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Talen Energy Corp (TLN)

CIK: 0001622536. SIC: 4911 Electric Services. Latest 10-K as of: 2026-02-26.

SIC breadcrumb: Transportation, Communications, Electric, Gas, And Sanitary Services > Electric, Gas, And Sanitary Services > SIC 4911 Electric Services

SEC company page: https://www.sec.gov/edgar/browse/?CIK=1622536. Latest filing source: 0001622536-26-000017.

Selected Fundamentals

MetricValueUnitFYFiled
Revenue2,581,000,000USD20252026-02-26
Net income-219,000,000USD20252026-02-26
Assets10,905,000,000USD20252026-02-26

Financials

Annual standardized facts from SEC companyfacts as of latest extracted filing date 2026-02-26. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001622536.json. Derived margins are computed from the extracted annual SEC facts.

Flow metrics use full-year FY periods from 10-K/10-K/A filings; balance-sheet metrics use FY-end instants. Missing metrics are omitted rather than fabricated.

Metric20122013201420152022202320242025
Revenue3,089,000,0002,115,000,0002,581,000,000
Net income-230,000,000410,000,000-341,000,000998,000,000-219,000,000
Operating income-293,000,000397,000,000-39,000,000241,000,000226,000,000-90,000,000
Diluted EPS-2.754.91-3.1017.67-4.79
Assets10,760,000,00012,826,000,0007,059,000,0006,106,000,00010,905,000,000
Liabilities4,628,000,0004,719,000,0009,812,000,000
Stockholders' equity3,907,000,0004,303,000,0002,321,000,0001,387,000,0001,093,000,000
Cash and cash equivalents413,000,000239,000,000352,000,000141,000,000169,000,000328,000,000689,000,000
Net margin47.19%-8.49%
Operating margin7.80%10.69%-3.49%

Financial Charts

Quarterly

Quarterly standardized facts from SEC companyfacts as of latest extracted filing date 2026-05-05. Source: https://data.sec.gov/api/xbrl/companyfacts/CIK0001622536.json.

Flow metrics use discrete quarter-length periods from 10-Q/10-Q/A filings. Q4 revenue and net income are derived only when annual FY and nine-month YTD facts exist for the same fiscal year; derived Q4 values are labeled. EPS Q4 is not derived.

QuarterEnd DateRevenueNet IncomeDiluted EPSMethod
2015-Q22015-06-300.26reported discrete quarter
2015-Q32015-09-30-3.12reported discrete quarter
2016-Q12016-03-311.17reported discrete quarter
2016-Q22016-06-30-0.02reported discrete quarter
2016-Q32016-09-300.68reported discrete quarter
2024-Q22024-03-31319,000,000reported discrete quarter
2024-Q32024-06-30458,000,000reported discrete quarter
2024-Q22024-06-30489,000,0007.60reported discrete quarter
2024-Q32024-09-30650,000,0003.16reported discrete quarter
2024-Q42024-12-31467,000,00068,000,000derived Q4 = FY annual - nine-month YTD
2025-Q12025-03-31390,000,000-135,000,000-2.94reported discrete quarter
2025-Q22025-03-31-135,000,000reported discrete quarter
2025-Q32025-06-3072,000,000reported discrete quarter
2025-Q22025-06-30630,000,0001.50reported discrete quarter
2025-Q32025-09-30812,000,0004.25reported discrete quarter
2025-Q42025-12-31749,000,000-363,000,000derived Q4 = FY annual - nine-month YTD
2026-Q12026-03-311,129,000,00063,000,0001.33reported discrete quarter

Quarterly Charts

Macro Cross-References

Latest quarter (10-Q)

Latest 10-Q source: 0001622536-26-000036.

Extracted between Part I Item 2 and the next Item 3/4 or Part II heading after HTML sanitization. Confidence: high. Filing date: 2026-05-05. Report date: 2026-03-31.

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 (“MD&A”) should be read in conjunction with the Interim Financial Statements, the Annual Financial Statements, and the Notes thereto. The discussion contains forward-looking statements as well as estimates regarding market and industry data, which involve risks, uncertainties, and assumptions. See “Cautionary Note Regarding Forward-Looking Information” and “Market and Industry Data” for additional information. Dollars are in millions, unless otherwise noted.

Recent Developments

Financing Transactions

Unsecured Notes due 2031 and 2033. In April 2026, TES issued in private placement transactions not involving a public offering: (i) $1.5 billion in aggregate principal amount of 6.125% Senior Unsecured Notes due 2031; and (ii) $2.5 billion in aggregate principal amount of 6.375% Senior Unsecured Notes due 2033. We intend to use the net proceeds from the issuance and sale of the Unsecured Notes due 2031 and 2033 to fund: (i) the previously announced Cornerstone Acquisition and (ii) the redemption in full of the Company’s outstanding Secured Notes.

Secured Notes. In April 2026, using a portion of the net proceeds of the Unsecured Notes due 2031 and 2033, TES redeemed in full, the Company’s outstanding Secured Notes in aggregate principal amount of $1.2 billion.

Credit Facility Transactions. In April 2026, TES also undertook the following financing transactions that are expected to become effective concurrently with the closing of the Cornerstone Acquisition: (i) received commitments to increase its existing RCF (including its revolving LC capacity) from $900 million to $1.35 billion; and (ii) received commitments to upsize its existing $1.1 billion LCF to $1.5 billion and extend the maturity from December 2027 to December 2029.

See Notes 10 and 17 to the Interim Financial Statements for additional information on the financing transactions and the Cornerstone Acquisition.

Common Stock Repurchases

During the three months ended March 31, 2026, we repurchased and retired 300,000 shares of TEC’s outstanding common stock under the SRP. The aggregate purchase price, including transaction fees and excise tax, was $101 million at a weighted average price of $336.42 per share. As of March 31, 2026, the remaining capacity under the SRP is $1.9 billion through 2028. See Note 15 to the Interim Financial Statements for additional information on the SRP.

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Table of Contents

Cornerstone Acquisition

In January 2026, we entered into the Cornerstone Merger Agreement to acquire from affiliates of Energy Capital Partners (“ECP”) the 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana, for an aggregate purchase price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of TEC common stock, valued at approximately $900 million at the time of the entry into the Cornerstone Merger Agreement. The final value of the equity portion of the transaction price will be based on the value of TEC common stock at the close of the transaction. The cash portion of the purchase price will be funded from the proceeds of the Unsecured Notes due 2031 and 2033 which were issued in April 2026. The stock consideration will be subject to lock-ups of 90 days on 50% of the stock consideration and 180 days on the remaining stock consideration.

The addition of these assets to Talen’s portfolio will increase generation capacity by approximately 2.5 GW of natural gas generation, substantially expanding Talen’s presence in the western PJM market and adding additional efficient baseload generation assets to its fleet.

At the closing of the Cornerstone Acquisition, the Company intends to enter into the Cornerstone RRA with certain parties, under which it will use commercially reasonable efforts to file a registration statement on Form S-3 with the SEC to register the TEC common stock to be issued pursuant to the Cornerstone Merger Agreement within three business days (and in any event within five business days) after issuance.

The proposed Cornerstone Acquisition is subject to regulatory approvals and the satisfaction of other customary closing conditions, and is expected to close early in the second half of 2026.

See Note 17 to the Interim Financial Statements for additional information on the Cornerstone Acquisition and “Item 1A. Risk Factors—Risks Related to the Cornerstone Acquisition” of our 2025 Annual Report for a discussion of the associated risks.

The foregoing description of the Cornerstone Merger Agreement and the transaction contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Cornerstone Merger Agreement, a copy of which is incorporated by reference as Exhibit 2.1 to our 2025 Annual Report. The Cornerstone Merger Agreement was filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Cornerstone Merger Agreement, which may be subject to important limitations and qualifications, and which may change after the date of the Cornerstone Merger Agreement, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.

Factors Affecting Our Financial Condition and Results of Operations

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,” and Notes 2 and 9 to the Interim Financial Statements for additional information on our risks.

Commodity Markets

During the first quarter 2026, PJM experienced weather-related volatility as extreme temperatures over certain days contributed to increased load demand, resulting in higher settled on-peak power prices. Additionally, TETCO M-3 natural gas prices settled higher in the period due to the effect of increased electric demand resulting from the extreme temperature days in PJM driving natural gas prices to historic highs on those days. Natural gas storage levels during the quarter were near the 5-year average.

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended March 31, were:

2026

2025

PJM West Hub Day Ahead Peak - $/MWh

$

102.98 

$

60.50 

PJM PPL Zone Day Ahead Peak - $/MWh

86.95 

53.87 

PJM AEP-D Hub Day Ahead Peak - $/MWh

74.81 

53.40 

TETCO M-3 - $/MMBtu

9.61 

6.42 

The weighted average forward market prices for the periods from April 1 through December 31 as of March 31, were:

2026

2025

PJM West Hub ATC - $/MWh

$

57.85 

$

53.87 

PJM West Hub ATC Spark Spreads - $/MWh (a)

37.92 

27.30 

TETCO M-3 - $/MMBtu

2.85 

3.80 

__________________

(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

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Table of Contents

Capacity Markets

Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM market seller offer cap as determined by the PJM independent market monitor. Additionally, capacity prices may be affected by regulatory proceedings and (or) interventions by government stakeholders.

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.

Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2027/2028 PJM Capacity Year was held in December 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 9 to the Interim Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

2027/2028

2026/2027

2025/2026

2024/2025

2023/2024

PJM Capacity Performance ($/MWd) (a)

MAAC

$

333.44 

$

329.17 

$

269.92 

$

49.49 

$

49.49 

PPL

333.44 

329.17 

269.92 

49.49 

49.49 

__________________

(a)Displayed prices are from the applicable market publications.

For the 2027/2028 PJM Capacity Year, the Company cleared 8,745 MW at a price of $333.44/MWd.

Seasonality/Scheduled Maintenance

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We maintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna.

Susquehanna commenced its planned refueling outage on Unit 1 on March 23, 2026. We expect similar incremental maintenance activities that were performed on Unit 2 in 2025 to be performed during this outage on Unit 1, and anticipate the completion of the work in the first half of May 2026.

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Table of Contents

Results of Operations

The results of operations presented below are prepared in accordance with GAAP and should be reviewed in conjunction with the Interim Financial Statements and the related Notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the three months ended March 31, 2026, compared to the three months ended March 31, 2025.

In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the vari

[Excerpt truncated for page length; source filing is linked above.]

Latest 10-K MD&A

Extracted between Item 7 and the next Item 7A/8 heading after HTML sanitization. Confidence: high. Filing date: 2026-02-26. Report date: 2025-12-31.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

The following Management’s Discussion and Analysis of Financial Condition and Results of Operations (“MD&A”) should be read in conjunction with the Annual Financial Statements and the accompanying notes included elsewhere in this Report.

This MD&A discusses activity for the years ended December 31, 2025 (Successor) and December 31, 2024 (Successor). The operating results for the period from May 18 through December 31, 2023 (Successor) and for the period from January 1 through May 17, 2023 (Predecessor) are not comparable with the operating results for the years presented in this MD&A due to the application of fresh start accounting after our Emergence from Restructuring in May 2023. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in our 2024 Annual Report on Form 10-K, filed with the SEC on February 28, 2025, for a discussion of the activities and results of operations for each of these periods.

The discussion contains forward-looking statements as well as estimates regarding market and industry data, which involve risks, uncertainties, and assumptions. See “Cautionary Note Regarding Forward-Looking Information” and “Market and Industry Data” for additional information. Dollars are in millions, unless otherwise noted.

Recent Developments

Cornerstone Acquisition

On January 15, 2026, we entered into the Cornerstone Merger Agreement to acquire from affiliates of Energy Capital Partners (“ECP”) the 875 MW Waterford Energy Center and 456 MW Darby Generating Station, both located in Ohio, and the 1,120 MW Lawrenceburg Power Plant located in Indiana, for an aggregate purchase price of $3.45 billion, consisting of $2.55 billion in cash, subject to working capital and other customary adjustments, and 2,400,000 shares of Talen common stock, valued at approximately $900 million at the time of the entry into the Cornerstone Merger Agreement. The Company expects the cash portion of the purchase price to be funded from the proceeds of new indebtedness. The stock consideration will be subject to lock-ups of 90 days on 50% of the stock consideration and 180 days on the remaining stock consideration.

33

Form 10-K Table of Contents

The addition of these assets to Talen’s portfolio will increase generation capacity by approximately 2.5 GW of natural gas generation, substantially expanding Talen’s presence in the western PJM market and adding additional efficient baseload generation assets to its fleet.

In connection with the stock consideration, at the closing of the Cornerstone Acquisition, we intend to enter into the Cornerstone RRA with certain parties thereto substantially in the form attached to this Report as Exhibit 4.16. Pursuant to the terms of the Cornerstone RRA, the Company will agree to use its commercially reasonable efforts to file a registration statement on Form S-3 under the Securities Act of 1933, as amended, to register the TEC common stock issued pursuant to the Cornerstone Merger Agreement with the SEC within three business days (and in any event within five business days) after issuance. See also “Item 1A. Risk Factors—Financial and Equity Risks—A number of factors could adversely affect the market price or trading volume of our common stock, even if our business is doing well, including but not limited to substantial sales of our common stock by existing shareholders, future issuances of equity or debt securities by us, and (or) research or reports published by financial analysts.”

The proposed Cornerstone Acquisition is subject to regulatory approvals and the satisfaction of other customary closing conditions, and is expected to close early in the second half of 2026.

See Note 17 to the Annual Financial Statements for additional information on the Cornerstone Acquisition and “Item 1A. Risk Factors—Risks Related to the Cornerstone Acquisition” of this Report for a discussion of the associated risks.

The foregoing description of the Cornerstone Merger Agreement and the transaction contemplated thereby is only a summary, does not purport to be complete, and is qualified in its entirety by reference to the full text of the Cornerstone Merger Agreement, a copy of which is incorporated by reference as Exhibit 2.1 to this Report. The Cornerstone Merger Agreement is being filed only to provide investors with information regarding their terms and are not intended to provide any other factual information about the parties thereto. Investors should not rely on the representations, warranties, or covenants in the Cornerstone Merger Agreement, which may be subject to important limitations and qualifications, and which may change after the date of the Cornerstone Merger Agreement, as characterizations of the actual state of facts or condition of the Company, the sellers, or any of their respective subsidiaries or affiliates.

PJM 2027/2028 Base Residual Auction

In December 2025, PJM announced the results of the 2027/2028 PJM BRA. Talen cleared 8,745 MW at a price of $333.44/MWd.

See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets” for additional information.

Closing of the Freedom and Guernsey Acquisitions

In November 2025, the Company consummated the Freedom and Guernsey Acquisitions for an aggregate $3.8 billion which is subject to certain post-closing adjustments for net working capital and other customary items. The Freedom and Guernsey Acquisitions were funded from the proceeds of the Unsecured Notes and the TLB-3. Additionally, TES increased its RCF (including its revolving LC capacity) from $700 million to $900 million and increased its LCF from $900 million to $1.1 billion and extended its maturity from December 2026 to December 2027.

Issuance of Senior Notes. In October 2025, TES issued (i) $1.4 billion in aggregate principal amount of 6.25% Senior Unsecured Notes due 2034, and (ii) $1.3 billion in aggregate principal amount of 6.50% Senior Unsecured Notes due 2036.

See Notes 10 and 17 to the Annual Financial Statements for additional information on the financing transactions and issuance of the Unsecured Notes, and the Freedom and Guernsey Acquisitions, respectively.

Factors Affecting Our Financial Condition and Results of Operations

Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,” and Notes 2 and 9 to the Annual Financial Statements for additional information on our risks.

Commodity Markets

During 2025, PJM experienced weather-related volatility, as extreme winter and summer temperatures over certain days contributed to increased load demand and higher settled on-peak power prices during the year. TETCO M-3 natural gas prices settled higher in the period due to the effect of increased electric demand despite elevated storage levels that exceeded the five-year average.

34

Form 10-K Table of Contents

The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, were:

2025

2024

2023

PJM West Hub Day Ahead Peak - $/MWh

$

60.30 

$

40.91 

$

39.22 

PJM PPL Zone Day Ahead Peak - $/MWh

47.40 

31.51 

29.59 

TETCO M-3 - $/MMBtu

3.69 

2.07 

1.90 

As of December 31, 2025 (Successor), the weighted average forward market prices for the following years were:

2026

2027

PJM West Hub ATC - $/MWh

$

55.60 

$

59.29 

TETCO M-3 - $/MMBtu

3.69 

4.04 

PJM West Hub ATC Spark Spreads - $/MWh (a)

29.76 

31.00 

__________________

(a)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

As of December 31, 2024 (Successor), the weighted average forward market prices for the following years were:

2025 (a)

2026

2027

PJM West Hub ATC - $/MWh

$

47.43 

$

51.16 

$

54.34 

TETCO M-3 - $/MMBtu

3.45 

3.73 

3.72 

PJM West Hub ATC Spark Spreads - $/MWh (b)

23.25 

25.07 

28.27 

__________________

(a)Represents forward prices for 2025 as of December 31, 2024 (Successor). See weighted average settled prices table above for 2025 realized prices.

(b)Spark spreads are computed based on day-ahead PJM West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.

Capacity Markets

Our generation facilities are located primarily in markets with capacity products, which are intended to ensure long-term grid reliability for customers by securing sufficient power supply resources to meet predicted future demand. Capacity prices are affected by supply and demand fundamentals, such as generation facility additions and retirements, capacity imports from and exports to adjacent markets, generation facility retrofit costs, non-performance risk premium penalties, demand response products, power demand forecasts, reserve margin targets and, in PJM, adjustments to the PJM market seller offer cap as determined by the PJM independent market monitor. Additionally, capacity prices may be affected by regulatory proceedings and (or) interventions by government stakeholders.

PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM BRA is required to be conducted in the month of May three years prior to the start of the applicable PJM Capacity Year in order for PJM to secure commitments from capacity resources. The results of each PJM BRA impact our capacity revenues expected to be earned for the specific PJM Capacity Year.

Recently, PJM has delayed its auctions, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The PJM BRA for the 2027/2028 PJM Capacity Year was held in December 2025. The capacity market construct provides generation owners some opportunity for revenue visibility on a multiyear basis and is intended to provide a price signal for new generation to be built in the future. See Note 9 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, auction delays, and related legal actions.

Capacity Prices. The following table displays the cleared capacity prices for completed PJM BRAs for the markets and zones in which we primarily operate:

2027/2028

2026/2027

2025/2026

2024/2025

2023/2024

PJM Capacity Performance ($/MWd) (a)

MAAC

$

333.44 

$

329.17 

$

269.92 

$

49.49 

$

49.49 

PPL

333.44 

329.17 

269.92 

49.49 

49.49 

__________________

(a)Displayed prices are from the applicable market publications.

For the 2027/2028 PJM Capacity Year, the Company cleared 8,745 MW at a price of $333.44/MWd.

35

Form 10-K Table of Contents

Nuclear Production Tax Credit

The Nuclear PTC program, established by the Inflation Reduction Act, provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $44.60/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $26/MWh, and is subject to potential adjustments including inflation escalators and a five-times increase in value (up to $15/MWh) for meeting prevailing wage requirements (which we expect to meet). Electricity produced and sold by Susquehanna to third parties from December 31, 2023 through December 31, 2032 will be eligible for the credit. Susquehanna earned Nuclear PTC revenue during the year ended December 31, 2024 (Successor). However, as prevailing market prices exceeded the PTC recognition threshold during the year ended December 31, 2025 (Successor), no such tax credits were earned for the period. See Notes 3 and 4 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the tax impact.

Seasonality/Scheduled Maintenance

The demand for and market prices of electricity and natural gas are affected considerably by weather and, as a result, our operating results may fluctuate significantly on a seasonal basis. In general, below-average temperatures in the winter and above-average temperatures in the summer tend to increase electricity demand, energy prices, and revenues. Alternatively, moderate temperatures tend to decrease electricity demand and may adversely affect resulting energy margins, particularly in PJM. In addition, our operating expenses typically fluctuate geographically on a seasonal basis, with peak power generation and expenses during the winter in the Mid-Atlantic. We ordinarily perform planned facility maintenance during milder non-peak demand periods in the spring and fall to ensure reliability during peak periods. The pattern of fluctuations in our operating results varies depending on the type and location of the facilities being serviced, the capacity markets served, the maintenance requirements of our facilities, and the terms of bilateral contracts to purchase or sell electricity. We maintain our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. See also “Item 1A. Risk Factors—Industry and Market Risks—Our business is subject to physical, market, economic, and regulatory risks relating to weather conditions and extreme weather events.”

Results of Operations

The results of operations presented below are prepared in accordance with GAAP and should be reviewed in conjunction with the Annual Financial Statements and the related notes in this Report. The following discussion provides an analysis of the changes in our results of operations for the year ended December 31, 2025 (Successor), compared to the year ended December 31, 2024 (Successor).

In the explanations below, “Energy and other revenues” and “Fuel and energy purchases” are evaluated collectively because the price for power is generally determined by the variable operating cost of the next marginal generator dispatched to meet demand. “Energy and other revenues” relate to sales to an RTO or ISO, sales under wholesale bilateral contracts, realized hedges, Bitcoin revenue, and Nuclear PTC revenue. “Fuel and energy purchases” includes costs for fuel to generate electricity and settlements of financial and physical transactions related to fuel and energy purchases.

Unrealized gains (losses) on derivative instruments resulting from changes in fair value during the periods are presented separately as revenues within “Operating Revenues” and expenses within “Energy Expenses.” We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.

36

Form 10-K Table of Contents

Results for the Years Ended December 31, 2025 (Successor) and 2024 (Successor)

The following table and subsequent sections display the results of operations:

Successor

Favorable (Unfavorable) Variance

Year Ended December 31,

2025

2024

Energy and other revenues

$

2,141 

$

1,881 

$

260 

Capacity revenues

485 

192 

293 

Unrealized gain (loss) on derivative instruments (Note 2)

(45)

42 

(87)

Operating Revenues (Note 3)

2,581 

2,115 

466 

Fuel and energy purchases

(908)

(694)

(214)

Nuclear fuel amortization

(97)

(123)

26 

Unrealized gain (loss) on derivative instruments (Note 2)

(61)

20 

(81)

Energy Expenses

(1,066)

(797)

(269)

Operating Expenses

Operation, maintenance and development

(620)

(592)

(28)

General and administrative (includes stock-based compensation of $(526) and $(33)) (Note 13)

(624)

(163)

(461)

Depreciation, amortization and accretion (Note 7)

(279)

(298)

19 

Impairments (Note 7)

— 

(1)

1 

Other operating income (expense), net

(82)

(38)

(44)

Operating Income (Loss)

(90)

226 

(316)

Nuclear decommissioning trust funds gain (loss), net (Note 6)

182 

178 

4 

Interest expense and other finance charges (Note 10)

(302)

(238)

(64)

Gain (loss) on sale of assets, net (Note 17)

34 

884 

(850)

Other non-operating income (expense), net

10 

61 

(51)

Income (Loss) Before Income Taxes

(166)

1,111 

(1,277)

Income tax benefit (expense) (Note 4)

(53)

(98)

45 

Net Income (Loss)

(219)

1,013 

(1,232)

Less: Net income (loss) attributable to noncontrolling interest

— 

15 

15 

Net Income (Loss) Attributable to Stockholders (Successor)

$

(219)

$

998 

$

(1,217)

Year Ended December 31, 2025 (Successor) compared to Year Ended December 31, 2024 (Successor)

Net Income (Loss) Attributable to Stockholders decreased by $(1.2) billion, primarily driven by the factors discussed below.

•Operating Revenues, net of Energy Expenses. $197 million favorable increase, primarily due to the following:

◦Energy and other revenues, net of Fuel and energy purchases. $46 million favorable increase. This is primarily related to the effects of a $519 million increase in margin associated with electric generation and ancillary revenue, primarily due to higher realized prices at Susquehanna and our dispatchable generation facilities, and higher generation volumes at our dispatchable generation facilities. Such amounts are partially offset by (i) $(318) million decrease in digital revenue and Nuclear PTC revenue, coupled with (ii) $(155) million decrease in realized hedge results.

◦Capacity revenues. $293 million favorable increase. This is primarily driven by higher cleared capacity prices, partially offset by a decrease to lower cleared volumes through the PJM 2025/2026 BRA compared to the PJM 2024/2025 BRA.

◦Unrealized gain (loss) on derivative instruments, net. $(168) million unfavorable decrease. This is primarily related to the combined effects of: (i) $(82) million lower volume of hedge positions executed in the current period and (ii) $(45) million decrease in net short positions resulting from higher forward power prices, coupled with (iii) $(42) million unrealized losses from the reversal of positions previously recognized as mark-to-market assets which settled during the period.

◦Nuclear fuel amortization. $26 million favorable decrease. This is primarily related to a decrease in the amortization of intangible assets related to certain nuclear fuel supply contracts which have expired.

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Form 10-K Table of Contents

•Operation, maintenance and development. $(28) million unfavorable increase. This is primarily due to increased maintenance costs, including the incremental maintenance at Susquehanna performed during its extended planned Unit 2 refueling outage in the spring of 2025, partially offset by lower maintenance costs at ERCOT and development costs at Cumulus Digital, both of which were sold in 2024.

•General and administrative. $(461) million unfavorable increase. This primarily consisted of a $(493) million increase of stock-based compensation expense primarily due to a change in accounting for certain stock-based awards. See Note 13 to the Annual Financial Statements for additional information. This was offset by a $32 million decrease in other compensation.

•Depreciation, amortization and accretion. $19 million favorable decrease. This is primarily due to a decrease in amortization and depreciation because of the derecognition of Nautilus assets in June 2025. See Note 7 to the Annual Financial Statements for additional information.

•Other operating income (expense), net. $(44) million unfavorable increase. This is primarily related to transaction costs for the Freedom and Guernsey Acquisitions and the loss resulting from the sale of Nuclear PTCs.

•Interest expense and other finance charges. $(64) million unfavorable increase. This primarily consisted of: (i) a $(34) million increase in cash interest expense on the Unsecured Notes, TLB-2, and TLB-3, partially offset by the absence of interest expense on the TLC and lower interest expense on the TLB-1, and (ii) a $(30) million increase in non-cash interest expense resulting from changes in unrealized positions on interest rate swaps and increases in deferred finance cost amortization. See Note 10 to the Annual Financial Statements for additional information on activity related to the above debt instruments.

•Gain (loss) on sale of assets, net. $(850) million unfavorable decrease. This primarily consisted of: (i) $564 million gain from the ERCOT Sale and (ii) $324 million gain from the AWS Data Campus Sale, both of which closed in 2024; and (iii) a $22 million gain from the sale of the Camden and Dartmouth in September 2025. See Note 17 to the Annual Financial Statements for additional information.

•Other non-operating income (expense), net. $(51) million unfavorable decrease. This primarily consisted of lower interest income on cash deposits in 2025 due to the release of restricted cash in 2024 after refinancing the TLC, combined with additional debt restructuring fees in 2025. See Note 19 to the Annual Financial Statements for additional information.

•Income tax benefit (expense). $45 million favorable decrease. This is primarily due to a decrease in pre-tax income for the year ended December 31, 2025 (Successor), the absence of valuation adjustments and the tax benefit associated with the Nuclear PTC recognized in 2024, and changes in nondeductible and other items. See the reconciliation of the effective tax rate in Note 4 to the Annual 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 hedging activities including cash collateral and other forms of credit support; (v) the settlement of, or forms of credit in support of, legacy asset retirement and (or) environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.

Our primary sources of liquidity and capital include available cash deposits, cash flows from operations, amounts available under our debt and credit facilities, and potential incremental financing proceeds. Generating sufficient cash flows for our business is primarily dependent on capacity revenue, the production and sale of power at margins sufficient to cover fixed and variable expenses, hedging strategies to manage price risk exposure, and the ability to access a wide range of capital market financing options.

Our hedging strategy is focused on maintaining appropriate risk tolerances with an emphasis on protecting cash flows across our generation fleet. Our strong balance sheet provides ample capacity and counterparty appetite for lien-based hedging, which limits the use of margin posting requirements. Specifically, our hedging strategy prioritizes a first lien-based hedging program, in which hedging counterparties are granted a lien in the same collateral securing our first-lien debt obligations, while minimizing exchange-based hedging and the associated margin requirements. Additionally, the stability provided by contracted cash flows associated with long-term contracts lowers our overall hedging requirements.

We are partially exposed to financial risks arising from natural business exposures including commodity price and interest rate volatility. Within the bounds of our risk management program and policies, we use a variety of derivative instruments to enhance the stability of future cash flows to maintain sufficient financial resources for working capital, debt service, capital expenditures, debt covenant compliance, and (or) other needs.

See the following Notes to the Annual Financial Statements for additional information on liquidity topics discussed below: Note 2 for derivatives and hedging, Note 8 for AROs and environmental obligations, Note 10 for long-term debt and credit facilities, and Note 16 for supplemental cash flow information.

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Form 10-K Table of Contents

Liquidity and Letter of Credit Capacity

Successor

December 31,

2025

December 31,

2024

Cash and cash equivalents, unrestricted

$

689 

$

328 

Unutilized RCF capacity (a)

900 

700 

Total available liquidity

$

1,589 

$

1,028 

Additional unutilized LC capacity (b)

$

652 

$

526 

__________________

(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.

(b)Includes LC capacity under the LCF and excludes LC capacity available under the RCF.

Based on current and anticipated levels of operations, industry conditions, and market environments in which we transact, we believe available liquidity from financing activities, cash on hand, and cash flows from operations (including changes in working capital) will be adequate to meet working capital, debt service, capital expenditures, and (or) other future requirements for the next twelve months and beyond. See Note 10 to the Annual Financial Statements for additional information on the RCF and LCF.

Financial Performance Assurances

TES has provided financial performance assurances in the form of surety bonds to third parties on behalf of certain subsidiaries for obligations including but not limited to environmental obligations and AROs. Surety bond providers generally have the right to request additional collateral to backstop surety bonds.

Successor

December 31,

2025

December 31,

2024

Outstanding surety bonds

$

228 

$

234 

In May 2025, the Company elected to replace a surety provider and, as of December 31, 2025 (Successor), the replacement surety bonds issued by the new provider were outstanding. However, an aggregate $6 million of replaced surety bonds (included in the total above) continued to be outstanding as their release was not yet completed as of December 31, 2025 (Successor).

Forecasted Uses of Cash

Indebtedness. See Note 10 to the Annual Financial Statements and “—Recent Developments” above for additional information on our indebtedness.

Capital Expenditures. Capital expenditure plans are revised periodically for changes in operational needs, market conditions, regulatory requirements, and cost projections. Accordingly, the expected cash requirements for capital expenditures are subject to revision.

2026

2027

Nuclear fuel

$

122 

$

137 

PJM nuclear generation facility

53 

46 

PJM fossil generation facilities

118 

73 

Other

25 

12 

Total (a)

$

318 

$

268 

__________________

(a)Expected capitalized interest on capital expenditures is a non-material amount in 2026 and 2027.

Projected ARO and Accrued Environmental Liability Cash Flows. Certain of our subsidiaries have legal obligations to perform significant decommissioning and remediation activities associated with current operations and (or) at former generation facility sites. We believe the NDT, which was established to fund the Company’s proportionate share of Susquehanna’s ARO decommissioning costs, will be adequate when decommissioning commences at the expiration of Susquehanna’s licenses.

39

Form 10-K Table of Contents

Non-nuclear AROs and accrued environmental costs are expected to be funded with available cash on hand. The majority of these obligations relate to ash impoundments at Colstrip, Brunner Island, and Montour. Based on the scope of work, a significant portion of the Colstrip and Brunner Island obligations are expected to be settled through 2030 as remediation activities are scheduled for completion. Settlements thereafter are forecasted to continue at reduced levels for several decades. No assurance can be provided as to the timing or amount of ARO and (or) accrued environmental cost settlements. Projections are subject to revision based on changes to the scope of work, estimated inflation rates, changes in the estimated timing of settling AROs, escalating retirement costs, and (or) other projections. Additionally, projections do not contemplate settlements for conditional AROs, which are AROs not presented on the consolidated balance sheets as they cannot be determined. See Note 8 to the Annual Financial Statements for additional information on AROs and Note 9 for additional information on the EPA CCR Rule.

As of December 31, 2025 (Successor), the expected undiscounted payments of non-nuclear AROs are estimated to be:

2026

2027

2028

2029

2030

Thereafter

Total

Accrued environmental costs

$

3 

$

3 

$

4 

$

4 

$

3 

$

13 

$

30 

Non-nuclear AROs (a)

40 

53 

47 

56 

38 

255 

489 

__________________

(a)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.

Cash Flow Activities

Net cash provided by (used in) operating, investing, and financing activities for the periods was:

Successor

Favorable (Unfavorable) Variance

Year Ended December 31,

2025

2024

Operating activities

$

704 

$

256 

$

448 

Investing activities

(4,003)

1,171 

(5,174)

Financing activities

3,686 

(1,963)

5,649 

Operating activities

A change of $448 million in net cash provided by (used in) operating activities is generally aligned with results from operations combined with working capital changes in the normal course of business. See “—Results of Operations” for additional information.

Investing activities

A change of $(5.2) billion in net cash provided by (used in) investing activities was primarily due to: (i) $(3.8) billion used to finance the Freedom and Guernsey Acquisitions in 2025; (ii) a $(635) million decrease in proceeds from the AWS Data Campus Sale in 2024; and (iii) a $(763) million decrease in proceeds from the ERCOT Sale in 2024. See Note 17 to the Annual Financial Statements for additional information on acquisitions and divestitures.

Financing activities

A change of $5.6 billion in net cash provided by (used in) financing activities was primarily due to: (i) $3.9 billion in new debt from the TLB-3 and the Unsecured Notes raised in 2025; (ii) $(370) million of net debt issuances in 2024; (iii) $182 million repayment of the Cumulus Digital TLF and (iv) $125 million purchase of noncontrolling interest in Cumulus Digital, both of which closed in 2024; and (v) a $1.9 billion decrease in share repurchases.

Non-GAAP Financial Measure

Adjusted EBITDA, which we use as a measure of our performance, is not a financial measure prepared under GAAP. Non-GAAP financial measures do not have definitions under GAAP and may be defined and calculated differently by, and not be comparable to, similarly titled measures used by other companies. Non-GAAP measures are not intended to replace the most comparable GAAP measures as indicators of performance. Generally, a non-GAAP financial measure is a numerical measure of financial performance, financial position, or cash flows that excludes (or includes) amounts that are included in (or excluded from) the most directly comparable measure calculated and presented in accordance with GAAP. Management cautions readers not to place undue reliance on the following non-GAAP financial measure, but to also consider it along with its most directly comparable GAAP financial measure. Non-GAAP measures have limitations as analytical tools and should not be considered in isolation or as a substitute for analyzing our results as reported under GAAP.

40

Form 10-K Table of Contents

Adjusted EBITDA

We use Adjusted EBITDA to: (i) assist in comparing operating performance and readily view operating trends on a consistent basis from period to period without certain items that may distort financial results; (ii) plan and forecast overall expectations and evaluate actual results against such expectations; (iii) communicate with our Board of Directors, shareholders, creditors, analysts, and the broader financial community concerning our financial performance; (iv) set performance metrics for our annual short-term incentive compensation; and (v) assess compliance with our indebtedness.

Adjusted EBITDA is computed as net income (loss) adjusted, among other things, for certain: (i) nonrecurring charges; (ii) non-recurring gains; (iii) non-cash and other items; (iv) unusual market events; (v) any depreciation, amortization, or accretion; (vi) mark-to-market gains or losses; (vii) gains and losses on the NDT; (viii) gains and losses on asset sales, dispositions, and asset retirement; (ix) impairments, obsolescence, and net realizable value charges; (x) interest expense; (xi) income taxes; (xii) legal settlements, liquidated damages, and contractual terminations; (xiii) development expenses; (xiv) noncontrolling interests, except where otherwise noted; and (xv) other adjustments. Such adjustments are computed consistently with the provisions of our indebtedness to the extent that they can be derived from the financial records of the business. Pursuant to TES’s debt agreements, Cumulus Digital contributes to Adjusted EBITDA beginning in the first quarter 2024, following termination of the Cumulus Digital TLF and associated cash flow sweep.

Additionally, we believe investors commonly adjust net income (loss) information to eliminate the effect of nonrecurring restructuring expenses and other non-cash charges, which can vary widely from company to company and from period to period and impair comparability. We believe Adjusted EBITDA is useful to investors and other users of our financial statements to evaluate our operating performance because it provides an additional tool to compare business performance across companies and between periods. Adjusted EBITDA is widely used by investors to measure a company’s operating performance without regard to such items described above. These adjustments can vary substantially from company to company and period to period depending upon accounting policies, book value of assets, capital structure, and the method by which assets were acquired.

The following table presents a reconciliation of the GAAP financial measure of “Net Income (Loss)” presented on the Consolidated Statements of Operations to the non-GAAP financial measure of Adjusted EBITDA:

Successor

Predecessor

(Millions of Dollars)

Year Ended December 31, 2025

Year Ended December 31, 2024

May 18 through December 31, 2023

January 1 through May 17, 2023

Net Income (Loss)

$

(219)

$

1,013 

$

143 

$

465 

Adjustments

Interest expense and other finance charges

302 

238 

176 

163 

Income tax (benefit) expense

53 

98 

51 

212 

Depreciation, amortization and accretion (a)

266 

281 

157 

200 

Nuclear fuel amortization (a)

97 

123 

108 

33 

Reorganization (income) expense, net (Note 20) (b)

— 

— 

— 

(799)

Unrealized (gain) loss on commodity derivative contracts

106 

(62)

(52)

63 

Nuclear decommissioning trust funds (gain) loss, net

(182)

(178)

(108)

(57)

Stock-based and other long-term incentive compensation expense (Note 13) (b)

535 

54 

21 

— 

(Gain) loss on asset sales, net (Note 17) (b)

(34)

(884)

(7)

(50)

Non-cash impairments and other charges (c)

11 

24 

15 

438 

Legal settlements and litigation costs

6 

4 

(84)

1 

Acquisition and divestiture activities (d)

65 

62 

— 

— 

Operational and other restructuring activities (e)

21 

9 

30 

19 

Noncontrolling interest

— 

(21)

(42)

(14)

Other

8 

9 

18 

21 

Total Adjusted EBITDA

$

1,035 

$

770 

$

426 

$

695 

__________________

(a)Includes the periodic amortization of fair value adjustments associated with acquired executory contracts and intangible assets.

(b)See the corresponding Note to the Annual Financial Statements for additional information.

(c)Includes impairments, net realizable value adjustments and other write-offs. See Note 7 to the Annual Financial Statements for additional information associated with the Brandon Shores impairment group recognized during the period of January 1 through May 17, 2023 (Predecessor).

(d)Includes the non-recurring: (i) advisory fees associated with completed acquisitions and divestitures; (ii) remaining settlements on contracts of divested assets; and (iii) non-recurring finance fees charged to the Consolidated Statement of Operations associated with acquisition financing fee arrangements.

(e)Non-recurring severance and retention costs and strategic initiative costs.

41

Form 10-K Table of Contents

Critical Accounting Estimates

Financial statements prepared in conformity with GAAP 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 the inherent uncertainties of future events that 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. We believe the following areas contain the most significant accounting judgments, the highest levels of subjectivity, or relate to uncertain matters that are susceptible to material changes in estimates that are critical to understanding the Company’s financial results. Due to such inherent uncertainties, actual results may differ substantially from estimates and (or) estimates may change materially in periods where new information becomes known. Management develops these estimates based on best available information, historical experience, and subject matter experts.

See Note 1 to the Annual Financial Statements for accounting policies related to each of the following topics.

Business Combinations

The purchase price paid by the Company to acquire a business is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values as of the acquisition date. If the purchase price exceeds the net fair value of the acquired business, the difference is recognized as goodwill on the consolidated balance sheet. Conversely, a bargain purchase gain is recognized on the consolidated statement of operations if the purchase price of an acquired business is below its net fair value.

Valuations of material long-term assets and (or) liabilities associated with an acquired business that lack quoted market prices contain the most significant fair value assumptions as they require substantial management judgment due to inherently uncertain future market, regulatory, and operational conditions. The Company engages third party specialists to assist with the preparation of fair value estimates as of the acquisition date utilizing present value techniques. The most significant factors influencing fair value measurements include: (i) the forecasted prices for capacity, wholesale power, and natural gas; (ii) volumetric assumptions; and (iii) discount rates. Although these inputs are believed to be consistent with reasonable market participant-based assumptions, the resulting fair value estimates are inherently unpredictable and uncertain. Changes to these assumptions may result in materially different fair value estimates, which in turn, could result in a different expense recognition pattern for future depreciation and amortization.

If the preliminary accounting for a business combination is incomplete by the end of the reporting period in which an acquisition occurs, purchase price allocation estimates are recognized on the consolidated balance sheet. Revisions to such estimates are permitted within one year from the acquisition date based on new information obtained that would have existed as of the acquisition date. Any adjustment that arises from information obtained that did not exist as of the acquisition date is recognized in the period in which the adjustment arises.

See Note 17 to the Annual Financial Statements for additional information on business combinations.

Nuclear Decommissioning Asset Retirement Obligations

We have significant legal obligations associated with Susquehanna’s decommissioning. Susquehanna’s Unit 1 and Unit 2 licenses, if not renewed, will expire in 2042 and 2044, respectively, at or before which time the units will be shut down.

Judgment is required to make reasonable ARO assumptions regarding the range of likely outcomes for cost estimates, as these obligations are not expected to be paid until years or decades in the future, and potentially many years after shutdown. Inflation rates and discount rates may be subject to revision until the ARO settlement date. As such, changes in assumptions to the range of likely outcomes could result in different cash outlay for AROs at the settlement date than the current carrying value of the ARO presented on the Consolidated Balance Sheets. Susquehanna periodically assesses its ARO through third-party engineering studies in order to determine expected scope, costs, and timing of decommissioning activities. Generally, its decommissioning cost study is updated approximately every seven years. As part of the cost study update process, we and the third-party engineering firm evaluate cost projections based on the latest engineering techniques and the latest information, which incorporates nuclear plant retirements in the industry. We use the results of the study along with our experience, knowledge, and professional judgment to update Susquehanna’s decommissioning plan and the related carrying value of the ARO.

AROs are recognized at fair value at the time of installation of the related asset and as an increase to PP&E. The income effect of AROs is generally presented as “Depreciation, amortization and accretion” on the Consolidated Statements of Operations through the expected ARO settlement date. However, for an asset that has a fully depreciated PP&E carrying value, revisions in ARO estimates have an immediate effect in earnings. Revisions to the estimated ARO are presented as “Other operating income (expense), net” on the Consolidated Statements of Operations.

See Note 8 to the Annual Financial Statements for additional information on AROs.

42

Form 10-K Table of Contents

Derivative Instruments

Derivative instruments, which are deployed by our commercial organization to manage and (or) mitigate market and commodity price risk, are presented on the Consolidated Balance Sheets at fair value and are comprised primarily of power and natural gas commodity contracts. Derivative identification is challenging. While a conventional financially settled contract, such as a swap or option, generally contains standard terms that facilitate its identification as a derivative instrument, judgment is required to determine whether contracts to buy or sell commodities with physical delivery requirements, or contracts that contain certain embedded settlement or fluctuating price features, meet the definition of a derivative instrument. This judgment typically includes, among other things, an evaluation of the contract, its expected cash flows, and the activity levels of its principal market. Additionally, judgment is required to determine if a commodity contract intended for physical delivery meets an allowable exemption to account for its income effects under the accrual accounting method rather than at fair value. This typically includes assumptions regarding the probability of physical delivery and the quantities used in normal business activities.

As our derivative contracts generally settle within future time periods supportable by commodity exchange markets and the frequent occurrence of commercial transactions, our derivative contracts are valued using a market approach utilizing quoted prices in active markets or other observable market inputs to determine fair value. However, such prices are subject to volatility between periods based on weather, local market events, macroeconomic trends, and (or) other events and factors. Accordingly, changes in fair value for contracts identified as derivatives may result in material changes to unrealized gains or losses presented on the Consolidated Statements of Operations between periods. Changes in fair value of commodity derivatives are presented as “Unrealized gain (loss) on derivative instruments” as a component of either “Operating Revenues” or “Fuel and energy purchases” on the Consolidated Statements of Operations, in a consistent manner with the presentation of its realized net gains or losses.

See Note 2 to the Annual Financial Statements for additional information on derivative instruments.

Postretirement Benefit Obligations

Certain of our subsidiaries sponsor postemployment benefits that include defined benefit pension plans. Accounting for defined benefit pensions involves significant estimates to determine projected benefit obligations and company contribution requirements, which inherently require assumptions be made regarding many uncertainties. Such uncertainties include discount rates, expected return on assets, expected wages for participants at retirement, estimated retirement dates, and mortality rates. Over a period of time, we are required to fund all vested benefits for postretirement defined benefit pension plans through plan assets, investment returns, or contributions to the plans.

Actuarial assumptions required under GAAP to determine the projected benefit obligations and actuarial assumptions required under ERISA to determine contribution assumptions differ in their objectives. Actuarial assumptions regarding projected benefit obligations under GAAP affect the net periodic defined benefit cost presented within our Consolidated Statements of Operations. Actuarial assumptions used in the computation to estimate required contributions to the defined benefit plans affect funding requirements over a period of time.

We are responsible for the estimates regarding our postemployment benefits. However, we engage actuarial firms, who apply professional standards in the determination of the judgmental assumptions for plan contributions, to estimate both the contribution requirements for postemployment benefits and the associated projected benefit obligations under GAAP.

Projected benefit obligations are particularly sensitive to expected return on plan assets and the discount rate. The expected return on plan assets is the estimated long-term rates of return on plan assets that will be earned over the life of each plan. These projected returns reduce the net periodic defined benefit costs. The discount rate is used to compute the present value of benefits, which is based on projections of benefit payments to be made in the future. The objective in selecting the discount rate is to measure the single amount that, if invested at the measurement date in a portfolio of high-quality debt instruments, would provide the necessary future cash flows to pay the accumulated benefits when due. See Note 12 to the Annual Financial Statements for the weighted-average assumptions used for the discount rate and expected return on plan assets for all plans.

A variance in the discount rate or expected return on plan assets could have a significant impact on postretirement benefit obligations and annual net periodic pension costs. The following table displays the estimated increase (decrease) for defined benefit pension plans of a 1% increase and a 1% decrease in the discount rate and expected return on plan assets on the postretirement benefit obligation and net periodic pension cost as of December 31, 2025 (Successor).

Sensitivity

Actuarial Assumption

1% Increase

1% Decrease

Discount rate

Postretirement benefit obligation

$

(106)

$

126 

Net periodic pension cost

4 

(6)

Expected return on plan assets

Net periodic pension cost

(10)

10 

43

Form 10-K Table of Contents

Income Taxes

Significant management estimates and judgments are involved to determine the provision for income taxes, deferred tax assets and liabilities, and valuation allowances.

An assessment is performed on a quarterly basis to determine the likelihood of realizing deferred tax assets. We assess the probability of realizing deferred tax assets by evaluating historical income after adjusting for certain nonrecurring items for purposes of projecting future income, our intent and ability to implement tax planning strategies, and performing scheduling of the reversal of temporary differences. We also evaluate negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate an inability to realize deferred tax assets. Based on the combined assessment, we recognize valuation allowances for deferred tax assets when it is more likely than not such benefit will not be realized in future periods.

Actual income taxes could vary from estimated amounts due to the future impacts of various items, including changes in income tax laws, forecasted financial conditions, and results of operations in future periods, as well as results of audits and examinations of filed tax returns by taxing authorities. See Note 4 to the Annual Financial Statements for additional information on income taxes.

Recent Accounting Pronouncements

See Note 1 to the Annual Financial Statements for a description of recently issued accounting pronouncements not yet adopted. There have been no recently adopted accounting pronouncements that had a material effect on the Company’s financials statements and (or) disclosures.