What changed in this filing

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Item 7. Management’s Discussion and Analysis

2026-02-24 compared with 2025-02-18 · 368 added, 371 removed, 491 unchanged (60% of the section changed)

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Executive Overview

We are a producer of carbon-free energy and a supplier of energy products and services.

We are the nation's largest producer of clean energy and a leading supplier of energy products and services.

Our generating capacity includes primarily nuclear, wind, solar, natural gas, and hydroelectric assets.

Through our integrated business operations, we sell electricity, natural gas, and other energy-related products and sustainable solutions to various types of customers, including distribution utilities, municipalities, cooperatives, and commercial,

industrial, public sector, and residential customers in markets across multiple geographic regions.

We have five reportable segments:

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Significant Transactions and Developments

Proposed Acquisition of Calpine Corporation

On January 10, 2025, we entered an agreement and plan of merger (Merger Agreement) with Calpine Corporation (Calpine) under which we will acquire all the outstanding equity interests of Calpine in a cash and stock transaction.

Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with over 27 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 2.5 million customers with 60 TWhs of load annually.

Acquisition of Calpine Corporation

On January 7, 2026, we acquired 100% of the outstanding equity of Calpine for a purchase price of approximately $22 billion.

The merger consideration consisted of 50 million newly issued shares of our common stock, no par value, and approximately $4.5 billion in cash on hand.

After considering divestitures connected with certain regulatory approvals, Calpine owns and operates a generation fleet of natural gas, geothermal, battery storage, and solar assets with approximately 23 GWs of generation capacity, in addition to a competitive retail electric supplier platform serving approximately 62 TWhs of load annually.

This acquisition is complementary to, and aligns strategically with, our existing business operations and provides both increased scale and meaningful market diversification.

We will couple the largest producer of clean, carbon-free energy with the reliable, dispatchable natural gas assets of Calpine, and also create the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that will enable us to meet growing demand with a broader array of energy and sustainability products.

The addition of Calpine will strengthen our essential role in providing clean, reliable, and affordable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.

Completion of the transaction is conditioned upon review of the transaction by the DOJ, and approval by the FERC, NYPSC, and PUCT, in addition to other regulatory bodies, and is also subject to other customary closing conditions.

See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

The merger couples the largest producer of clean, emissions-free energy with the reliable, dispatchable natural gas assets of Calpine, and also creates the nation’s leading competitive retail electric supplier, providing increased scale, diversification and complementary capabilities that enable us to meet growing demand with a broader array of energy and sustainability products.

The addition of Calpine strengthens our essential role in providing clean, reliable energy as the nation seeks to transition to a more sustainable future, and will better position us to pursue investments in new and existing technologies to meet growing demand.

See Note 2 — Mergers, Acquisitions, and Dispositions and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Crane Clean Energy Center

During the third quarter of 2024, we executed a 20-year PPA with Microsoft that will support the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center, which was retired in 2019 for economic reasons.

Under the agreement, Microsoft will purchase the output generated from the renewed plant as part of its goal to help power its data centers in PJM with clean energy.

We expect Crane will also be eligible for the technology-neutral clean electricity PTC (45Y) provided for by the IRA for its first 10 years of operations.

We estimate the project will require approximately $1.6 billion of cash from operations for capital expenditures necessary to restart the plant, with an estimated in-service date of 2028.

In 2024, we announced the restart of Three Mile Island Unit 1, renamed as the Crane Clean Energy Center.

The restart is supported by a 20-year PPA with Microsoft to purchase the output generated from the renewed plant.

The restart of the plant and delivery of electricity under the PPA is subject to certain regulatory approvals, including the NRC comprehensive safety and environmental review, as well as permits from relevant state and local agencies.

Additionally, through a separate request, we will pursue obtaining a renewed license that will extend operations at the plant to at least 2054.

Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032.

The nuclear PTC (45U) provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh.

We have evaluated and expect to meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier.

Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year.

The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.

For the year ended December 31, 2024, our Consolidated Statements of Operations and Comprehensive Income include a nuclear PTC benefit of approximately $2,080 million in Operating revenues.

See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

Share Repurchase Program

As part of our capital allocation plan, our Board of Directors has authorized up to $3 billion of share repurchases of our outstanding common stock to-date, of which $991 million has yet to be exercised.

See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

In November 2025, the DOE Office of Energy Dominance Financing issued a guarantee for up to $1.0 billion for an unsecured loan from the Federal Financing Bank to support the restart of the Crane Clean Energy Center.

The loan will mature in October 2055.

Interest rates on the loan will be fixed upon each advance at a spread of 37.5 basis points above U.S.

Treasuries of comparable maturity.

Cash from operations will fund the remaining capital expenditures.

Conowingo Hydroelectric Project License Renewal

In September 2025, we reached a settlement agreement with MDE, Lower Susquehanna Riverkeeper Association, and Waterkeepers Chesapeake, that resolves all outstanding issues related to obtaining a water quality certification from MDE.

As a result, MDE issued a water quality certification, clearing the way for the re-licensing and continued operation of our Conowingo hydroelectric facility.

The terms of the agreement include operational improvements and commitments for water quality and resiliency, trash and debris removal, aquatic life passage, freshwater mussel restoration, dredging and invasive species management.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information.

Clinton Clean Energy Center

In June 2025, we signed a 20-year PPA with Meta Platforms, Inc.

(Meta) for the output of the Clinton Clean Energy Center to support Meta’s clean energy goals and operations in the region with emissions-free nuclear energy.

The agreement, beginning in June 2027, supports the relicensing and continued operations of Clinton for another two decades after the state’s ZEC program expires.

This deal will expand Clinton’s clean energy output by 30 megawatts through plant uprates, expected to be fully complete in 2029, and will enable the Clinton Clean Energy Center to continue to flow power onto the local grid, providing grid reliability and low-cost power to the region for decades to come.

The uprates are expected to qualify for the technology-neutral clean electricity PTC (45Y) provided for by the IRA and preserved by the OBBBA for its first 10 years of operations.

Other Key Business Drivers

PJM Market Reform

On January 16, 2026, the National Energy Dominance Council, with support from Governors within the PJM territory, urged PJM to file proposed tariff revisions at FERC to address reliability and pricing within its capacity auctions.

These changes aim to increase supply which is increasingly important as energy-intensive sectors expand.

The proposed changes include:

1) providing revenue certainty to new generation (for instance, through a Reliability Backstop Auction to procure new, out of market capacity resources), 2) protecting residential customers from capacity price increases, 3) allocating costs to data centers through the Reliability Backstop Auctions, 4) improving load forecasting, specifically large load modeling, 5) accelerating ongoing generator interconnection studies, and 6) performing market studies to ensure the long-term viability of the PJM capacity market.

While this is an emerging issue and tariff revisions have not been developed, this has the potential to impact future revenues received by our fleet.

FERC Issues Order in PJM Show Cause Proceeding

In December 2025, FERC found PJM's tariff unjust and unreasonable because it lacked sufficient clarity and consistency regarding rates, terms, and conditions of service for serving co-located load.

The order also found that the existing behind-the-meter generation rules permitting netting of load and supply were no longer just and reasonable, with certain limited exceptions.

FERC also directed that PJM make three new transmission services available to co-located loads:

an interim, interruptible network integration transmission service, a permanent firm contract demand service, and a non-firm contract demand service.

The rates, terms and conditions for these services will be developed in upcoming compliance filings and a paper hearing at FERC in 2026, as will the scope of technical studies required to pursue service of co-located load ion such services.

One Big Beautiful Bill Act

We continue to see legislative support for nuclear energy generation, including the passage of the OBBBA.

Signed into law in July 2025, the OBBBA both preserves certain federal tax credits from the IRA and enhances certain credits to allow advanced nuclear facilities to qualify for the energy communities bonus adder, subject to eligibility requirements.

It also preserves tax credits which benefit our efforts to commercialize CCUS for natural gas power generation and maintains tax credits for geothermal and certain other investments.

Overall, the OBBBA reinforces the long-term economic viability of our nuclear generation assets.

See Note 3 — Regulatory Matters of the Combined Notes to Consolidated Financial Statements for more information.

Russia and Ukraine Conflict

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that is produced in Russia or by Russian entities, absent a waiver from the DOE.

Under a corollary bill, the Department of Energy has begun the process of distributing billions of dollars that were previously appropriated to support expansion of the domestic nuclear fuel cycle within the United States to improve carbon-free energy security.

In November 2024, the Russian government issued a decree imposing temporary restrictions on the export of enriched uranium from Russia to the U.S.

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The preparation of financial statements in conformity with GAAP requires that management apply accounting policies and make estimates and assumptions that affect results of operations and the amounts of assets and liabilities reported in the consolidated financial statements.

Management believes that the accounting policies described below require significant judgment in their application or incorporate estimates and assumptions that are inherently uncertain and that may change in subsequent periods.

Additional information on the application of these accounting policies can be found in the Combined Notes to Consolidated Financial Statements.

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These factors could result in material changes to our current estimates as more information becomes available and could change the timing of plant retirements and the probability assigned to the decommissioning outcome scenarios.

required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

The nuclear decommissioning obligation is adjusted on a regular basis due to the passage of time and revisions to the key assumptions for the expected timing and/or estimated amounts of the future undiscounted cash flows required to decommission the nuclear plants, based upon the following methodologies and significant estimates and assumptions:

Decommissioning Cost Studies.

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We initially recognize an ARO at fair value and subsequently adjust it for changes to estimated costs, timing of future cash flows and modifications to decommissioning assumptions.

The ARO is not required or permitted to be re-measured for changes in the CARFR that occur in isolation.

Increases in the ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO.

Any decrease in the estimated undiscounted future cash flows relating to the ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR rates used in creating the initial ARO cost layers.

If all our future nominal cash flows associated with the ARO were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.2 billion to approximately $11.2 billion.

The following table illustrates the significant impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of the ARO:

Change in the CARFR applied to the annual ARO update Increase (Decrease) to ARO as of December 31, 2024

An ARO is not required or permitted to be remeasured for changes in the CARFR that occur in isolation.

Increases in an ARO due to upward revisions in estimated undiscounted cash flows are considered new obligations and are measured using a current CARFR as the increase creates a new cost layer within the ARO.

Any decrease in the estimated undiscounted future cash flows relating to an ARO are treated as a modification of an existing ARO cost layer and, therefore, are measured using the average historical CARFR used in creating the initial ARO cost layers.

If all our future nominal cash flows associated with AROs were to be discounted at the current prevailing CARFR, the obligation would decrease from approximately $12.9 billion to approximately $11.3 billion.

The following table illustrates the impact that changes in the CARFR, when combined with changes in projected amounts and expected timing of cash flows, can have on the valuation of our AROs:

Change in the CARFR applied to the annual ARO update Increase (Decrease) to AROs as of December 31, 2025

2024 CARFR rather than the 2025 CARFR

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ARO Sensitivities.

Changes in the assumptions underlying the ARO could materially affect the decommissioning obligation.

The impact of a change in any one of these assumptions to the ARO is highly dependent on how the other assumptions may correspondingly change.

Changes in the assumptions underlying an ARO could materially affect the decommissioning obligation.

The impact of a change in any one of these assumptions to an ARO is highly dependent on how the other assumptions may correspondingly change.

The following table illustrates the effects of changing certain ARO assumptions while holding all other assumptions constant:

Change in ARO Assumption Increase (Decrease) to ARO as of December 31, 2024

Change in ARO Assumption Increase (Decrease) to AROs as of December 31, 2025

Cost escalation studies

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Probabilistic cash flow models

Increase the estimated costs to decommission the nuclear plants by 10 percent 770

Increase the likelihood of the DECON scenario by 10 percent and decrease the likelihood of the SAFSTOR scenario by 10 percent (a)

Shorten each unit's probability-weighted operating life assumption by 10 percent (b)

Increase the estimated costs to decommission the nuclear plants by 10%

Increase the likelihood of the DECON scenario by 10% and decrease the likelihood of the SAFSTOR scenario by 10% (a)

Shorten each unit's probability-weighted operating life assumption by 10% (b)

Extend the estimated date for DOE acceptance of SNF to 2045

(a) Excludes any sites in which management has committed to a specific decommissioning approach.

(b) Excludes Crane and Zion.

(b) Excludes Zion as the ARO is associated with its SNF storage facility.

See Note 1 — Basis of Presentation and Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information regarding accounting for nuclear AROs.

Purchase Accounting

In accordance with authoritative guidance, the assets acquired and liabilities assumed in an acquired business are recorded at their estimated fair values on the date of acquisition.

Acquisition Accounting

In accordance with authoritative guidance, the assets acquired and liabilities assumed in a business combination are recorded at their estimated fair values on the date of acquisition.

Determining the fair value of assets acquired and liabilities assumed requires management’s judgment, often utilizes independent valuation experts and involves the use of significant estimates and assumptions with respect to the timing and amounts of future cash inflows and outflows, discount rates, market prices and asset lives, among other items.

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See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

The difference between the purchase price amount and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value, or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value.

The difference between the purchase price and the net fair value of assets acquired and liabilities assumed is recognized as goodwill on the balance sheet if the purchase price exceeds the estimated net fair value, or as a bargain purchase gain on the income statement if the purchase price is less than the estimated net fair value.

Goodwill is assigned to reporting units that are expected to benefit from the acquisition.

Goodwill is not amortized, instead it is subject to an impairment assessment at least annually to consider whether the reporting unit fair value is more likely than not less than the carrying amount.

See Note 1 — Basis of Presentation, Note 2 — Mergers, Acquisitions, and Dispositions, and Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

We perform an assessment for impairment of goodwill at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount.

Goodwill is not amortized, but rather is subject to an impairment assessment at least annually or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of the reporting units below their carrying amount.

A reporting unit is an operating segment or one level below an operating segment (known as a component) and is the level at which goodwill is tested for impairment.

Our operating segments and reporting units are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on our segments.

Our current operating segments and reporting units are Mid-Atlantic, Midwest, New York, ERCOT, and Other Power Regions.

See Note 5 — Segment Information of the Combined Notes to Consolidated Financial Statements for additional information on our reportable segments.

Goodwill is primarily reported within our ERCOT segment.

See Note 12 — Intangible Assets of the Combined Notes to Consolidated Financial Statements for additional information.

We first perform a qualitative assessment to determine whether a quantitative assessment is necessary.

As part of the qualitative assessment, we evaluate, among other things, management’s best estimate of projected operating and capital cash flows for the reporting units and changes in certain market conditions, including the discount rate.

Significant assumptions used in these fair value analyses include discount and growth rates, energy prices, and projected operating and capital cash flows.

While the 2024 annual assessments indicated no impairments, certain assumptions used in the assessment are highly sensitive to changes.

Adverse regulatory actions or changes in significant assumptions could potentially result in future impairments of our goodwill, which could be material.

For reporting units with goodwill, we perform a qualitative assessment to determine whether it is more likely than not that the fair value of the reporting unit is less than its carrying value.

As part of the qualitative assessment, we evaluate macroeconomic conditions, such as deterioration in general economic conditions, industry and market considerations, cost factors, and overall financial performance.

If we determine, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required.

If the qualitative test determines that it is more likely than not that the fair value of the reporting unit is less than its carrying amount, a quantitative goodwill impairment test is performed by calculating the fair value of the reporting unit and comparing it to its carrying amount.

The fair value of the reporting units is calculated using a weighted combination of the income approach, which estimates fair value based on discounted cash flows, and the market approach, which estimates fair value based on market comparables in our industry.

The income approach uses our internal forecasts to determine estimated cash flows and uses significant assumptions including, but not limited to growth rates, discount rates, customer attrition rates, useful lives, and tax rates.

These assumptions are used to arrive at estimated cash flows which are inherently uncertain.

Similarly, while comparables used in the market approach are determined to be a reasonable proxy for the fair value of the reporting unit, there is judgment involved and the actual fair value may be different than the fair value implied by the market approach.

If the carrying amount of the reporting unit is greater than its fair value, the reporting unit’s goodwill is impaired.

The goodwill impairment loss is the difference between the reporting unit’s fair value and carrying amount, and is recorded as a reduction to goodwill and a charge to operating expense.

The 2025 annual assessments indicated no impairments.

Adverse regulatory actions or changes in significant assumptions could result in future impairments of our goodwill.

The acquisition of Calpine is expected to add a significant amount of goodwill to our balance sheet which will be assessed for impairment in accordance with our policy described above.

Unamortized Energy Contract Assets and Liabilities

Unamortized energy contract assets and liabilities represent the remaining unamortized balances of non-derivative energy contracts and fuel contracts that we have acquired.

The initial amount recorded represents the difference between the fair value of the contracts at the time of acquisition and the contract value based on the terms of each contract.

The unamortized energy contract assets and liabilities are amortized over the life of the contract in relation to the expected realization of the underlying cash flows.

UEC assets and liabilities represent the remaining unamortized balances of non-derivative energy and fuel contracts that we have acquired.

The initial amount recorded represents the fair value of the contracts at the time of acquisition.

The UEC assets and liabilities are amortized over the life of the contract in accordance with the expected realization of the underlying cash flows.

Amortization of the unamortized energy and fuel contract assets and liabilities are recorded through Operating revenues or Purchased power and fuel expense, depending on the nature of the underlying contract.

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The cash flows from our generating units are generally evaluated at a regional portfolio level (asset group), given the interdependency of cash flows generated from the customer supply and risk management activities within each region.

In certain cases, our generating assets may be evaluated on an individual basis where those assets are contracted on a long-term basis with a third party and operations are independent of other generating assets (typically contracted renewable generation).

On a quarterly basis, we assess our long-lived assets or asset groups for indicators of potential impairment.

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When the undiscounted cash flow analysis indicates the carrying value of a long-lived asset or asset group may not be recoverable, the amount of the impairment loss is determined by measuring the excess of the carrying amount of the long-lived asset or asset group over its fair value.

The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the asset or asset groups.

This includes significant assumptions of the estimated future cash flows generated by the asset or asset groups and market discount rates.

The fair value of the long-lived asset or asset group is dependent upon a market participant’s view of the exit price of the long-lived asset or asset group.

This includes significant assumptions of the estimated future cash flows generated by the long-lived assets or asset groups and market discount rates.

Events and circumstances often do not occur as expected, resulting in differences between prospective financial information and actual results, which may be material.

The determination of fair value is driven by both internal assumptions that include significant unobservable inputs, such as revenue and generation forecasts, projected capital, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.

The determination of fair value is driven by both internal assumptions that include significant unobservable inputs, such as revenue and generation forecasts, projected capital investments, maintenance expenditures, and discount rates, as well as information from various public, financial and industry sources.

Depreciable Lives of Property, Plant, and Equipment

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Under both methods, a reporting entity depreciates the assets over the average life of the assets in the group.

The estimation of asset useful lives requires management judgment, supported by formal depreciation studies of historical asset retirement experience.

Depreciation studies are generally conducted periodically if an event, regulatory action, or change in retirement patterns indicate an update is necessary.

Along with depreciation study results, management considers expected future energy market conditions and generation plant operating costs and capital investment requirements in determining the estimated useful lives of our generating facilities and reassesses the reasonableness of estimated useful lives whenever events or changes in circumstances warrant.

When a determination has been made that an asset will be retired before the end of its current estimated useful life, depreciation provisions will be accelerated to reflect the shortened estimated useful life, which could have a material unfavorable impact on future results of operations.

Changes in estimated useful lives of electric generating assets could have a significant impact on future results of operations.

The estimation of asset useful lives requires management judgment, informed by formal depreciation studies of historical asset retirement experiences conducted at least every five years and other factors, including expected energy market conditions, operating costs, and capital investment requirements.

Management reassesses these estimates when events or changes in circumstances indicate that revisions may be necessary.

When a determination has been made that an asset's current estimated useful life will be shortened or extended, depreciation provisions will be adjusted which could have a material impact on future results of operations.

See Note 1 — Basis of Presentation and Note 8 — Property, Plant, and Equipment of the Combined Notes to Consolidated Financial Statements for information regarding depreciation and estimated useful lives of the property, plant and equipment.

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Determining whether a contract qualifies as a derivative requires that management exercise significant judgment, including assessing market liquidity as well as determining whether a contract has one or more underlying and one or more notional quantities.

Changes in management’s assessment of contracts and the liquidity of their markets, and changes in authoritative guidance, could result in previously excluded contracts becoming in scope of new authoritative guidance.

Changes in management’s assessment of contracts and the liquidity of their markets, and changes in

authoritative guidance, could result in previously excluded contracts becoming in scope of existing authoritative guidance.

All derivatives are recognized on the balance sheet at their fair value, except for certain derivatives that qualify for, and are elected under, NPNS.

Derivatives entered for economic hedging and for proprietary trading purposes are recorded at fair value through earnings.

Derivatives executed for economic hedging purposes are recorded at fair value through earnings.

NPNS transactions are not required to be recorded at fair value, but rather on an accrual basis of accounting.

Determining whether a contract qualifies for NPNS requires judgment on whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.

Determining whether a contract qualifies for NPNS requires judgment as to whether the contract will physically deliver and requires that management ensure compliance with all associated qualification and documentation requirements.

Commodity Contracts.

Identification of a commodity contract as an economic hedge requires us to determine that the contract is in accordance with the RMP.

We reassess our economic hedges on a regular basis to determine if they continue to be within the guidelines of the RMP.

As a part of the authoritative guidance, we make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and the expected changes in the fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions.

We make estimates and assumptions concerning future commodity prices, load requirements, interest rates, the timing of future transactions and their probable cash flows, the fair value of contracts and expected changes in fair value in deciding whether to enter derivative transactions, and in determining the initial accounting treatment for derivative transactions.

Under the authoritative guidance for fair value measurements, we categorize these derivatives under a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value.

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Defined Benefit Pension and Other Postretirement Employee Benefits

The majority of our employees participate in defined benefit pension and OPEB plans we sponsor.

Approximately half of our employees participate in the defined benefit pension and OPEB plans that we sponsor.

Measuring plan obligations and costs involves various factors, including valuation assumptions and inputs and accounting policy elections.

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To determine the EROA, we consider forecasted future long-term capital market performance, weighted by our target asset class allocations.

We calculate the expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year, considering anticipated contributions and benefit payments to be made during the year.

We calculate the expected return on pension and OPEB plan assets by multiplying the EROA by the MRV of plan assets at the beginning of the year,

considering anticipated contributions and benefit payments to be made during the year.

The MRV for pension and OPEB plan assets is based on either fair value or a calculated value that systematically and rationally recognizes changes in fair value over multiple years.

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Discount Rate.

Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality non-callable (or callable with make-whole provisions) bonds with similar maturities to the pension and OPEB obligations.

Discount rates are determined by developing a spot rate curve based on the yield to maturity of high-quality corporate bonds with similar maturities to the pension and OPEB obligations.

These spot rates discount the estimated future benefit distribution amounts for the pension and OPEB plans.

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The following table illustrates the effects of changing certain of the actuarial assumptions reflected above and as discussed in Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements, while holding all other assumptions constant:

Actual Assumption

Pension OPEB Assumption Increase / (Decrease)

Pension OPEB Change in Assumption

Increase / (Decrease)

Actuarial Assumption Pension OPEB Total

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Significant judgment is required to determine whether the recognition threshold has been met and, if so, the appropriate amount of tax benefits to be recorded in the consolidated financial statements.

We evaluate quarterly the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets.

We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate our inability to realize our deferred tax assets.

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In the preparation of our financial statements, we make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information.

The amount recorded may differ from the actual expense incurred when the uncertainty is resolved and may have a material impact to our consolidated financial statements.

The amount recorded may differ from the actual expense incurred when the uncertainty is resolved and may have a material impact to our results of operations or financial condition.

Environmental Costs.

Environmental investigation and remediation liabilities are based upon estimates with respect to the number of sites for which we will be responsible, the scope and cost of work to be performed at each site, the portion of costs that will be shared with other parties, the timing of the remediation work, regulations, and the requirements of local governmental authorities.

These matters, if resolved in a manner different from the estimate, could have a material impact to our consolidated financial statements.

These matters, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information.

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Future events, such as the number of new claims to be filed each year, the average cost of disposing of claims, as well as the numerous uncertainties surrounding litigation and possible state and national legislative measures could cause the actual costs to be higher or lower than estimated.

Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to the consolidated financial statements.

Accordingly, these claims, if resolved in a manner different from the estimate, could have a material impact to our results of operations or financial condition.

Revenue Recognition

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Revenue from Contracts with Customers.

We recognize revenues in the period in which the performance obligations within contracts with customers are satisfied, which generally occurs when power, natural gas and other energy-related products and services are provided to the customer.

Transactions within the scope of Revenue from Contracts with Customers generally include non-derivative agreements, contracts that are designated as NPNS and spot-market energy commodity sales, including settlements with RTOs and ISOs.

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Repeal or significant reduction or modification of the PTC could have a material impact on our financial performance depending on gross receipts received by our nuclear units each year.

Further, the nuclear PTC continues to be the subject of additional

guidance expected to be issued from the U.S.

Treasury and IRS that may materially impact the total amount of benefits we receive.

Absence of prescriptive guidance requires the application of judgement in determining annual gross receipts, a primary component in the determination of the credit.

Further, the nuclear PTC continues to be the subject of additional guidance, from the U.S.

Treasury and IRS, and may materially impact the total amount of benefits we receive.

Absence of prescriptive guidance requires the application of judgment in determining annual gross receipts, a primary component in the determination of the credit.

We closely monitor developments in relevant tax laws and regulations to anticipate and mitigate potential risks.

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BUSINESS – Price and Supply Risk Management for additional information on how we mitigate market price risk.

See Note 6 — Government Assistance of the Combined Notes to the Consolidated Financial Statements for additional information regarding nuclear PTC.

See Note 6 — Government Assistance of the Combined Notes to the Consolidated Financial Statements for additional information.

Derivative Revenues.

We record revenues and expenses using the fair value method of accounting, also referred to as mark-to-market method of accounting for transactions that are accounted for as derivatives.

We record revenues and expenses using the fair value method of accounting for transactions that are accounted for as derivatives.

These derivative transactions primarily relate to commodity price risk management activities.

Mark-to-market revenues and expenses include inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

Derivative revenues and expenses include inception gains or losses on new transactions where the fair value is observable, unrealized gains and losses from changes in the fair value of open contracts, and realized gains and losses.

Financial Results of Operations

GAAP Results of Operations.

The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the year ended December 31, 2024 compared to the same period in 2023.

The following table sets forth our consolidated GAAP Net Income (Loss) Attributable to Common Shareholders for the year ended December 31, 2025 compared to 2024.

For additional information regarding the financial results for the years ended December 31, 2025 and 2024, see the discussions of Results of Operations below.

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Adjusted (non-GAAP) Operating Earnings is not a standardized financial measure and may not be comparable to other companies’ presentations of similarly titled measures.

Unless otherwise noted, the income tax impact of each reconciling adjustment between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings is based on the marginal statutory federal and state income tax rates, taking into account whether the income or expense item is taxable or deductible, respectively, in whole or in part.

For all adjustments except the NDT fund investment returns, which are included in decommissioning-related activities, the marginal statutory income tax rate was 25.5% and 25.1% for the years ended December 31, 2024 and 2023, respectively.

Under IRS regulations, NDT fund investment returns are taxed at different rates for investments if they are in qualified or non-qualified funds.

The effective tax rates for the unrealized and realized gains and losses related to NDT funds were 54.8% and 52.4% for the years ended December 31, 2024 and 2023, respectively .

The following table provides a reconciliation between GAAP Net Income (Loss) Attributable to Common Shareholders and Adjusted (non-GAAP) Operating Earnings for the year ended December 31, 2024 compared to the same period in 2023.

The marginal statutory income tax rate was 25.6% and 25.5% for the years ended December 31, 2025 and 2024, respectively.

For the Years Ended December 31,

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38 0.12 5 0.02

Separation Costs (net of taxes $3 and $21, respectively) (d)

9 0.03 62 0.19

ERP System Implementation Costs (net of taxes $3 and $6, respectively)

Acquisition-Related Costs (net of taxes $4 and $2, respectively) (d)

97 0.31 6 0.02

1 unchanged sentence

5 0.02 65 0.21

Separation Costs (net of taxes $— and $3, respectively)

ERP System Implementation Costs (net of taxes $— and $3, respectively)

Income Tax-Related Adjustments (e)

22 0.07 (52) (0.17)

Acquisition-Related Costs (net of taxes $2 and $3, respectively)

6 0.02 9 0.03

Asset Impairments (net of taxes $— and $9, respectively)

Noncontrolling Interests (f)

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Earnings per share amount is based on average diluted common shares outstanding of 314 million and 315 million for the years ended December 31, 2025 and 2024, respectively.

(b) Includes mark-to-market on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

(b) Includes unrealized gains and losses on economic hedges, interest rate swaps, and fair value adjustments related to gas imbalances and equity investments.

(c) Reflects all gains and losses associated with NDTs, ARO accretion, ARC depreciation, ARO remeasurement, and impacts of contractual offset for Regulatory Agreement Units.

(d) Represents certain incremental costs related to the separation (system-related costs, third-party costs paid to advisors, consultants, lawyers, and other experts assisting in the separation), including a portion of the amounts billed to us pursuant to the TSA.

See Note 1 — Basis of Presentation of the Combined Notes to Consolidated Financial Statements for additional information.

(e) In 2024, primarily reflects the adjustment to deferred income taxes due to changes in forecasted apportionment.

The tax effects of Regulatory Agreement Units result in a 100% effective tax rate under contractual offset accounting.

Additionally, the tax effects of NDT investment returns result in different effective tax rates depending on whether the underlying funds are held within qualified or non-qualified trusts.

(d) Reflects acquisition-related costs associated with the Calpine merger.

The majority of these expenses are not tax deductible.

(e) Adjustment to deferred income taxes due to changes in forecasted apportionment.

(f) Represents elimination of the noncontrolling interest portion of certain adjustments included above.

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Income tax (benefit) expense

1,187 774 413

Equity in income (losses) of unconsolidated affiliates (1) (4) 3

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Year Ended December 31, 2025 Compared to Year Ended December 31, 2024.

The variance in Net income (loss) attributable to common shareholders was favorable by $2,126 million primarily due to:

• Favorable net mark-to-market activity and other fair value adjustments;

• Favorable nuclear PTC activity related to the IRA beginning in 2024;

• Favorable market and portfolio conditions primarily driven by higher realized margins on load contracts and generation-to-load optimization.

The favorable items were partially offset by:

• Higher labor (inclusive of incentives), contracting, and materials;

• Lower unrealized gains resulting from an investment that became a publicly traded company in the second quarter of 2023;

• Unfavorable net realized and unrealized NDT activity;

• Lower revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years.

The variance in Net income (loss) attributable to common shareholders was unfavorable by $1,430 million primarily due to:

• Lower Nuclear PTC revenues in 2025.

See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information;

• Unfavorable net unrealized losses on economic hedges;

• Higher net unrealized losses on equity investments.

The unfavorable items were partially offset by:

• Favorable market and portfolio conditions primarily driven by higher capacity revenues and generation-to-load optimization;

• Favorable net ZEC revenues, including the impacts of higher revenue recognized for ZECs delivered under the Illinois ZEC program in prior planning years;

• Favorable net realized and unrealized NDT fund investment activity.

Operating revenues.

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For the year ended December 31, 2025 compared to 2024, Operating revenues were as follows:

2024 2023 $ Change % Change (a)

2025 2024 $ Change % Change

Mid-Atlantic $ 6,487 $ 5,522 $ 965 17.5 %

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Other 4,370 3,819 551 14.4 %

Mark-to-market gains

Unrealized gains (losses) (a)

(805) 316 (1,121)

Total Operating revenues $ 25,533 $ 23,568 $ 1,965 8.3 %

(a) % Change in mark-to-market is not a meaningful measure.

(a) % Change in unrealized gains (losses) is not a meaningful measure.

Sales and Supply Sources.

Our sales and supply sources by region are summarized below:

Our sales and supply volumes (GWhs) by region are summarized below:

2025 2024 Change

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48,288 49,769 (1,481) (3.0) %

Total Supply/Sales by Region 269,417 269,689 (272) (0.1) %

Total Supply/Sales

268,943 269,417 (474) (0.2) %

(a) Includes the proportionate share of output where we have an undivided ownership interest in jointly-owned generating plants.

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Non-refueling outage days 57 36

Beginning in 2024, our existing nuclear units are eligible for a PTC extending through 2032.

The nuclear PTC provides a transferable credit up to $15 per MWh (a base credit of $3 per MWh with a five times multiplier provided certain prevailing wage requirements are met) and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh.

We have evaluated and expect to meet the annual prevailing wage requirements at all our nuclear units and are eligible for the five times multiplier.

Both the amount of the PTC and the gross receipts thresholds adjust for inflation after 2024 through the duration of the program based on the GDP price deflator for the preceding calendar year.

The benefits of the PTC may be realized through a credit against our federal income taxes or transferred via sale to an unrelated party.

Many of the state-sponsored programs (i.e., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.

See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

We are compensated through state programs for the carbon-free attributes of our nuclear generation.

The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted.

Gross prices reflect the weighted average price for the various delivery periods within the years ended December 31, 2024 and 2023 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.

State (Region) (a)

2024 2023 $ Change % Change

New Jersey (Mid-Atlantic) (b)

$ 9.98 $ 9.92 $ 0.06 0.6 %

Illinois (Midwest) (c)

Electricity Prices.

As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost.

We report the sale and purchase of electricity in the spot market on a net hourly basis in either Operating revenues or Purchased power and fuel expense within each region, depending on our net hourly position.

The price of electricity is impacted by several variables, including but not limited to, the price of fuels, generation resources in the region, weather, ongoing competition, emerging technologies, as well as macroeconomic and regulatory factors.

The following table presents an average day-ahead around-the-clock reference price ($/MWh) for the periods presented for each of our major regions and does not necessarily reflect prices we ultimately realized.

Location (Region) 2025 2024 $ Change % Change

PJM West (Mid-Atlantic) $ 50.19 $ 33.74 $ 16.45 48.8 %

ComEd (Midwest) 36.62 25.50 11.12 43.6 %

Central (New York) 56.31 34.12 22.19 65.0 %

North (ERCOT) 32.94 26.97 5.97 22.1 %

Southeast Massachusetts (Other) (a)

68.56 41.70 26.86 64.4 %

New York (New York) 18.27 19.05 (0.78) (4.1) %

(a) See ITEM 1.

BUSINESS, Environmental Matters for additional information on the plants receiving payments through state programs.

(b) The ZEC price is expected to be $10.00/MWh for each delivery period and is subject to an annual update once full year generation is known.

Following the latest annual update in August 2024, the ZEC price for the delivery period beginning June 2023 through May 2024 was calculated to be $9.95.

(c) See Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZEC program.

Illinois CMC Price.

The price received (paid) for each CMC is determined by the IPA monthly and is based on the accepted CMC bid, less the sum of (a) monthly weighted average PJM Busbar price, (b) ComEd zone capacity price and (c) any federal tax credit or subsidy received by each qualifying plant and is subject to a customer protection cap ($30.30 per MWh for initial delivery period June 2022 through May 2023, $32.50 per MWh for the period June 2023 through May 2024 and $33.43 per MWh for the period June 2024 through May 2025).

If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us.

If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd.

CMC prices per MWh were $8.05 and $4.13 for the years ended December 31, 2024 and 2023, respectively.

The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed above.

(a) Reflects New England, which comprises the majority of the activity in the Other region.

Capacity Prices.

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Southeast New England (Other) 446.97 581.69 (134.72) (23.2) %

Electricity Prices.

As a producer and supplier of electricity, the price of electricity has a significant impact on our operating revenues and purchased power cost.

Location (Region) 2024 2023 $ Change % Change

PJM West (Mid-Atlantic) $ 33.74 $ 33.06 $ 0.68 2.1 %

ComEd (Midwest) 25.50 26.64 (1.14) (4.3) %

Central (New York) 34.12 26.97 7.15 26.5 %

North (ERCOT) 26.97 55.15 (28.18) (51.1) %

Southeast Massachusetts (Other) (a)

We are compensated through state programs for the emissions-free attributes of our nuclear generation.

The following table includes the average ZEC reference prices ($/MWh) for each of our major regions in which state programs have been enacted.

Gross prices reflect the weighted average price for the various delivery periods within the years ended December 31, 2025 and 2024 and may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

State (Region) (a)

2025 2024 $ Change % Change

New Jersey (Mid-Atlantic) (b)

$ 10.00 $ 9.98 $ 0.02 0.2 %

(a) Reflects New England, which comprises the majority of the activity in the Other region.

For the year ended December 31, 2024 compared to 2023, changes in Operating revenues by region were approximately as follows:

$ Change % Change (a)

Mid-Atlantic $ 384 7.5 % • favorable estimated nuclear PTC revenue of $515

• favorable retail load revenue of $135 primarily due to

higher contracted energy prices;

partially offset by

• unfavorable wholesale load revenue of ($100) primarily due to lower volumes

• unfavorable net ZEC program revenue of ($80) due to estimated refund associated with Nuclear PTC

• unfavorable settled economic hedges of ($60) due to

settled prices relative to hedged prices

$ Change % Change (a)

Midwest 147 3.2 % • favorable estimated nuclear PTC revenue of $1,300;

partially offset by

• unfavorable net ZEC and CMC program revenue of ($750) due to decrease in ZEC revenue realized and estimated pass through associated with nuclear PTC

• unfavorable settled economic hedges of ($205) due to

settled prices relative to hedged prices

• unfavorable net generation and wholesale load revenue of ($85) primarily due to lower load volumes

• unfavorable PJM performance bonuses of ($70) due to absence of favorable adjustment in 2023 associated with the December 2022 weather event

New York 29 1.4 % • favorable retail load revenue of $155 primarily due to higher load volumes and contracted energy prices

• favorable estimated nuclear PTC revenue of $150;

Illinois (Midwest) (c)

4.59 5.60 (1.01) (18.0) %

New York (New York) 15.64 18.27 (2.63) (14.4) %

(a) See ITEM 1.

BUSINESS, Environmental Matters and Regulation for additional information on the plants receiving payments through state programs.

(b) The New Jersey ZEC program concluded in May 2025.

(c) See Note 4 — Revenue from Contracts with Customers of the Combined Notes to Consolidated Financial Statements for additional information on the Illinois ZEC program.

Illinois CMC Price.

The price received (paid) for each CMC is determined by the IPA monthly by subtracting energy and capacity index prices from the bid price, which resulted in $32.50 per MWh for the period June 2023 through May 2024, $33.43 per MWh for the period June 2024 through May 2025 and $33.50 per MWh for the period June 2025 through May 2026.

If the monthly CMC price per MWh calculation results in a net positive value, ComEd will multiply that value by the delivered quantity and pay the total to us.

If the CMC price per MWh calculation results in a net negative value, we will multiply this value by the delivered quantity and pay the net value to ComEd.

The average CMC prices per MWh were ($7.58) and $8.05 for the years ended December 31, 2025 and 2024, respectively.

The average CMC prices may not necessarily reflect prices we ultimately realize as a result of interaction with the nuclear PTC discussed below.

Beginning in 2024, our nuclear units are eligible for a PTC extending through 2032.

The nuclear PTC provides a transferable credit up to $15 per MWh and is subject to phase-out when annual gross receipts are between $25.00 per MWh and $43.75 per MWh and $26.00 per MWh and $44.75 per MWh for 2024 and 2025, respectively.

Both the amount of the PTC and the gross receipts thresholds adjust for inflation annually through the duration of the program based on the GDP price deflator for the preceding calendar year.

Many of the state-sponsored programs (e.g., ZECs and CMCs) providing compensation for the emissions-free attributes of generation from certain of our nuclear units include contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.

See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information on the nuclear PTC.

The following table summarizes the impacts to Operating revenues related to the benefits of nuclear PTC and state-sponsored programs subject to refund or pass through as described above for the year ended December 31, 2025 compared to 2024:

2025 2024 $ Change % Change

Nuclear PTC revenue (a)

$ 320 $ 2,080 $ (1,760) (84.6) %

State-sponsored programs net revenue (b)

(125) (50) (75) 150.0 %

(a) Our estimate required the exercise of judgment in determining the amount of nuclear PTC expected for each of our nuclear units.

Refer to Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Includes only state-sponsored programs that have contractual or other provisions that require us to refund that compensation up to the amount of the nuclear PTC received or pass through the entirety of the nuclear PTC received.

For the year ended December 31, 2025 compared to 2024, changes in Operating revenues by segment were approximately as follows:

$ Change % Change

Mid-Atlantic $ 965 17.5 % • favorable retail load revenue of $700 primarily due to higher contracted energy prices and load volumes

• favorable realized economic hedges of $450 due to settled prices relative to hedged prices

• favorable wholesale load revenue of $325 primarily due to higher contracted energy prices;

partially offset by

• unfavorable net ZEC program revenue of ($180) due to estimated refund associated with nuclear PTC and decrease in ZEC price in current planning year

• unfavorable settled economic hedges of ($120) due to

settled prices relative to hedged prices

ERCOT 204 15.2 % • favorable settled economic hedges of $150 due to settled prices relative to hedged prices

• favorable estimated nuclear PTC revenue of $110;

• unfavorable activity due to absence of nuclear PTC revenue of $515 due to higher energy and capacity prices in the current year

Midwest 999 20.8 % • favorable net generation and wholesale load revenue of $730 primarily due to higher energy prices, partially offset by lower generation volumes

• favorable realized economic hedges of $720 due to settled prices relative to hedged prices

• favorable retail load revenue of $520 primarily due to higher contracted energy prices and load volumes

• favorable net capacity revenue of $195 primarily due to higher prices

• favorable net ZEC revenue of $130 primarily due to revenue recognized for Illinois ZECs delivered in prior planning years;

partially offset by

• unfavorable retail load revenue of ($100) primarily due to lower contracted energy prices

Other Power Regions (345) (5.9) % • unfavorable wholesale load revenue of ($515) primarily due to lower contracted prices and load volumes;

• unfavorable activity due to lower nuclear PTC revenue of $1,090 and lower net CMC program revenue of $210 due to higher energy and capacity prices in the current year

New York 140 6.8 % • favorable net generation revenue of $255 associated with the sale of generation volumes relative to purchase power to supply load primarily due to higher energy prices and generation volumes

• favorable retail load revenue of $110 primarily due to higher contracted energy prices

• favorable ZEC program revenue of $105 primarily due to the absence of the refund associated with nuclear PTC revenue;

partially offset by

• favorable retail load revenue of $200 primarily due to

higher contracted energy prices

Other (686) (15.2) % • unfavorable gas revenue, inclusive of settled economic hedges, of ($555) primarily due to lower gas prices

• no other individually significant items to note

Mark-to-market (b)

(1,083) • gains on economic hedging activities of $316 in 2024 compared to gains of $1,399 in 2023

• unfavorable activity due to absence of nuclear PTC revenue of $150 due to higher energy prices in the current year

• unfavorable realized economic hedges of $185 due to settled prices relative to hedged prices

ERCOT 354 22.8 % • favorable realized economic hedges of $150 due to settled prices relative to hedged prices

• favorable wholesale load revenue of $120 primarily due to higher contracted energy prices, partially offset by lower load volumes

• favorable retail load revenue of $75 primarily due to higher contracted energy prices and load volumes

$ Change % Change

Other Power Regions 77 1.4 % • favorable retail load revenue of $50 primarily due to higher contracted energy prices

Other 551 14.4 % • favorable retail gas revenue of $410 primarily due to higher gas prices

• favorable revenues in the United Kingdom, inclusive of realized economic hedges, of $160 primarily due to higher energy prices

Unrealized gains or losses (a)(b)

(1,121) • losses on economic hedging activities of $805 in 2025 compared to gains of $316 in 2024

Total $ 1,965 8.3 %

(a) % Change in mark-to-market is not a meaningful measure.

(b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

(a) % Change in unrealized gains or losses is not a meaningful measure.

(b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

Purchased power and fuel.

See Operating revenues above for discussion of our reportable segments and hedging strategies and for supplemental statistical data, including sales and supply sources by region, nuclear fleet capacity factor, capacity prices, and electricity prices.

Wholesale and retail natural gas activity, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a region.

Wholesale and retail natural gas activity, energy-related activity in the United Kingdom, as well as other miscellaneous business activities that are not significant to overall results of operations are reported under Other and are not allocated to a region.

For the year ended December 31, 2025 compared to 2024, Purchased power and fuel expense were as follows:

2024 2023 $ Change % Change (a)

2025 2024 $ Change % Change

Mid-Atlantic $ 3,076 $ 2,442 $ 634 26.0 %

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Other 3,569 2,997 572 19.1 %

Mark-to-market losses (gains) (961) 2,371 (3,332)

Unrealized losses (gains) (a)

(187) (961) 774

Total purchased power and fuel $ 14,681 $ 11,419 $ 3,262 28.6 %

(a) % Change in mark-to-market is not a meaningful measure.

For the year ended December 31, 2024 compared to 2023, changes in Purchased power and fuel expense by region were approximately as follows:

$ Change % Change (a)

Mid-Atlantic $ 228 10.3 % • unfavorable cost of ($100) associated with purchased power to supply load relative to generation volumes primarily driven by higher prices during peak load periods and higher net transmission costs

• unfavorable settlement of economic hedges of ($75) due to settled prices relative to hedged prices

Midwest 200 14.3 % • unfavorable cost of ($170) associated with purchased power to supply load relative to generation volumes primarily driven by higher net transmission costs

• unfavorable nuclear fuel cost of ($55) primarily due to higher amortization rates related to the reversal of the previous decision in 2020 to retire certain sites

New York (173) (22.5) % • favorable settlement of economic hedges of $230 due to settled prices relative to hedged prices

ERCOT (261) (34.2) % • favorable cost of $245 associated with purchased power to supply load relative to generation volumes primarily due to higher generation volumes

• favorable settlement of economic hedges of $70 due to settled prices relative to hedged prices

Other Power Regions (373) (8.1) % • favorable purchased power and fuel of $390 primarily due to lower energy prices and load served, partially offset by the expiration of the Mystic COS

$ Change % Change (a)

Other (871) (22.5) % • favorable net gas purchases, inclusive of settled economic hedges, of $730 primarily due to lower gas

• favorable purchases in the United Kingdom, inclusive of settled economic hedges, of $95 primarily due to lower energy prices

Mark-to-market (b)

(3,332) • gains on economic hedging activities of $961 in 2024 compared to losses of ($2,371) in 2023

(a) % Change in unrealized losses (gains) is not a meaningful measure.

For the year ended December 31, 2025 compared to 2024, changes in Purchased power and fuel expense by segment were approximately as follows:

$ Change % Change

Mid-Atlantic $ 634 26.0 % • unfavorable cost of $660 associated with purchased power to supply load, net of generation, primarily due to higher energy prices, as well as higher prices associated with net capacity costs;

partially offset by

• favorable realized economic hedges of $105 due to settled prices relative to hedged prices

Midwest 499 31.1 % • unfavorable cost of $460 associated with purchased power to supply load, net of generation, primarily due to higher transmission costs and energy prices

$ Change % Change

New York (7) (1.2) % • no individually significant drivers

ERCOT 264 52.5 % • unfavorable cost of $210 associated with purchased power to supply load, net of generation, primarily due to higher energy prices

• unfavorable realized economic hedges of $60, due to settled prices relative to hedged prices

Other Power Regions 526 12.4 % • unfavorable purchased power of $1,330 primarily due to lower generation volumes driven by the retirement of Mystic Units 8 and 9, higher energy prices, and higher ancillary charges;

partially offset by

• favorable realized economic hedges of $835 due to settled prices relative to hedged prices

Other 572 19.1 % • unfavorable net wholesale gas purchases, inclusive of realized economic hedges, of $315 primarily due to higher gas prices

• unfavorable purchases in the United Kingdom, inclusive of realized economic hedges, of $190 primarily due to higher energy prices

• unfavorable fair value adjustments related to gas imbalances of $65

Unrealized gains or losses (a)(b)

774 • gains on economic hedging activities of $187 in 2025 compared to gains of $961 in 2024

Total $ 3,262 28.6 %

(a) % Change in mark-to-market is not a meaningful measure.

(b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on mark-to-market gains and losses.

The changes in Operating and maintenance expense consisted of the following:

Increase (Decrease)

Labor, other benefits, contracting, and materials (a)

Plant retirements and divestitures

Change in environmental liabilities 43

Decommissioning-related activities

Nuclear refueling outage costs (b)

Asset impairments (71)

Separation costs

Total increase $ 474

(a) Primarily reflects increased employee incentive program costs, driven by stock compensation expense and Company performance exceeding relative metrics, increased headcount, and the acquisition of STP in November 2023.

(b) Includes the co-owned Salem and STP generating units.

Other, net was unfavorable for the year ended December 31, 2024 compared to the same period in 2023, due to activity described in the table below:

(a) % Change in unrealized gains or losses is not a meaningful measure.

(b) See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on unrealized gains and losses.

Other, net was favorable for the year ended December 31, 2025 compared to 2024, due to activity described in the table below:

Income (Deductions)

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Decommissioning-related activities (a)

Non-service net periodic benefit credit (cost)

Net realized and unrealized gains (losses) from equity investments

$ 1,112 $ 567

Net unrealized gains (losses) from equity investments (b)

Other, net $ 936 $ 670

1 unchanged sentence

See Note 10 — Asset Retirement Obligations and Note 22 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information.

(b) Includes unrealized gains (losses) resulting from an equity investment in a publicly traded company.

We record the fair value of this investment in Other deferred debits and other assets in the Consolidated Balance Sheets based on quoted market price of the stock.

Effective income tax rates were 33.8% and 17.1% for the years ended December 31, 2025 and 2024, respectively.

The change in effective tax rate in 2024 compared 2023 is primarily attributable to the inclusion of nuclear PTCs which are non-taxable.

The change in effective tax rate in 2025 compared to 2024 is primarily due to the decrease in nuclear PTCs generated, which are not taxable, as well as higher qualified NDT fund income that is taxed at a higher rate.

See Note 13 — Income Taxes of the Combined Notes to Consolidated Financial Statements for additional information.

Liquidity and Capital Resources

For discussion of the year ended December 31, 2023 compared to the year ended December 31, 2022, refer to Liquidity and Capital Resources of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2023 Form 10-K which was filed with the SEC on February 27, 2024.

For discussion of the year ended December 31, 2024 compared to the year ended December 31, 2023, refer to the Liquidity and Capital Resources section of MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS in the 2024 Form 10-K which was filed with the SEC on February 18, 2025.

All results included throughout the liquidity and capital resources section are presented on a GAAP basis.

Our operating and capital expenditures requirements are provided by internally generated cash flows from operations, the sale of certain receivables, as well as funds from external sources in the capital markets and through bank borrowings.

Our operating and capital expenditure requirements are provided by internally generated cash flows from operations, as well as funds from bank borrowings and other capital market sources.

Our business is capital intensive and requires considerable capital resources.

We annually evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade ratings while meeting our cash needs to fund capital requirements, including construction expenditures, retire debt, pay dividends, fund pension and OPEB obligations, and invest in new and existing ventures.

A broad spectrum of financing alternatives beyond the core financing options can be used to meet our needs and fund growth, including monetizing assets in the portfolio via project financing, asset sales, and the use of other financing structures (e.g., joint ventures, minority partners, etc.).

We regularly evaluate our financing plan and credit line sizing, focusing on maintaining our investment grade credit ratings while meeting our cash needs to fund capital requirements, including funding construction expenditures, retiring debt, paying dividends, funding pension and OPEB obligations, and investing in new and existing ventures, such as our acquisition of Calpine and planned restart of Crane.

Our access to external financing on reasonable terms depends on our credit ratings and current overall capital market business conditions.

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See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Cash Flows from Operating Activities

Our cash flows from operating activities include the sale of energy, energy-related products, and sustainable solutions, as well as sales of nuclear PTCs.

Our future cash flows from operating activities may be affected by future demand for, and market prices of, energy and our ability to continue to produce and supply power at competitive costs, as well as to obtain collections from customers.

The following table provides a summary of the change in cash flows from operating activities for the years ended December 31, 2024 and 2023:

For the Years Ended December 31,

Cash flows from operating activities 2024 2023 $ Change

Net income (loss)

$ 3,738 $ 1,577 $ 2,161

Adjustments to reconcile net income (loss) to cash:

Collateral received (posted), net

1,803 (1,491) 3,294

Option premiums received (paid), net

Pension and non-pension postretirement benefit contributions (184) (54) (130)

Changes in working capital and other noncurrent assets and liabilities (a)

(9,168) (8,355) (813)

Total non-cash operating activities (b)

1,131 2,996 (1,865)

Net cash flows provided by (used in) operating activities

$ (2,464) $ (5,301) $ 2,837

(a) Includes changes in Accounts receivable, Inventories, Accounts payable and accrued expenses, Income taxes, and Other assets and liabilities.

(b) See the Consolidated Statements of Cash Flows for details of non-cash operating activities, includes Depreciation, amortization, and accretion, Asset impairments, Gain on sale of assets and businesses, Deferred income taxes and amortization of ITCs, Net fair value changes related to derivatives, and Net realized and unrealized activity associated with NDTs and equity investments.

See Note 22 — Supplemental Financial Information of the Combined Notes to Consolidated Financial Statements for additional information on the Other non-cash operating activities line.

Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted by changes in working capital in the normal course of business, except as discussed below.

Significant operating cash flow impacts for 2024 and 2023 were as follows:

• In 2024, $1,570 million of cash was received related to the sale of nuclear PTCs.

See Note 6 — Government Assistance of the Combined Notes to Consolidated Financial Statements for additional information.

• Depending upon whether we are in a net mark-to-market liability or asset position, collateral may be required to be posted with or collected from our counterparties, respectively.

In addition, the collateral posting and collection requirements differ depending on whether the transactions are on an exchange or in the over-the-counter markets.

See Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on collateral.

• Option premiums received (paid), net relate to options contracts that we purchase and sell as part of our established policies and procedures to manage risks associated with market fluctuations in commodity prices.

Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information on derivative contracts.

• Increase in cash outflows for pension and non-pension postretirement benefit contributions is primarily due to our annual qualified pension contribution of $161 million and $21 million made in February 2024 and July 2023, respectively.

See Note 14 — Retirement Benefits of the Combined Notes to Consolidated Financial Statements for additional information on pension and non-pension postretirement benefit plans.

• A net increase in cash outflows for changes in working capital and other noncurrent assets and liabilities primarily driven by an increase in cash collections applied to the Deferred Purchase Price (DPP) partially offset by an increase in liabilities associated with state-sponsored programs requiring refund or pass through of the nuclear PTC, as well as price changes related to natural gas purchases in 2024.

See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information on the sales of customer accounts receivable.

Cash Flows from Investing Activities

The following table provides a summary of the change in cash flows from investing activities for the years ended December 31, 2024 and 2023:

Cash Flow Activities

The following table summarizes our cash flow activities for the years ended December 31, 2025 and 2024, respectively:

For the Years Ended December 31,

Cash flows from investing activities

2025 2024 $ Change

Collection of DPP, net $ 10,217 $ 7,340 $ 2,877

Acquisitions of assets and businesses

Cash, restricted cash, and cash equivalents at beginning of period

$ 3,129 $ 454 $ 2,675

Investment in NDT funds, net (277) (228) (49)

Capital expenditures (2,565) (2,422) (143)

Other investing activities 85 31 54

Net cash flows provided by (used in) investing activities

Net cash provided by (used in):

Operating activities 4,237 (2,464) 6,701

Investing activities (3,198) 7,428 (10,626)

Financing activities (420) (2,289) 1,869

Net increase (decrease) in cash, restricted cash, and cash equivalents

619 2,675 (2,056)

Significant investing cash flow impacts for 2024 and 2023 were as follows:

• Collection of DPP, net increased primarily due to the increased cash collections applied to DPP as a result of a decrease in the drawn Facility balance in 2024 compared to 2023.

In addition, more cash collections were reinvested in the Facility in 2024.

See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

• See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information related to the STP acquisition in November 2023.

• Variances in capital expenditures are primarily due to the timing of cash payments for capital projects.

See the "Credit Matters and Cash Requirements" section below for additional information on projected capital expenditure spending.

Cash Flows from Financing Activities

The following table provides a summary of the change in cash flows from financing activities for the years ended December 31, 2024 and 2023:

For the Years Ended December 31,

Cash flows from financing activities

2024 2023 $ Change

Long-term debt, net $ 799 $ 3,027 $ (2,228)

Changes in short-term borrowings, net (1,644) 485 (2,129)

Dividends paid on common stock (444) (366) (78)

Repurchases of common stock (999) (992) (7)

Other financing activities (1) 42 (43)

Net cash flows provided by (used in) financing activities

Cash, restricted cash, and cash equivalents at end of period

$ 3,748 $ 3,129 $ 619

Significant financing cash flow impacts for 2024 and 2023 were as follows:

• Long-term debt, net varies due to debt issuances and redemptions each year.

Refer to the Debt Issuances and Redemptions tables below for additional information.

• Changes in short-term borrowings, net is driven by repayments on and issuances of notes due in less than 365 days.

Refer to Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

• Refer to ITEM 5.

— MARKET FOR REGISTRANT'S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES for additional information on dividends.

See below for quarterly dividends declared.

• Repurchases of common stock is related to our share repurchase program that commenced in March 2023.

See Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Operating Activities

Cash provided by operating activities was $4,237 million for the year ended December 31, 2025, compared to cash used in operating activities of ($2,464) million for the year ended December 31, 2024.

Changes in our cash flows from operations were generally consistent with changes in results of operations, as adjusted for changes in working capital in the normal course of business.

In December 2024, we amended our Accounts Receivable Facility whereby we now retain the rights to our receivables and any changes in our receivable balance flow through operating activities.

This increase in cash flows from operating activities was partially offset by cash outflows associated with an increase in collateral postings.

See Note 7 — Accounts Receivable and Note 15 — Derivative Financial Instruments of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Investing Activities

Cash used in investing activities was ($3,198) million for the year ended December 31, 2025, compared to cash provided by investing activities of $7,428 million for the year ended December 31, 2024.

The change was primarily due to an amendment of our Accounts Receivable Facility.

Prior to the amendment, the collection and reinvestment of proceeds associated with the sale of receivables were treated as cash flows from investing activities in the Consolidated Statements of Cash Flows.

As a result of the amendment, cash collections of accounts receivable are now treated as Cash flows from operating activities in the Consolidated Statements of Cash Flows.

See Note 7 — Accounts Receivable of the Combined Notes to Consolidated Financial Statements for additional information.

Net Cash Provided By (Used In) Financing Activities

Cash used in financing activities was ($420) million for the year ended December 31, 2025, compared to cash used in financing activities of ($2,289) million for the year ended December 31, 2024.

The change primarily relates to long-term debt and changes in short-term borrowings.

Debt issuances and redemptions or repayments vary each year.

The remaining change primarily relates to repurchases of common stock during each period.

See Note 16 — Debt and Credit Agreements and Note 19 — Shareholders' Equity of the Combined Notes to Consolidated Financial Statements for additional information.

Debt Issuances and Redemptions

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Type Interest Rate Maturity Amount

2025 Senior Notes 3.25% June 2025 $ (900)

West Medway II Nonrecourse Debt 1-month SOFR + 3.225% - 3.350%

March 2026 (52)

CR Nonrecourse Debt 3-month SOFR + 2.00% - 2.25% (a)

December 2027 (34)

Continental Wind Nonrecourse Debt 6.00% February 2033 (31)

Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26)

Tax Exempt Pollution Control Revenue Bonds 4.45% March 2025 (23)

RPG Nonrecourse Debt 4.11% March 2035 (7)

Energy Efficiency Project Financing (b)

2.20% - 4.96% December 2025 - March 2026 (3)

Total long-term debt issued (redeemed)

(a) The interest rate for long-term debt redemptions prior to October 2025 were based on SOFR + 2.25%.

Beginning in October 2025, these redemptions are based on SOFR + 2.00%.

(b) Represents funding to install energy conservation measures.

The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

During 2024, the following long-term debt was issued (redeemed):

Type Interest Rate Maturity Amount

Green Senior Notes (a)

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March 2026 (36)

Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56%

January 2037 (26)

Antelope Valley DOE Nonrecourse Debt 2.29% - 3.56% January 2037 (26)

RPG Nonrecourse Debt 4.11% March 2035 (9)

Total long-term debt issued (redeemed)

(a) The Green Senior Notes were issued to finance or refinance, in whole or in part, one or more new or existing Eligible Projects.

(a) Issued to finance or refinance, in whole or in part, one or more new or existing Eligible Projects.

Eligible Projects are defined as investments and expenditures made by us in the 24 months prior to or after the issuance of the notes within the following eligible green categories:

clean generation fleet, clean hydrogen, energy storage, and clean commercial offerings.

(b) Energy Efficiency Project Financing represents funding to install energy conservation measures.

(b) Represents funding to install energy conservation measures.

The maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

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Beginning in July 2024 these redemptions are based on SOFR + 2.25%.

During 2023, the following long-term debt was issued (redeemed):

Type Interest Rate Maturity Amount

2053 Senior Notes

6.50 % October 2053 $ 900

2028 Senior Notes

5.60 % March 2028 750

2033 Senior Notes

5.80 % March 2033 600

2034 Senior Notes

6.13 % January 2034 500

Tax-Exempt Notes Reoffering

4.10% - 4.45% 2025 - 2053 (a)

Energy Efficiency Project Financing (b)

2.20% - 4.96% March 2024 - June 2024

Energy Efficiency Project Financing 2.44% - 6.96%

May 2023 - March 2024

CR Nonrecourse Debt

3-month SOFR + 2.76% (c)

December 2027 (39)

West Medway II Nonrecourse Debt

1-month SOFR + 2.975% - 3.225% (d)(e)

March 2026 (26)

Continental Wind Nonrecourse Debt

6.00 % February 2033 (25)

Antelope Valley DOE Nonrecourse Debt

2.29% - 3.56%

January 2037 (25)

RPG Nonrecourse Debt

4.11 % March 2035 (9)

Total long-term debt issued (redeemed)

(a) The Tax-exempt notes have a maturity date of March 2025 - April 2053, and a mandatory purchase date that ranges from March 2025 - June 2029.

(b) For Energy Efficiency Project Financing, the maturity dates represent the expected date of project completion, upon which the respective customer assumes the outstanding debt.

Beginning in June 2023, these redemptions are based on SOFR + 2.76%.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the CR nonrecourse debt.

(d) The interest rate for long-term debt redemptions prior to May 2023 were based on LIBOR + 2.875%.

Beginning in May 2023, these redemptions are based on SOFR + the variable interest rate of 2.975% - 3.225%.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on the West Medway II nonrecourse debt.

(e) The nonrecourse debt has an average blended interest rate.

Calpine Acquisition

In January 2026, upon completion of the acquisition of Calpine, we assumed all of Calpine's outstanding obligations including approximately $12.6 billion of debt composed of approximately $7.6 billion of long-term debt and approximately $5 billion of various project financing arrangements.

The acquisition of Calpine had the following impacts on our liquidity position:

• The purchase price included cash consideration of approximately $4.5 billion which was funded through cash on hand from normal operating activities at the time of acquisition.

• We assumed approximately $7.6 billion of long-term debt including senior unsecured and secured notes, and corporate term loans.

In December 2025, we commenced private exchange offers and related consent solicitations (“Exchange Offers”) with respect to certain outstanding debt of Calpine.

Pursuant to the Exchange Offers, we issued new notes in January 2026 effectively replacing $2.3 billion of Calpine's senior unsecured and secured notes.

Using the proceeds from our January 2026 bond issuance, as described more fully below, along with cash on hand and short-term debt, we repaid Calpine corporate term loans totaling $2.5 billion immediately after the acquisition closing and repaid additional Calpine senior secured first lien notes totaling $1.25 billion in February 2026.

Following the debt exchange and redemptions discussed, approximately $1.5 billion of long-term Calpine corporate debt remains outstanding, which matures primarily in March 2028.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

• We assumed approximately $5 billion of various project financing arrangements including:

◦ Calpine Construction Finance Company, L.P.

(CCFC) term loan, a first lien senior secured facility with $2.1 billion outstanding at acquisition.

The CCFC term loan matures July 2030 and is secured by certain real and personal property of CCFC, primarily seven natural gas-fired power plants.

◦ Geysers Power Company, LLC (GPC) term loan and credit facility, a first lien senior secured term loan facility, with approximately $1.35 billion and $45 million of borrowings outstanding under the term loan and credit facility, respectively, at acquisition.

The GPC term loan and credit facility mature May 2029.

The GPC term loan and credit facility is secured by certain real and personal property of GPC and subsidiaries primarily consisting of the Geysers Assets.

◦ Nova Power, LLC (Nova Power) credit agreement, comprising credit facilities intended to finance a portion of the cost of the development, construction and operation of the Nova Power battery storage project.

These facilities include a first lien term loan with $591 million outstanding at acquisition and letter of credit facilities.

The Nova Power credit agreement matures September 2031 and is secured by Nova Power's real and personal property.

◦ Greenfield LP (Greenfield) loan facility which includes a term loan with $342 million outstanding at acquisition and several letters of credit facilities.

The Greenfield loan facility matures November 2030 and is secured by certain real and personal property, primarily the Greenfield Energy Center in Ontario, Canada.

◦ Pin Oak Creek Energy Center loan pursuant to the TEF with lender, PUCT, with an outstanding amount of $230 million at acquisition.

The proceeds were used to finance anticipated eligible costs for the development, construction, and installation of Pin Oak Creek Energy Center in Texas.

The loan will mature in October 2045.

◦ Calpine Development Holdings, LLC Revolver (CDHI Revolver) with total capacity of approximately $1.2 billion and borrowings totaling $319 million outstanding at acquisition.

The CDHI Revolver matures March 2028.

• During 2025, we amended our RCF to increase the capacity from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition.

As a result, Calpine's revolving credit facility and commodity linked revolver were both paid off and terminated at the time of acquisition.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

• We issued senior unsecured notes in January 2026 totaling $2.75 billion, the proceeds from which were used to retire certain outstanding indebtedness of Calpine following completion of the Calpine acquisition.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

• In addition to the Calpine revolving credit facility and commodity linked revolver referenced above, we assumed credit facilities totaling approximately $2.3 billion of capacity, which is reduced by outstanding borrowings under the GPC term loan facility and CDHI Revolver totaling $364 million.

At the time of the acquisition, there were outstanding letters of credit on the assumed facilities of approximately $1.7 billion.

These facilities consist of secured and unsecured Calpine facilities and project facilities including the CDHI Revolver.

• We assumed Calpine's accounts receivable sales program with a financial institution which allows for the sale of, at a discount, up to $500 million of certain Calpine receivables.

The program is set to mature November 2026.

At the time of acquisition, there was $399 million of accounts receivable sold into the program outstanding.

Quarterly dividends declared by our Board of Directors during 2025 and for the first quarter of 2026 were as follows:

Period Declaration Date Shareholder of Record Date Dividend Payable Date Cash per Share

First Quarter of 2024 February 26, 2024 March 8, 2024 March 19, 2024 $ 0.3525

Second Quarter of 2024 May 1, 2024 May 29, 2024 June 10, 2024 $ 0.3525

Third Quarter of 2024 July 30, 2024 August 12, 2024 September 6, 2024 $ 0.3525

Fourth Quarter of 2024 November 1, 2024 November 15, 2024 December 6, 2024 $ 0.3525

First Quarter of 2025

February 18, 2025 March 7, 2025 March 18, 2025 $ 0.3878

Second Quarter of 2025

April 29, 2025 May 16, 2025 June 6, 2025 $ 0.3878

Third Quarter of 2025

August 5, 2025 August 18, 2025 September 5, 2025 $ 0.3878

Fourth Quarter of 2025

October 29, 2025 November 17, 2025 December 5, 2025 $ 0.3878

First Quarter of 2026

February 20, 2026 March 9, 2026 March 20, 2026 $ 0.4265

Credit Matters and Cash Requirements

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RISK FACTORS for additional information regarding the effects of uncertainty in the capital and credit markets.

We believe our cash flow from operating activities, access to credit markets and our credit facilities provide sufficient liquidity to support the estimated future cash requirements discussed below, including the cash consideration necessary to close on our proposed acquisition of Calpine.

See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to Consolidated Financial Statements for additional information.

Security Ratings

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our securities ratings.

Our access to the capital markets, including the commercial paper market, and our financing costs in those markets, may depend on our security ratings.

A loss of investment grade credit rating would have required a three-notch downgrade by S&P or Moody's from their current levels as of December 31, 2025 of BBB+ and Baa1, to BB+ and Ba1 or below, respectively.

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Our borrowings are not subject to default or prepayment as a result of a downgrade of our securities, although such a downgrade could increase fees and interest charges under our credit agreements.

Our credit ratings were affirmed following the announcement of our proposed acquisition of Calpine.

Our credit ratings were affirmed by Moody’s and S&P in January 2026 following the completion of the acquisition of Calpine.

If we had lost our investment grade credit ratings as of December 31, 2025, we would have been required to provide incremental collateral estimated to be approximately $2.7 billion to meet collateral obligations for derivatives, non-derivatives, NPNS, and applicable payables and receivables, net of the contractual right of offset under master netting agreements.

1 unchanged sentence

Capital Expenditures

Our most recent estimate of capital expenditures is approximately $3 billion and $3.5 billion for 2025 and 2026, respectively.

Approximately 35% of projected capital expenditures are for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply.

Additionally, the above estimates of capital expenditures includes $1.7 billion of growth capital expenditures, including our planned restart of Crane, nuclear uprates, behind-the-meter infrastructure, and license renewals.

Our most recent estimate of capital expenditures, inclusive of Calpine, is approximately $5.7 billion and $4.7 billion for 2026 and 2027, respectively.

Approximately 29% of projected capital expenditures is for the acquisition of nuclear fuel, which includes additional nuclear fuel to increase inventory levels in response to the potential for the continuing Russia and Ukraine conflict to impact our long-term nuclear fuel supply.

Additionally, the above estimates of capital expenditures include $3.9 billion of growth capital expenditures, including our planned restart of Crane, nuclear uprates, co-location infrastructure, and license renewals.

The remaining amounts primarily reflect additions and upgrades to existing generation facilities (including material condition improvements during nuclear refueling outages).

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS, Other Key Business Drivers for more information on the Russia and Ukraine conflict.

Planned additions and upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory actions, impacts of inflation, changes in the cost of materials and labor, and financing costs.

Planned additions, upgrades and other investments are subject to periodic review and revision to reflect changes in economic conditions impacting our generating assets and other factors, including, but not limited to, market power prices, results of capacity auctions, potential legislative and regulatory actions, impacts of inflation, changes in the cost of materials and labor, and financing costs.

We anticipate funding these capital expenditures with a combination of internally generated funds and borrowings.

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The Pension Protection Act requires the attainment of certain funding levels to avoid benefit restrictions (such as an inability to pay lump sums or to accrue benefits prospectively) and at-risk status (which triggers higher minimum contribution requirements and participant notification).

The contributions in the table below reflect a funding strategy to make levelized annual contributions to offset the growth of the liability.

The contributions in the table below reflect a funding strategy to make annual contributions to offset the growth of the liability.

Unlike the qualified pension plans, our non-qualified pension plans are not subject to statutory minimum contribution requirements.

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Annually, we evaluate whether additional funding for those plans is needed.

For our funded OPEB plans, we consider several factors in determining the level of our contributions, including liabilities management and levels of benefit claims paid.

Expected contributions in 2026 or future years could be affected by adjustments in our pension and OPEB funding strategy, market conditions, or pension regulation changes.

18 unchanged sentences

162 650 812 2026 - 2031

Cash consideration for the acquisition of Calpine (g)

4,500 — 4,500 2026

Total cash requirements $ 9,612 $ 28,228 $ 37,840

2 unchanged sentences

(b) Capacity payments associated with contracted generation lease agreements are net of sublease and capacity offsets of $48 million and $181 million for 2026 and beyond 2026, respectively and $229 million in total.

(c) Purchase power obligations primarily include expected payments for REC purchases and capacity payments associated with contracted generation agreements, which may be reduced based on plant availability.

Expected payments exclude payments on renewable generation contracts that are contingent in nature.

(d) Represents commitments to purchase nuclear fuel and related services and natural gas-related transportation and capacity.

2 unchanged sentences

(f) These amounts represent our expected contributions to our qualified pension plans.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information of our other commitments potentially triggered by future events.

(g) In January 2026, we acquired all of the outstanding equity interest of Calpine in a cash and stock transaction.

The aggregate purchase price included approximately $4.5 billion in cash.

See Note 2 — Mergers, Acquisitions, and Dispositions of the Combined Notes to the Combined Consolidated for additional information.

See Note 18 — Commitments and Contingencies of the Combined Notes to Consolidated Financial Statements for additional information on our other commitments potentially triggered by future events.

Additionally, see below for where to find additional information regarding the financial commitments in the table above in the Combined Notes to Consolidated Financial Statements.

5 unchanged sentences

Pension contributions Note 14 — Retirement Benefits

Sales of Customer Accounts Receivable

We had an accounts receivable financing facility with a number of financial institutions and a commercial paper conduit to sell certain receivables.

The facility was amended effective December 31, 2024 resulting in an increased funding limit secured by certain receivables.

See Note 7 — Accounts Receivable and Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Accounts Receivable Facility

We have an accounts receivable financing facility that provides us access to revolving loans from a number of financial institutions secured by certain customer accounts receivables.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information.

Project Financing

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Lenders do not have recourse against us in the event of a default.

a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates.

If a project financing entity does not maintain compliance with its specific debt covenants, there could be a requirement to accelerate repayment of the associated debt or other project-related borrowings earlier than the stated maturity dates.

In these instances, if such repayment were not satisfied, or restructured, the lenders or security holders would generally have rights to foreclose against the project-specific assets and related collateral.

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We may use our credit facilities for general corporate purposes, including meeting short-term funding requirements and the issuance of letters of credit.

During 2025, we increased the capacity of our RCF from $4.5 billion to $7.0 billion, of which the incremental $2.5 billion became available upon closing of the Calpine acquisition in January 2026.

See Note 16 — Debt and Credit Agreements of the Combined Notes to Consolidated Financial Statements for additional information on our credit facilities.

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Percentage of Capital Structure

Commercial paper and notes payable 7 %

Long-term debt 31 %

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These NRC minimum funding levels are typically based upon the assumption that decommissioning activities will commence after the end of the current licensed life of each unit.

If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available.

If a unit fails the NRC minimum funding test, then the plant’s owners or parent companies would be required to take steps, such as providing financial

guarantees through surety bonds, letters of credit, or parent company guarantees or making additional cash contributions to the NDT fund to ensure sufficient funds are available.

See Note 10 — Asset Retirement Obligations of the Combined Notes to Consolidated Financial Statements for additional information.

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We will continue to file Crane's decommissioning funding status with the NRC annually until restart, at which point we will file decommissioning funding status reports in accordance with applicable NRC requirements.

Additionally, as of December 31, 2024, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion

Station related to the Independent Spent Fuel Storage Installation.

Additionally, as of December 31, 2025, we have adequate NDT funds for the remaining radiological decommissioning cost at Zion Station related to the Independent Spent Fuel Storage Installation.

Decommissioning costs other than radiological may require funding from us.

1 unchanged sentence

Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis