the regulatory timeframe.
20
As of September 30, 2024 (Successor), the Company has recognized required cost estimates in order to comply with the rule’s initial compliance requirements and deadlines. However, the Company does not yet have sufficient information available to estimate costs for the future compliance obligations under the rule. As the Company continues its applicability evaluations and site assessments to determine the scope of work on its properties imposed by the new rule, additional new AROs and (or) revisions could be required. It is expected estimates will be available, under the timeline provided for by the regulations, as described above, at the completion of the initial facility evaluation reports or at the completion of a subsequent site investigation. Such AROs or ARO changes could be material and, as a result, may have a material impact on our results of operations and (or) financial condition.
Guarantees and Other Assurances
In the normal course of business, the Company enters into agreements to provide financial performance assurance to third parties on behalf of certain subsidiaries. These agreements primarily support or enhance the stand-alone creditworthiness attributed to a subsidiary or facilitate the commercial activities in which these subsidiaries engage. Such agreements may include guarantees, stand-by LCs, and (or) surety bonds. Additionally, they may include customary indemnifications to third parties related to asset sales and other transactions. The probability of expected material payment and (or) performance for these assurance agreements is believed to be remote.
Surety Bonds. Surety bonds provide financial performance assurance to third parties on behalf of certain Company 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 particular 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. As of September 30, 2024 (Successor) and December 31, 2023 (Successor), the aggregate amount of surety bonds outstanding was $234 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 Administrative Order on Consent (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 Colstrip has provided its proportionate share of financial assurance to the MDEQ for estimates of coal ash disposal impoundments remediation and closure activities approved by the MDEQ.
The aggregate amount of surety bonds posted to the MDEQ on behalf of Talen Montana’s proportionate share of such activities was $125 million as of September 30, 2024 (Successor) and $115 million as of December 31, 2023 (Successor). 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 are expected to decrease as Colstrip’s coal ash impoundments remediation and closure activities are completed.
Other Commitments and Contingencies
Talen Montana Fuel Supply. Talen Montana purchases coal from a coal mine owned by Westmoreland Rosebud Mining, LLC (the “Rosebud Mine”) for its interest in Colstrip Units 3 and 4 under a full requirements contract with an unaffiliated coal mine operator. Two lawsuits have been brought against the Rosebud Mine challenging permits issued to it by the State of Montana. Talen Montana is not party to either lawsuit, but is monitoring the progress of each to assess the impact to its operations. In the first lawsuit, the Montana Supreme Court affirmed a lower court’s ruling to vacate a mining permit and require the Montana Board of Environmental Review to perform an additional review of the permit. In the second lawsuit, the Montana Federal District Court ordered a branch of the U.S. Department of the Interior to complete an updated Environmental Impact Statement (“EIS”). In April 2024, the Montana Federal District Court granted an extension to the EIS completion date to January 31, 2025. At this time, Talen cannot predict the effect of that an adverse outcome of these lawsuits to Rosebud Mine would have on: (i) Talen Montana’s ability to source fuel for its share of Colstrip operations; or (ii) Talen Montana’s operations, results of operations, or liquidity.
21
11. Long-Term Debt and Other Credit Facilities
Long-Term Debt
Successor
Interest
Rate (a)
September 30, 2024
December 31, 2023
TLB
8.60 %
$
859
$
866
TLC
8.60 %
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
2,660
2,849
Unamortized deferred finance costs and original issuance discounts
(35)
(29)
Total carrying value
2,625
2,820
Less: long-term debt, due within one year
9
9
Long-term debt
$
2,616
$
2,811
__________________
(a)Computed interest rate as of September 30, 2024 (Successor).
(b)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 September 30, 2024 (Successor) were:
2024 (a)
2025
2026
2027
2028
Thereafter
Total
Total maturities
$
2
$
9
$
9
$
9
$
9
$
2,623
$
2,660
__________________
(a) For the period from October 1 through December 31, 2024.
Revolving Credit and Other Facilities
Successor
September 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
$
—
$
—
$
700
$
—
$
62
TLC LCF (b)(c)
May 2030
470
—
311
159
—
404
Bilateral LCF (b)
May 2028
75
—
18
57
—
74
Total
$
1,245
$
—
$
329
$
916
$
—
$
540
__________________
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs, subject to a $475 million LC sublimit.
(b)Direct cash borrowings are not permitted under the facility.
(c)LCs are collateralized by $472 million of cash as of September 30, 2024 (Successor) and December 31, 2023 (Successor), which is presented as “Restricted cash and cash equivalents” on the Consolidated Balance Sheets.
2024 Transactions
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 remarketed bonds 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.
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.
22
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.
Talen Energy Supply Long-Term Debt, Revolving Credit, and Other Facilities
As of September 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 $18 million under Secured ISDAs as of September 30, 2024 (Successor).
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
September 30, 2024
December 31, 2023
Level 1
Level 2
NAV
Netting (a)
Total
Level 1
Level 2
NAV
Netting (a)
Total
Assets
Cash equivalents
$
—
$
—
$
8
$
—
$
8
$
—
$
—
$
9
$
—
$
9
Equity securities (b)
755
—
377
—
1,132
629
—
384
—
1,013
U.S. Government debt securities
328
—
—
—
328
337
—
—
—
337
Municipal debt securities
—
88
—
—
88
—
86
—
—
86
Corporate debt securities
—
177
—
—
177
—
156
—
—
156
Receivables (payables), net (c)
—
—
—
—
4
—
—
—
—
(26)
NDT funds
1,083
265
385
—
1,737
966
242
393
—
1,575
Commodity derivatives
108
103
—
(139)
72
98
196
—
(200)
94
Interest rate derivatives
—
—
—
—
—
—
1
—
—
1
Total assets
$
1,191
$
368
$
385
$
(139)
$
1,809
$
1,064
$
439
$
393
$
(200)
$
1,670
Liabilities
Commodity derivatives
$
131
$
38
$
—
$
(162)
$
7
$
155
$
139
$
—
$
(257)
$
37
Interest rate derivatives
—
3
—
—
3
—
6
—
—
6
Total liabilities
$
131
$
41
$
—
$
(162)
$
10
$
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 September 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 nine months ended September 30, 2024 (Successor) and for the period from May 18 through September 30, 2023 (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
23
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.
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
September 30, 2024
December 31, 2023
Carrying Value
Fair Value
Carrying Value
Fair Value
Long-term debt (a)
$
2,625
$
2,769
$
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
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Postretirement benefits service cost (a)
$
—
$
—
$
2
$
1
$
1
Interest cost
17
17
50
25
27
Expected return on plan assets
(17)
(18)
(52)
(26)
(33)
Resolved litigation settlement
15
—
15
—
—
Amortization of:
Net loss
—
—
—
—
2
Postretirement benefit (gain) loss, net (b)
15
(1)
13
(1)
(4)
Net periodic defined benefit cost (credit)
$
15
$
(1)
$
15
$
—
$
(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 nine months ended September 30, 2024 (Successor) and presented as “Other non-operating income (expense), net” on the Consolidated Statements of Operations.
In September 2024, the Company contributed $38 million to the TERP that is presented as “Postretirement benefit obligations” on the Consolidated Balance Sheets as of September 30, 2024 (Successor). In October 2024, the Company contributed an additional $6 million to the TERP.
In September 2024, the Company approved a plan amendment for certain other postretirement benefit plans, resulting in the recognition of prior service credits of $21 million and presented as “Postretirement benefit prior service (credits) costs, net” on the Consolidated Statements of Comprehensive Income (Loss).
24
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
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Numerator: (Millions of Dollars)
Net Income (Loss)
$
168
$
(76)
$
945
$
(45)
$
465
Less:
Net income (loss) attributable to noncontrolling interest
—
1
29
3
(14)
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor)
$
168
$
(77)
$
916
$
(48)
$
479
Denominator: (Thousands)
Weighted-Average Number of Common Shares Outstanding - Basic
50,924
59,029
55,703
59,029
—
Restricted stock units
376
—
292
—
—
Performance stock units
1,869
—
1,761
—
—
Weighted-Average Number of Common Shares Outstanding - Diluted
53,169
59,029
57,756
59,029
—
Earnings per Share - Basic
$
3.30
$
(1.30)
$
16.44
$
(0.81)
N/A
Earnings per Share - Diluted
3.16
(1.30)
15.86
(0.81)
N/A
15. Stockholders' Equity
Common Stock Transactions
In September 2024, the Board of Directors approved an increase of the remaining capacity under the Company’s share repurchase program to $1.25 billion through December 31, 2026. See Note 16 in Notes to the Annual Financial Statement for more information on the Company’s share repurchase program.
The shares repurchased during nine months ended September 30, 2024 (Successor) represent 14% of the Company’s outstanding common stock. Summary of activity under the Company’s share repurchase program:
Successor
Three Months Ended September 30, 2024
Nine Months Ended September 30, 2024
Number of Shares (a)
Share Price (b)
Total Amount
Number of Shares (a) (c)
Share Price (b)
Total Amount
Share repurchases
2,559,826
$
118.82
$
304
8,333,715
$
115.87
$
966
Share retirements
(2,564,853)
118.81
(304)
(8,333,715)
115.87
(966)
_____________
(a)Includes 2,413,793 shares repurchased from affiliates of Rubric Capital Management LP in July 2024 at a weighted average price of $116.00 per share.
(b)Weighted average price per share, including transaction costs and excise taxes.
(c)Includes 5,275,862 shares repurchased as result of a tender offer in June 2024.
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.
As of September 30, 2024 (Successor), the Company had 50,855,417 shares of common stock outstanding.
25
Acquisition of Noncontrolling Interests
Purchase of Equity in Nautilus. In October 2024, the Company acquired TeraWulf’s 25% equity interest in in Nautilus in exchange for $85 million in cash and the distribution by Nautilus of its Bitcoin mining equipment to TeraWulf. As a result of the transaction, the Company owns 100% of the equity of Nautilus.
Purchase of Equity in Cumulus Digital Holdings. In March 2024, TES acquired all of the equity 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.
Accumulated Other Comprehensive Income
Changes in AOCI for the periods were:
Successor
Predecessor
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Beginning balance
$
(23)
$
—
$
(167)
Gains (losses) arising during the period (a)
26
(26)
6
Reclassifications to Consolidated Statements of Operations
(1)
7
5
Income tax benefit (expense)
(7)
7
(5)
Other comprehensive income (loss)
18
(12)
6
Cancellation of equity at Emergence
—
—
161
Accumulated other comprehensive income (loss)
$
(5)
$
(12)
$
—
_____________
(a)Primarily related to “Postretirement benefit prior service (credits) costs, net” for the nine months ended September 30, 2024 (Successor) and “Available-for-sale securities unrealized gain (loss), net” for the period from May 18 through September 30, 2023 (Successor).
The components of AOCI, net of tax, at September 30 were:
Successor
2024
2023
Available-for-sale securities unrealized gain (loss), net
$
7
$
(12)
Postretirement benefit prior service credits (costs), net
16
—
Postretirement benefit actuarial gain (loss), net
(28)
—
Accumulated other comprehensive income (loss)
$
(5)
$
(12)
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.
26
16. Supplemental Cash Flow Information
Supplemental information for the Consolidated Statements of Cash Flows for the periods was:
Successor
Predecessor
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Cash paid during the period
Interest and other finance charges, net of capitalized interest (a)
$
159
$
30
$
283
Income taxes, net
14
9
7
Unrealized (gain) loss on derivative instruments included on the Statements of Cash Flows
Commodity contracts
$
(58)
$
43
$
63
Interest rate swap contracts (interest expense)
(1)
6
2
Unrealized (gain) loss on derivative instruments
$
(59)
$
49
$
65
Depreciation, amortization and accretion included on the Statements of Cash Flows
Depreciation, amortization and accretion
$
225
$
94
$
200
Other
(9)
(5)
8
Depreciation, amortization and accretion
$
216
$
89
$
208
Reconciliation of other non-cash operating activities
Stock-based compensation
$
24
$
11
$
—
Derivative option premium amortization
16
31
29
Bitcoin revenue
(91)
(44)
(27)
Debt restructuring (gain) loss, net
(9)
—
—
Other
2
25
5
Total
$
(58)
$
23
$
7
Non-cash investing activities
Capital expenditure accrual increase (decrease)
$
(16)
$
(8)
$
(28)
Non-cash financing activities
Non-cash increase to PP&E and decrease to other current assets for contribution of Bitcoin miners to Nautilus (b)
$
—
$
—
$
14
Non-cash decrease to PP&E and decrease to noncontrolling interest for distribution of Bitcoin miners to TeraWulf
—
—
3
Non-cash increase to PP&E and increase to noncontrolling interest for contribution of Bitcoin miners by TeraWulf (b)
—
—
38
__________________
(a)Capitalized interest totaled $3 million for the nine months ended September 30, 2024 (Successor); $7 million for May 18 through September 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 Bitcoin miners that increased PP&E.
27
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
September 30, 2024
December 31, 2023
Cash and cash equivalents
$
648
$
400
Restricted cash and cash equivalents:
TES TLC debt restricted deposits
472
472
Nautilus project restricted deposits
9
10
Commodity exchange margin deposits
3
—
Cumulus Digital Holdings restricted deposits
—
19
Restricted cash and cash equivalents
484
501
Total
$
1,132
$
901
17. Acquisitions and Divestitures
2024 Activities
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 $564 million is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations for the nine months ended September 30, 2024 (Successor).
Cumulus Data Campus Sale. In March 2024, AWS purchased substantially all the assets related to the Cumulus Data Campus and certain other assets for gross proceeds of $650 million, of which $350 million were received at closing with the remaining $300 million held in escrow pending achievement of certain development milestones. In August 2024, the milestones were met and the Company received the remaining consideration. For the nine months ended September 30, 2024 (Successor), a $324 million gain on sale is presented as “Gain (loss) on sale of assets, net” on the Consolidated Statements of Operations. In connection with the Cumulus Data Campus Sale, the Company entered into the AWS PPA. See Note 10 for additional information on the AWS PPA and the Amended ISA.
2023 Activities
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.
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.
28
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 Colstrip 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 that includes: (i) general and administrative expenses incurred by our corporate function; (ii) interest expense and other corporate activities not allocated to our operating segments; 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 September 30, 2024 (Successor)
Operating revenues
$
575
$
96
$
(21)
$
650
Interest expense
—
—
66
66
Capital expenditures
54
3
1
58
Adjusted EBITDA
217
28
245
Three Months Ended September 30, 2023 (Successor)
Operating revenues
$
343
$
243
$
(70)
$
516
Interest expense
—
—
68
68
Capital expenditures
50
16
3
69
Adjusted EBITDA
168
83
251
PJM
Other
Corporate and Eliminations
Total
Nine Months Ended September 30, 2024 (Successor)
Operating revenues
$
1,446
$
304
$
(102)
$
1,648
Interest expense
—
—
187
187
Capital expenditures
123
23
1
147
Adjusted EBITDA
592
71
663
May 18 through September 30, 2023 (Successor)
Operating revenues
$
698
$
213
$
(94)
$
817
Interest expense
—
—
101
101
Capital expenditures
73
26
4
103
Adjusted EBITDA
240
104
344
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
29
Successor
Predecessor
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Adjusted EBITDA:
PJM
$
217
$
168
$
592
$
240
$
688
Other
28
83
71
104
37
Total Segment Adjusted EBITDA
$
245
$
251
$
663
$
344
$
725
Reconciling Items:
Interest expense and other finance charges
(66)
(68)
(187)
(101)
(163)
Income tax benefit (expense)
(11)
16
(192)
(3)
(212)
Depreciation, amortization and accretion
(75)
(66)
(225)
(94)
(200)
Nuclear fuel amortization
(30)
(47)
(93)
(72)
(33)
Reorganization gain (loss), net
—
—
—
—
799
Unrealized (gain) loss on commodity derivative contracts
102
(84)
58
(43)
(63)
Nuclear decommissioning trust funds gain (loss), net
67
(24)
169
15
57
Stock-based compensation expense
(8)
(9)
(24)
(11)
—
Long-term incentive compensation expense
(3)
—
(19)
—
—
Gain (loss) on asset sales, net
—
—
885
—
50
Non-cash impairments
—
(2)
—
(2)
(381)
Operational and other restructuring activities
(40)
(4)
(61)
(30)
(17)
Development expenses
(1)
(5)
(1)
(7)
(10)
Non-cash inventory net realizable value, obsolescence, and other charges
(2)
2
(5)
(1)
(56)
Noncontrolling interest
3
14
21
22
14
Other items
2
(23)
13
(21)
(15)
Corporate and Eliminations
(15)
(27)
(57)
(41)
(30)
Net Income (Loss)
$
168
$
(76)
$
945
$
(45)
$
465
30
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.
於2024年9月30日結束的三個月（繼承人），公司根據其股份回購計劃回購了總共255,982,6股公司普通股，總購買價格為3,0400萬美元，包括交易成本和選擇稅，在加權平均每股價格為118.82美元。在此期間購買的總股份中，有2,413,793股是在2024年7月從Rubric Capital Management LP 的附屬機構購買的。
The following tables summarize average on-peak power prices and natural gas prices for the PJM market for the three months ended September 30, 2024 (Successor) and 2023 (Successor). During the third quarter 2024, natural gas prices for Texas Eastern M-3 settled below their ten-year average resulting from storage levels above the five-year average 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 weighted average settled market prices for the three months ended September 30 were:
2024
2023
PJM West Hub Day Ahead Peak - $/MWh
$
50.03
$
42.93
PJM PPL Zone Day Ahead Peak - $/MWh
37.54
29.46
PJM BGE Zone Day Ahead Peak - $/MWh
69.60
53.27
Texas Eastern M-3 - $/MMBtu
1.50
1.39
The PJM West Hub Day Ahead Peak 2024 quarter weighted average settled prices increased approximately 17% compared to the prior year.
The weighted average forward market prices for the periods from October 1 through December 31 as of September 30:
2024
2023
PJM West Hub ATC - $/MWh
$
42.67
$
41.32
Texas Eastern M-3 - $/MMBtu
2.47
2.68
PJM West Hub ATC Spark Spreads (a)
25.34
22.53
__________________
(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 Market Seller Offer Cap as determined by the PJM Independent Market Monitor.
PJM Capacity Auctions. Under its reliability pricing model, 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
32
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 PJM matters, including recent developments related to potential delays in future PJM BRAs.
Capacity Prices.The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:
2025/2026
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.
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 may be eligible 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 that could impact the credit value recognized to date and credit value available in future periods. 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, the 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.
33
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 September 30, 2024, the nine months ended September 30, 2024, and for the period May 18 through September 30, 2023 are referred to as the “Successor” periods. Our financial results for the period from January 1 through May 17, 2023 are referred to as the “Predecessor” period. The operating results for the nine months ended September 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 derivative instruments resulting from changes in fair value during the period 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.
Results for the Three Months Ended September 30, 2024 (Successor) and the Three Months Ended September 30, 2023 (Successor)
The following table and subsequent section display the results of operations:
Successor
(Millions of Dollars)
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Favorable (Unfavorable) Variance
Capacity revenues
$
50
$
44
$
6
Energy and other revenues
505
600
(95)
Unrealized gain (loss) on derivative instruments (Note 3)
95
(128)
223
Operating Revenues (Note 4)
650
516
134
Fuel and energy purchases
(222)
(253)
31
Nuclear fuel amortization
(30)
(47)
17
Unrealized gain (loss) on derivative instruments (Note 3)
7
44
(37)
Energy Expenses
(245)
(256)
11
Operating Expenses
Operation, maintenance and development
(127)
(140)
13
General and administrative
(38)
(37)
(1)
Depreciation, amortization and accretion (Note 8)
(75)
(66)
(9)
Impairments (Note 8)
—
(2)
2
Other operating income (expense), net
(7)
(8)
1
Operating Income (Loss)
158
7
151
Nuclear decommissioning trust funds gain (loss), net
67
(24)
91
Interest expense and other finance charges (Note 11)
(66)
(68)
2
Other non-operating income (expense), net
20
(7)
27
Income (Loss) Before Income Taxes
179
(92)
271
Income tax benefit (expense) (Note 5)
(11)
16
(27)
Net Income (Loss)
168
(76)
244
Less: Net income (loss) attributable to noncontrolling interest
—
1
(1)
Net Income (Loss) Attributable to Stockholders (Successor)
$
168
$
(77)
$
245
34
Successor Periods — Three Months Ended September 30, 2024 Compared to Three Months Ended September 30, 2023
Net Income (Loss) Attributable to Stockholders increased by $245 million, primarily driven by the factors discussed below.
•Operating Revenues, net of Energy Expenses. $145 million favorable increase due to the following:
Energy and Other Revenues, net of Fuel and Energy Purchases. $(64) million unfavorable decrease. This is primarily driven by (i) $(198) million decrease in realized energy margin from electric generation and ancillary revenue due to the ERCOT Sale in April 2024 and lower generation at Susquehanna, partially offset by higher realized prices at Susquehanna and PJM fossil plants; (ii) $73 million favorable increase in hedge results; and (iii) $71 million favorable increase in Nuclear PTC revenue.
Unrealized Gain (Loss) on Derivative Instruments, net. $186 million favorable increase. This is primarily driven by (i) $130 million of favorable increase in positions existing in both the third quarters 2024 and 2023 resulting from lower forward power prices; (ii) $35 million favorable increase due to lower unrealized losses on new trades executed in the third quarter 2024 as compared to trades executed in the third quarter 2023; and (iii) $32 million unrealized gain from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
•Nuclear Decommissioning Trust Funds Gain (Loss), net. $91 million favorable increase. This is primarily driven by an increase in unrealized gains on equity securities in 2024 as a result of investment returns and a decline in interest rates during the third quarter 2024. Investment return volatility resulted in losses in the comparative 2023 period. See Notes 7 and 12 in Notes to the Interim Financial Statements for additional information.
•Other Non-operating Income (Expense), net. $27 million favorable increase. This is primarily related to a decrease in pension litigation settlement charges recognized in 2023 and an increase in interest income in 2024. See Note 10 in Notes to the Interim Financial Statements for additional information on the pension litigation settlement.
•Income Tax Benefit (Expense). $(27) million unfavorable increase. This is driven by an increase to federal and state tax expense due to change in pre-tax book income, increase in unfavorable permanent differences, increase in production tax credits benefit, increase in NDT net tax expense, and decrease to valuation allowance expense.
35
Results for the Nine Months Ended September 30, 2024 (Successor), May 18 through September 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)
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Capacity revenues
$
141
$
70
$
108
Energy and other revenues
1,444
788
1,042
Unrealized gain (loss) on derivative instruments (Note 3)
63
(41)
60
Operating Revenues (Note 4)
1,648
817
1,210
Fuel and energy purchases
(535)
(310)
(176)
Nuclear fuel amortization
(93)
(72)
(33)
Unrealized gain (loss) on derivative instruments (Note 3)
(5)
(2)
(123)
Energy Expenses
(633)
(384)
(332)
Operating Expenses
Operation, maintenance and development
(445)
(209)
(285)
General and administrative
(121)
(55)
(51)
Depreciation, amortization and accretion (Note 8)
(225)
(94)
(200)
Impairments (Note 8)
—
(2)
(381)
Operational restructuring
—
—
—
Other operating income (expense), net
(14)
(11)
(37)
Operating Income (Loss)
210
62
(76)
Nuclear decommissioning trust funds gain (loss), net
169
15
57
Interest expense and other finance charges
(187)
(101)
(163)
Reorganization income (expense), net
—
—
799
Gain (loss) on sale of assets, net
885
—
50
Other non-operating income (expense), net
60
(18)
10
Income (Loss) Before Income Taxes
1,137
(42)
677
Income tax benefit (expense) (Note 5)
(192)
(3)
(212)
Net Income (Loss)
945
(45)
465
Less: Net income (loss) attributable to noncontrolling interest
29
3
(14)
Net Income (Loss) Attributable to Stockholders (Successor) / Member (Predecessor)
$
916
$
(48)
$
479
Successor Period — Nine Months Ended September 30, 2024
Net Income (Loss) Attributable to Stockholders totaled $916 million for the nine months ended September 30, 2024. Results were driven by:
•Capacity Revenues totaled $141 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM BRA for the 2023/2024 and 2024/2025 delivery periods.
•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $909 million. This consisted of: (i) $989 million in third-party wholesale electricity sales and ancillary revenues; (ii) $242 million in other revenue primarily related to Nuclear PTC and Bitcoin revenue; and (iii) $182 million in net realized gains from hedging activities. Such amounts were partially offset by $(504) million in fuel and purchased power costs.
•Unrealized Gain (Loss) on Derivative Instruments totaled $58 million gain, net. This consisted of: (i) unrealized gains incurred as a result of decreases in forward power prices; partially offset by (ii) unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
•Nuclear Fuel Amortization totaled $(93) million. This consisted of the periodic expense of nuclear fuel costs capitalized as property, plant and equipment. Activity also included $27 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence.
•Operation, Maintenance, and Development totaled $(445) 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.
36
•Depreciation, Amortization and Accretion totaled $(225) 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 $169 million. This consisted of unrealized gains on equity securities, realized gains and losses on debt and 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 $(187) 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 $564 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 $60 million. This is primarily due to interest income.
•Income Tax Benefit (Expense) totaled $(192) million. This primarily consists of federal and state income taxes, effects of permanent items, trust tax on income from the NDT, changes in valuation allowance, and excluded production tax credit income.
Successor Period — May 18 through September 30, 2023
Net Income (Loss) totaled $(48) million for the period of May 18 through September 30, 2023 (Successor). Results were driven by:
•Capacity Revenues totaled $70 million for the period, which were primarily based on resource clearing prices received from the PJM BRA for the 2023/2024 delivery period.
•Energy and Other Revenues, net of Fuel and Energy Purchases, totaled $478 million for the period and consisted of $729 million in third-party wholesale electricity sales and ancillary revenues, coupled with $44 million in other revenue; partially offset by $(240) million in fuel and purchased power costs and $(55) million in net realized losses from hedging activities. Other revenues relate to operations of Nautilus that commenced in February 2023.
•Unrealized Gain (Loss) on Derivative Instruments totaled $(43) million of net losses for the period, which was comprised of unrealized losses incurred as a result of increases in forward power prices, partially offset by unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.
•Nuclear Fuel Amortization totaled $(72) million for the period and was related to the amortization of nuclear fuel costs that were previously capitalized to property, plant and equipment. Activity in this period included $38 million of additional amortization related to certain nuclear contracts as a result of fair value adjustments.
•Operation, Maintenance, and Development totaled $(209) million for the period. This consists of generation facility operating costs, including salary and benefit costs for generation-facility employees, the costs of removal, repairs and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
•Depreciation, Amortization and Accretion totaled $(94) million for the period. This consists of depreciation of long-lived property, plant and equipment and accretion related to AROs. The period includes the effect of fair value adjustments made to property, plant and equipment and AROs upon Emergence.
•Interest Expense and Other Finance Charges totaled $(101) million for the period and primarily consisted of interest expense incurred on the Secured Notes, Term Loans, Cumulus Digital TLF, and LMBE-MC TLB.
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 BRA for the 2022/2023 delivery period. Capacity revenues were negatively impacted by $(13) million of net PJM capacity penalties related to Winter Storm Elliott.
37
•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 in February 2023.
•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, primarily consisting of non-cash charges for fuel inventory net realizable value adjustments. 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, and 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.
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 and (or) the Company’s discretionary expenditures.
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.
38
We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.
See the following Notes to the Interim Financial Statements for additional information regarding various liquidity topics discussed below: Note 3 for derivatives and hedging, Note 9 for AROs and environmental obligations, Note 11 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.
Talen Liquidity
Successor
September 30, 2024
December 31, 2023
Cash and cash equivalents, unrestricted
$
648
$
400
RCF
700
638
Available liquidity
$
1,348
$
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.
Financial Performance Assurances
Successor
September 30, 2024
December 31, 2023
Outstanding surety bonds
$
234
$
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, reduce the SOFR interest rate margin by 100 basis points and waive any prepayment obligations 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.
39
Cash Flow Activities
The net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30 were:
Successor
Predecessor
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Operating activities
$
246
$
180
$
462
Investing activities
1,225
(108)
(157)
Financing activities
(1,240)
(62)
(539)
Successor Period — Nine Months Ended September 30, 2024
•Investing Cash Flows. Cash provided by investing activities totaled $1,225 million. Talen received $635 million of proceeds from the Cumulus Data Campus Sale in the nine months ended September 30, 2024 (Successor), including $300 million of deferred proceeds that were received in the third quarter 2024, and $763 million of proceeds from the ERCOT Sale in the second quarter 2024, including $8 million of deferred proceeds that were received in the third quarter 2024. Partially offsetting these inflows were NDT fund investments, net of $(24) million and capital expenditures of $(147) million that primarily consisted of $(89) million for nuclear fuel expenditures and $(58) million for property, plant, and equipment. See Note 17 in Notes to the Interim Financial Statements for additional information on the Cumulus Data Campus Sale and the ERCOT Sale.
•Financing Cash Flows. Cash used in financing activities totaled $(1,240) million. This primarily consisted of $(182) million for the repayment of the Cumulus Digital TLF in the first quarter 2024 using a portion of the proceeds from the Cumulus Data Campus Sale; $(39) million in the first quarter 2024 for the repurchase of noncontrolling interests held by affiliates of Orion and two former members of Talen senior management; and $(956) million in the nine months ended September 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 $(31) million occurred to settle vested restricted stock units in cash.
Successor Period — May 18 through September 30, 2023
•Investing Cash Flows. Cash used in investing activities totaled $(108) million and primarily consisted of capital expenditures.
Capital expenditures, including those for nuclear fuel, totaled $(103) million and consisted of $(60) million across the Company for then-current projects including the Montour gas conversion project and the Cumulus Data Campus; and $(43) million related to nuclear-fuel expenditures as Talen purchased uranium needs for future periods.
•Financing Cash Flows. Cash used by financing activities totaled $(62) million and primarily consisted of $(59) million for payments to former affiliates to settle warrants and to repurchase affiliates’ noncontrolling interests in Cumulus Digital Holdings.
Predecessor Period — January 1 through May 17, 2023
•Investing Cash Flows. Cash 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 then-current projects including the Montour gas conversion project, the Cumulus Data Campus, the Nautilus crypto mining project, and projects at Susquehanna; and $(49) million related to nuclear fuel expenditures.
•Financing Cash Flows. Cash 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.
40
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.
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 Holdings contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.
Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of 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.
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:
41
Successor
Predecessor
(Millions of Dollars)
Three Months Ended September 30, 2024
Three Months Ended September 30, 2023
Nine Months Ended September 30, 2024
May 18 through September 30, 2023
January 1 through May 17, 2023
Net Income (Loss)
$
168
$
(76)
$
945
$
(45)
$
465
Adjustments
Interest expense and other finance charges
66
68
187
101
163
Income tax (benefit) expense
11
(16)
192
3
212
Depreciation, amortization and accretion
75
66
225
94
200
Nuclear fuel amortization
30
47
93
72
33
Reorganization (gain) loss, net (a)
—
—
—
—
(799)
Unrealized (gain) loss on commodity derivative contracts
(102)
84
(58)
43
63
Nuclear decommissioning trust funds (gain) loss, net
(67)
24
(169)
(15)
(57)
Stock-based compensation expense
8
9
24
11
—
Long-term incentive compensation expense
3
—
19
—
—
(Gain) loss on asset sales, net (b)
—
—
(885)
—
(50)
Non-cash impairments (c)
—
2
—
2
381
Operational and other restructuring activities
40
4
61
30
17
Development expenses
1
5
1
7
10
Non-cash inventory net realizable value, obsolescence, and other charges (d)
2
(2)
5
1
56
Noncontrolling interest
(3)
(14)
(21)
(22)
(14)
Other
(2)
23
(13)
21
15
Total Adjusted EBITDA
$
230
$
224
$
606
$
303
$
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.
42
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 September 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 September 30, 2024 (Successor) that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
43
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.
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
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. In September 2024, the Board of Directors increased the remaining capacity under the share repurchase program to $1.25 billion through December 31, 2026. 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 September 30, 2024:
Period
Purchased Shares (a)
Share Price (b)
Remaining Purchase Amount (c)
July 1 to July 31, 2024
2,413,793
$
116.00
$
107
August 1 to August 31, 2024
—
—
107
September 1 to September 30, 2024
146,033
144.83
1,229
Total
2,559,826
$
117.64
$
1,229
__________________
(a)All open market purchases were made under authorization from our Board of Directors to purchase up to $1.25 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 dollar value of shares (in millions) that may yet be purchased 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.
ITEM 3. DEFAULTS UPON SENIOR SECURITIES
None.
ITEM 4. MINE SAFETY DISCLOSURES
Not applicable.
ITEM 5. OTHER INFORMATION
During the three months ended September 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).
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 Holdings contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF 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.
AWS PPA. The March 2024 power purchase agreement between the Company and 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.
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.
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.
Colstrip. A generation facility comprised of four coal-fired generation units located in Colstrip, Montana. Talen Montana operates Colstrip, 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 Colstrip.
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 Data Campus. The zero-carbon data center campus initially developed by a subsidiary Cumulus Digital Holdings adjacent to Susquehanna. See Note 17 for information on the Cumulus Data Campus Sale.
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Cumulus Data Campus Sale. The Company’s sale of the Cumulus Data Campus to AWS in March 2024 to AWS for gross proceeds of $650 million. See Note 17 for more information.
Cumulus Digital Holdings. Cumulus Digital Holdings LLC, a subsidiary of TES that, through its subsidiaries, (i) initially developed the Cumulus Data Campus; and (ii) holds the Company's interest in Nautilus.
Cumulus Digital TLF. The term loan facility, due September 2027, under which a subsidiary of Cumulus Digital Holdings borrowed $175 million from affiliates of Orion to support required contributions to Nautilus and 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.
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.
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.
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.
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.
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. 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.
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 cryptocurrency joint venture owned, as of September 30, 2024, 75% by a subsidiary of Cumulus Digital Holdings and 25% by TeraWulf. In October 2024, the Company purchased TeraWulf’s minority interest and now owns 100% of Nautilus. See Note 15 for more information.
NAV. Net asset value.
NCI. Noncontrolling interest.
NDT. Nuclear facility decommissioning trust for Susquehanna.
NERC. North American Electric Reliability Corporation.
NRC. U.S. Nuclear Regulatory Commission.
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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.
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 coordinates the movement of wholesale electricity in all or parts of Pennsylvania, New Jersey, Maryland, 10 other states, and the District of Columbia.
PJM BRA. PJM Base Residual Auction, a component of PJM’s capacity market 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. 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.
PJM Capacity Year. PJM capacity revenues for delivery years cover the period from June 1 to May 31.
PJM RMR. A generation unit that is otherwise slated to be retired but agrees with PJM to remain operational beyond its requested deactivation date as a reliability-must-run resource to mitigate reliability concerns until necessary upgrades can be established.
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.
Predecessor. Relates to the financial position or results of operations of Talen Energy Supply for periods prior to Emergence, or May 17, 2023.
Prepetition CAF. The Credit Agreement, dated as of December 14, 2021, as subsequently amended, supplemented, or otherwise modified, among Talen Energy Supply, as parent, Talen Energy Marketing and Susquehanna, as borrowers, the lenders party thereto, and Alter Domus (US) LLC, as administrative agent, which established a senior secured commodity accordion revolving credit facility.
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. TEC’s registration statement on Form S-1 pursuant to the Securities Act of 1933, as filed with the Securities and Exchange Commission on June 20, 2024 (File No. 333-280341), as subsequently amended, supplemented, or otherwise modified.
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
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certain electric power generators to hold allowances equal to their carbon dioxide emissions over a three-year control period. Pennsylvania has proposed joining this program.
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 Montana. Talen Montana, LLC, a Talen subsidiary that operates Colstrip, owns an undivided interest in Colstrip Unit 3, and is party to a contractual economic sharing agreement for Colstrip Units 3 and 4.
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 Talen Energy Supply 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 Talen Energy Supply 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 non-profit corporation that assures a reliable and secure bulk electric system in the Western Interconnection, covering all or parts of Montana, 13 other U.S. States, Canada, and Mexico.
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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.