Talen Energy Corp
For the period ended Dec 31, 2025. Filed Feb 26, 2026.
View on SEC.govAbout this filing
A company's yearly report to the SEC, with audited financial statements. It is the fullest account a company gives of its business, its finances and the risks it sees.
FY2025 · Filed Feb 26, 2026
TLN$338.64+7.1%Stored close · as of Nov 6, 2026
What changed in Management’s Discussion and Analysis?
Read the current filingPrevious report: 10-K
Period ended 2024-12-31; filed 2025-02-28.
0001628280-25-008786
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSCurrent report: 10-K
Period ended 2025-12-31; filed 2026-02-26.
0001622536-26-000017
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONSThe baseline is this issuer’s latest earlier reporting period of the same form that was filed before the current report. A previous 10-Q is a different quarter, not a year-over-year comparison. Amendments are excluded.
Compared 179 previous paragraphs and 131 current paragraphs.
43 unchanged; 33 reworded; 53 added; 103 removed; 0 previous and 2 current paragraphs rearranged.
Tables are not compared: 12 previous and 12 current tables excluded. Dates, whitespace, punctuation and numbering changes are ignored; changes to financial figures remain significant.
A changed paragraph is not evidence that risk increased or decreased. An unchanged paragraph does not establish that risk stayed the same.
Added paragraphs (53)
Current report
Cornerstone Acquisition
Current report
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.
Current report
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.
Current report
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.”
Current report
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.
Current report
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.
Current report
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.
Current report
PJM 2027/2028 Base Residual Auction
Current report
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.
Current report
See “—Factors Affecting Our Financial Condition and Results of Operations—Capacity Markets” for additional information.
Current report
Closing of the Freedom and Guernsey Acquisitions
Current report
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.
Current report
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.
Current report
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.
Current report
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.
Current report
For the 2027/2028 PJM Capacity Year, the Company cleared 8,745 MW at a price of $333.44/MWd.
Current report
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).
Current report
Results for the Years Ended December 31, 2025 (Successor) and 2024 (Successor)
Current report
Year Ended December 31, 2025 (Successor) compared to Year Ended December 31, 2024 (Successor)
Current report
Net Income (Loss) Attributable to Stockholders decreased by $(1.2) billion, primarily driven by the factors discussed below.
Current report
•Operating Revenues, net of Energy Expenses. $197 million favorable increase, primarily due to the following:
Current report
◦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.
Current report
◦Capacity revenues.$293 million favorable increase. This is primarily driven by higher cleared capacity prices, partially offset by a decrease to lower cleared volumes through the PJM 2025/2026 BRA compared to the PJM 2024/2025 BRA.
Current report
◦Unrealized gain (loss) on derivative instruments, net.$(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.
Current report
◦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.
Current report
•Operation, maintenance and development. $(28) million unfavorable increase. This is primarily due to increased maintenance costs, including the incremental maintenance at Susquehanna performed during its extended planned Unit 2 refueling outage in the spring of 2025, partially offset by lower maintenance costs at ERCOT and development costs at Cumulus Digital, both of which were sold in 2024.
Current report
•General and administrative.$(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.
Current report
•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.
Current report
•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.
Current report
•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 $(30) million increase in non-cash interest expense resulting from changes in unrealized positions on interest rate swaps and increases in deferred finance cost amortization. See Note 10 to the Annual Financial Statements for additional information on activity related to the above debt instruments.
Current report
•Other non-operating income (expense), net.$(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.
Current report
•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.
Current report
Financial Performance Assurances
Current report
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).
Current report
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 conditi onal 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.
Current report
Operating activities
Current report
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.
Current report
Investing activities
Current report
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.
Current report
Financing activities
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Removed paragraphs (103)
Previous report
Common Stock Transactions
Previous report
Share Repurchases. During the year ended December 31, 2024 (Successor), we repurchased and retired a total of 13,227,222 shares, or approximately 22%, of TEC’s outstanding common stock through a combination of the SRP and direct repurchases from affiliates of Rubric Capital Management LP (collectively, “Rubric”). A total of: (i) 7,307,300 shares were purchased from Rubric; (ii) 5,275,862 shares through a tender offer; and (iii) 644,060 shares in the open market. The aggregate purchase price after transaction fees and excise tax was approximately $2.0 billion at a weighted average price of $149.50 per share. As of December 31, 2024 (Successor), the remaining capacity under the SRP is approximately $1.1 billion through 2026.
Previous report
See Note 18 to the Annual Financial Statements for additional information on the SRP, other share repurchases, and other common stock transactions.
Previous report
Financing Transactions
Previous report
Secured Notes Consent. In January 2025, we received consents from noteholders representing a majority in principal amount of the Secured Notes to adopt certain amendments to the Indenture to, among other things: (i) modify certain provisions, including certain covenants and related definitions, in order to substantially conform to the corresponding amendments to the Credit Agreement obtained in the December 2024 transactions discussed below; and (ii) waive TES’s right to optionally redeem up to 10% of the Secured Notes at a price of 103% of par prior to June 1, 2025.
Previous report
December 2024 Financing Activities. In December 2024, we completed several financing transactions that resulted in the: (i) issuance of $380 million in net additional long-term indebtedness through full repayment of the TLC utilizing restricted cash collateralizing the TLC and issuance of the TLB-2 (at an initial rate of SOFR + 2.5%); (ii) issuance of the new $900 million LCF and termination of the TLC LCF and Bilateral LCF, which had the combined effect of increasing our LC capacity by $355 million; and (iii) favorable repricing and covenant improvements on the existing TLB-1 and RCF (repriced to initial rates of SOFR + 2.5% and SOFR + 2.0%, respectively) as well an extension of the RCF maturity. The proceeds of the TLB-2 issuance were used, together with cash on hand, to repurchase shares of our outstanding common stock held by Rubric.
Previous report
See Note 13 to the Annual Financial Statements for additional information on long-term debt, other credit facilities, and recent financing activities.
Previous report
Power Transactions
Previous report
AWS PPA. In connection with the AWS Data Campus Sale in 2024, we and AWS entered into the AWS PPA, pursuant to which we agreed to supply long-term, carbon-free power from Susquehanna to the AWS Data Campus through fixed-price power commitments. Under the AWS PPA, AWS has minimum contractual power commitments that increase in 120 MW increments annually (or earlier, at AWS’s option), with a one-time option to either cap commitments at 480 MW or otherwise purchase, in continuing annual steps, up to 960 MW. Each step up in capacity commitment has a fixed price for an initial 10-year term, after which AWS has the option to renew each step at a price that includes a fixed margin above then-applicable PJM energy and capacity prices. The initial term of the AWS PPA is 18 years, with two 10-year extensions at AWS’s option. Under a separate agreement, we will receive additional revenue from AWS related to the sales of carbon-free energy to the grid. We expect to begin receiving initial revenues from power sales in 2025. See Note 20 to the Annual Financial Statements for additional information on the AWS Data Campus Sale.
Previous report
Susquehanna ISA Amendment. In November 2024, FERC issued an order denying the Susquehanna ISA Amendment between PJM, PPL Corporation, and Susquehanna that would permit Susquehanna to decrease the amount of power supply it would otherwise provide to the power grid. Such order does not have an impact on the existing ISA permitting 300 MW of co-located load at Susquehanna to supply power for the first phases of the AWS Data Campus. In December 2024, FERC issued an order stating that it would address our request for rehearing in a future order, which FERC has not yet issued. Due to FERC’s decision not to address the merits of our motion for rehearing, we have filed an appeal in the U.S. Court of Appeals for the Fifth Circuit. Delivery “behind-the-meter” of more than 300 MW of power under the AWS PPA requires that FERC approve an amended ISA between Susquehanna, PPL, and PJM. Without an amendment we will be unable to deliver the full amount of contract volume under the AWS PPA on a behind-the-meter basis, which may require a contract renegotiation to deliver the additional power “in-front-of-the-meter.” See “Item 3. Legal Proceedings” and “Item 1A. Risk Factors—Regulatory, Environmental, and Legal Risks—Our business is subject to extensive energy-related regulation and oversight.” for additional information on the Susquehanna ISA Amendment.
Previous report
Brandon Shores and H.A Wagner RMR Arrangements. In 2023, we notified PJM of our intent to deactivate electric generation at both our Brandon Shores and H.A. Wagner facilities on June 1, 2025. However, PJM subsequently notified us that both Brandon Shores and H.A Wagner are needed past their previously planned retirement dates to maintain reliability in PJM. In January 2025, we reached a settlement (which remains subject to FERC approval) with key stakeholders on the terms of an RMR arrangement and filed with FERC the resulting Joint Offers of Settlement regarding both facilities’ RMR Continuing Operations Rates Schedules. If approved, the proposed RMR arrangements will extend the operating life of these plants through May 31, 2029, or until such time as the necessary transmission upgrades are placed into service. See Note 10 to the Annual Financial Statements for additional information on the RMR proceedings and settlement and the related impairment of the Brandon Shores asset group.
Previous report
During 2024, natural gas prices for Texas Eastern M-3 settled below their ten-year average as a result of natural gas storage levels above the five-year average and abundant natural gas supplies. In PJM, periodic below average temperatures during the winter and above average temperatures during the summer contributed to increased load demand that resulted in higher annual settled on-peak power prices compared with the prior year.
Previous report
For the 2025/2026 Capacity Year, we 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.
Previous report
Capacity Performance Event. As a result of Winter Storm Elliott in December 2022, PJM experienced extreme cold weather conditions that resulted in PJM’s declaration of a Capacity Performance event requiring generators to operate at their maximum output capacity. Certain of our generation facilities failed to meet PJM’s Capacity Performance requirements while others met or exceeded their obligations. Asa result, we incurred final aggregate net Capacity Performance penalties of $29 million, which were remitted during the period from May 18 through December 31, 2023 (Successor) and the period from January 1 through May 17, 2023 (Predecessor). See Note 12 to the Annual Financial Statements for additional information.
Previous report
Results for the Year Ended December 31, 2024 (Successor), the Period from May 18 through December 31, 2023 (Successor), the Period from January 1 through May 17, 2023 (Predecessor), and the Year Ended December 31, 2022 (Predecessor)
Previous report
Successor Period — Year Ended December 31, 2024
Previous report
Net Income (Loss) Attributable to Stockholders totaled $998 million for the year ended December 31, 2024 (Successor). Results were driven by:
Previous report
•Capacity Revenues totaled $192 million. This primarily included earned capacity awards based on resource clearing prices received from the PJM BRAs for the 2023/2024 and 2024/2025 PJM Capacity Years.
Previous report
•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $1.2 billion. This consisted of: (i) $1.3 billion in third-party wholesale electricity sales and ancillary revenues; (ii) $325 million in other revenue primarily related to Nuclear PTC and Bitcoin revenue; and (iii) $230 million in net realized gains from hedging activities. Such amounts were partially offset by $(659) million in fuel and purchased power costs.
Previous report
•Unrealized Gain (Loss) on Derivative Instruments totaled $62 million gain, net. This consisted of: (i) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period; and (ii) unrealized gains incurred as a result of decreases in forward power prices.
Previous report
•Nuclear Fuel Amortization totaled $(123) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $33 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.
Previous report
•Operation, Maintenance and Development totaled $(592) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Previous report
•Depreciation, Amortization and Accretion totaled $(298) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
Previous report
•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $178 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
Previous report
•Interest Expense and Other Finance Charges totaled $(238) million. This primarily consisted of interest expense incurred on the Secured Notes, TLB-1, and TLB-2.
Previous report
•Other Non-Operating Income (Expense), net totaled $61 million. This primarily consisted of interest income on cash deposits.
Previous report
•Income Tax Benefit (Expense) totaled $(98) million. This primarily related to federal and state tax expense on pre-tax income, the release of the federal and state valuation allowance, and the exclusion of Nuclear PTC income as a permanent item.
Previous report
Successor Period — May 18 through December 31, 2023
Previous report
Net Income (Loss) Attributable to Stockholders totaled $134 million for the period from May 18 through December 31, 2023 (Successor). Results were driven by:
Previous report
•Capacity Revenues totaled $133 million. This primarily consisted of earned capacity awards based on resource clearing prices received from the PJM BRA for the 2023/2024 PJM Capacity Year. Capacity revenues were positively impacted by $19 million as a result of the FERC-approved settlement agreement for net PJM Capacity Performance penalties assessed related to Winter Storm Elliot. See Note 12 to the Annual Financial Statements for additional information on PJM Capacity Performance penalties.
Previous report
•Energy and Other Revenues, net of Fuel and Energy Purchases totaled $732 million. This consisted of: (i) $950 million in third-party wholesale electricity sales and ancillary revenues; (ii) $81 million in Bitcoin revenue; and (iii) $33 million in net realized gains from hedging activities. Such amounts were partially offset by $(332) million in fuel and purchased power costs.
Previous report
•Unrealized Gain (Loss) on Derivative Instruments totaled $52 million gain, net. This consisted of unrealized gains incurred as a result of decreases in forward power prices; and (ii) unrealized gains from the reversal of positions previously recognized as mark-to-market liabilities which settled during the period.
Previous report
•Nuclear Fuel Amortization totaled $(108) million. This consisted of the periodic expense of nuclear fuel costs capitalized as PP&E and $53 million of amortization on certain nuclear fuel contracts that were recognized at fair value at Emergence. See Note 4 to the Annual Financial Statements for additional information.
Previous report
•Operation, Maintenance and Development totaled $(358) million. This consisted of generation facility operating costs, including employee wages and benefits, the costs of removal, repairs, and maintenance that are not capitalized, contractor costs, and certain materials and supplies.
Previous report
•Depreciation, Amortization and Accretion totaled $(165) million. This consisted of depreciation of long-lived PP&E, intangibles, and ARO accretion.
Previous report
•Nuclear Decommissioning Trust Funds Gain (Loss), net totaled $108 million. This consisted of realized and unrealized gains and losses on debt and equity securities, dividends, and interest income associated with NDT investments. See Notes 9 and 14 to the Annual Financial Statements for additional information.
Previous report
•Interest Expense and Other Finance Charges totaled $(176) million. This primarily consisted of interest expense incurred on the Secured Notes and TLB-1.
Previous report
•Other Non-Operating Income (Expense), net totaled $95 million. This primarily consisted of the gain on the PPL/Talen Montana litigation settlement. See Note 12 to the Annual Financial Statements for additional information.
Previous report
•Income Tax Benefit (Expense)totaled $(51) million. This primarily related to federal and state tax expense on pre-tax income and changes in the valuation allowance. See Note 7 to the Annual Financial Statements for additional information.
Previous report
Predecessor Period — January 1 through May 17, 2023
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Reworded paragraphs (33)
Previous wording
The results of operations presented below should be reviewed in conjunction with the Annual Financial Statements and the related notes. Our financial results for the year ended December 31, 2024 (Successor) and for the period from May 18 through December 31, 2023 (Successor) are referred to as the “Successor” periods. Our financial results for the period from January 1 through May 17, 2023 (Predecessor) and the year ended December 31, 2022 (Predecessor) are referred to as the “Predecessor” periods. The operating results for the Successor Periods are not comparable with the operating results for the Predecessor Periods due to the application of fresh start accounting after Emergence in May 2023. See Notes 2, 3, and 4 to the Annual Financial Statements for additional information regarding the Restructuring and related accounting. Our results of operations as reported in the Annual Financial Statements are prepared in accordance with GAAP.
Current wording
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.
Previous wording
The following Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with the Annual Financial Statements and the accompanying notes. 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.
Current wording
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.
Previous wording
Earnings in future periods are subject to various uncertainties and risks. See “Cautionary Note Regarding Forward-Looking Information,” “Item 1A. Risk Factors,” and Notes 5 and 12 to the Annual Financial Statements for additional information on our risks.
Current wording
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.
Previous wording
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, 2024 (Successor), December 31, 2023 (Successor), and December 31, 2022 (Predecessor) were:
Current wording
The weighted average settled on-peak power prices and natural gas prices for the PJM market for the years ended December 31, were:
Previous wording
(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Current wording
(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.
Previous wording
(b)Represents forward prices for 2024 as of December 31, 2023 (Successor). See weighted average settled prices table above for 2024 realized prices.
Current wording
(a)Represents forward prices for 2025 as of December 31, 2024 (Successor). See weighted average settled prices table above for 2025 realized prices.
Previous wording
(a)Spark spreads are computed based on day-ahead West Hub ATC prices, TETCO M-3 natural gas prices, and a heat rate of 7 MMBtu/MWh.
Current wording
(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.
Previous wording
Our generation capacity is 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, RTO/ISO demand forecasts, reserve margin targets, and (in PJM) adjustments to the PJM Market Seller Offer Cap as determined by the PJM Independent Market Monitor.
Current wording
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.
Previous wording
PJM Capacity Auctions. Under the PJM Reliability Pricing Model, when held on schedule, the PJM Base Residual Auction 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 for the specific PJM Capacity Year. However, PJM has delayed its recent BRAs, which has resulted in less than 3 years between each auction and the start of the relevant PJM Capacity Year. The BRA for the 2025/2026 Capacity Year, which was the most recent auction, was held in July 2024. The BRA for the 2026/2027 Capacity Year is currently delayed until July 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 12 to the Annual Financial Statements for additional information on the PJM capacity market, systemic risks, BRA delays, and related legal actions.
Current wording
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.
Previous wording
The Inflation Reduction Act was signed into law in August 2022. Among the Act’s provisions are amendments to the Internal Revenue Code to create a nuclear production tax credit program. The Nuclear PTC program provides qualified nuclear power generation facilities with a transferable tax credit for electricity produced and sold to an unrelated party during each tax year. The credit provides support beginning when annual gross receipts decline below an equivalent $43.75/MWh, increases ratably up to $3/MWh when annual gross receipts are equivalent to $25/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. See Notes 6 and 7 to the Annual Financial Statements for additional information on Nuclear PTC revenue recognized and the Inflation Reduction Act.
Current wording
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 theyear 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.
Previous wording
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. Our largest recurring maintenance project is the annual spring refueling outage at Susquehanna. We serve our fossil generation fleet through a combination of self-service and contracted maintenance activity (including long-term service agreements at certain facilities). 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.”
Current wording
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.”
Previous wording
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 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.
Current wording
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.
Previous wording
In addition, 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” in the Annual Financial Statements. We evaluate them collectively because they represent the changes in fair value of our economic hedging activities.
Current wording
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.
Previous wording
The following table and subsequent sections display the results of operations for the Successor and Predecessor periods:
Current wording
The following table and subsequent sections display the results of operations:
Previous wording
•Gain (Loss) on Sale of Assets, net totaled $884 million. This primarily consisted of the $564 million gain from the ERCOT Sale that closed in May 2024 and the $324 million gain from the AWS Data Campus Sale that closed in March 2024. See Note 20 to the Annual Financial Statements for additional information.
Current wording
•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.
Previous wording
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) legacy environmental obligations; (vi) other working capital requirements; and (or) (vii) discretionary expenditures, including share repurchase activities.
Current wording
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.
Previous wording
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, we now have lower overall hedging needs given the cash-flow stability afforded by the Nuclear PTC (which provides a built-in hedging apparatus through the tax credit) and significantly reduced debt service requirements following the Restructuring and subsequent refinancing transactions.
Current wording
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.
Previous wording
(a)As of December 31, 2024 (Successor), all RCF committed capacity can be used for direct cash borrowings and (or) LCs. As of December 31, 2023 (Successor). All RCF committed capacity could be used for direct cash borrowings and up to $475 million of such capacity could be used for LCs.
Current wording
(a)RCF committed capacity can be used for direct cash borrowings and (or) LCs.
Previous wording
(b)Excludes LC capacity available under the RCF. Includes (i) LC capacity under the LCF as of December 31, 2024 (Successor); and (ii) aggregate LC capacity under the TLC LCF and Bilateral LCF as of December 31, 2023 (Successor).
Current wording
(b)Includes LC capacity under the LCF and excludes LC capacity available under the RCF.
Previous wording
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 13 to the Annual Financial Statements for additional information on the RCF and the issuance of the LCF and termination of the TLC LCF and Bilateral LCF in December 2024.
Current wording
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.
Previous wording
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.
Current wording
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.
Previous wording
Indebtedness. See Note 13 to the Annual Financial Statements and “—Recent Developments—Financing Transactions” above for additional information on our indebtedness.
Current wording
Indebtedness. See Note 10 to the Annual Financial Statements and “—Recent Developments” above for additional information on our indebtedness.
Previous wording
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. Our projected undiscounted spending on AROs and environmental liabilities is presented in the table below. The majority of the estimated non-nuclear spend is related to ash impoundments at Colstrip and Brunner Island. Beginning in 2025, we expect to increase our remediation spend associated with our obligations at Colstrip. The carrying value of these obligations includes certain assumptions, including a rate of inflation of 2.50%. Projections are subject to revision based on changes in estimated inflation rates, changes in the estimated timing of settling AROs, and escalating retirement costs. Susquehanna’s AROs are expected to be settled with funds available from the NDT at the time of decommissioning. See Note 11 to the Annual Financial Statements for additional information.
Current wording
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.
Previous wording
As of December 31, 2024 (Successor), the expected undiscounted payments are estimated to be:
Current wording
As of December 31, 2025 (Successor), the expected undiscounted payments of non-nuclear AROs are estimated to be:
Previous wording
The net cash provided by (used in) operating, investing, and financing activities for the periods were:
Current wording
Net cash provided by (used in) operating, investing, and financing activities for the periods was:
Previous wording
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 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. 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 2 to the Annual Financial Statements for additional information on accounting policies for each of the following topics.
Current wording
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.
Previous wording
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 shut down.
Current wording
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.
Previous wording
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 incorporate the results of the study as well as our experience, knowledge, and professional judgment to the specific characteristics of Susquehanna’s decommissioning plan to update the carrying value of the ARO.
Current wording
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.
Previous wording
AROs are recognized at fair value at the time of installation 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.
Current wording
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.
Previous wording
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 prior to accounting 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.
Current wording
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.
Previous wording
As our derivative contracts generally settle within future time periods supportable by commodity exchange markets and the frequent occurrence of commercial transactions, the majority of our derivative contracts utilize 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.
Current wording
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.
Previous wording
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. Please see Note 15 to the Annual Financial Statements for the weighted-average assumptions used for the discount rate and expected return on plan assets for all plans.
Current wording
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.
Previous wording
See Note 2 to the Annual Financial Statements for a description of recently adopted accounting pronouncements and recently issued accounting pronouncements not yet adopted.
Current wording
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.
Rearranged current paragraphs (2)
Current report — wording carried from elsewhere
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.
Current report — wording carried from elsewhere
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.