Cheniere Energy, Inc.

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We operate natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the“Sabine Pass LNG Terminal” and“Corpus Christi LNG Terminal”), with total expected production capacity of over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 9 mtpa was under construction and the remainder was in operation as of December 31, 2025, comprised of the following:

•over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities at the Sabine Pass LNG Terminal owned by CQP (the“SPL Project”). The Sabine Pass LNG Terminal also hasfive LNG storage tanks, vaporizers andthree marine berths. CQP also owns and operates a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several large interstate and intrastate pipelines (the“Creole Trail Pipeline”). As of December 31, 2025, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.

•over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including over 9 mtpa under construction and the remainder in operation as of December 31, 2025, from our natural gas liquefaction facilities at the Corpus Christi LNG Terminal, of which we have 100% ownership interest. The Corpus Christi LNG Terminal also hasthree LNG storage tanks andtwo marine berths. We also own an approximately 21-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several large interstate and intrastate natural gas pipelines (the“Corpus Christi Pipeline”). The projects under construction at the Corpus Christi LNG Terminal include:

◦a project consisting ofseven midscale Trains that is expected to add total production capacity of over 10 mtpa of LNG once fully completed (the“Corpus Christi Stage 3 Project”), with over 4 mtpa under construction and the remainder in operation from the first four midscale Trains that have reached substantial completion as of December 31, 2025; and

◦a project consisting oftwo additional midscale Trains that is expected to add total production capacity of approximately 5 mtpa of LNG once fully completed, inclusive of estimated debottlenecking opportunities (the“CCL Midscale Trains 8 & 9 Project” and together with the existing assets at the Corpus Christi LNG Terminal, the Corpus Christi Stage 3 Project and the Corpus Christi Pipeline, the“CCL Project”), which was under construction as of December 31, 2025. Our board of directors (our“Board”) made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project on June 17, 2025, and issued a full notice to proceed with construction to Bechtel Energy Inc. (“Bechtel”) effective June 18, 2025.

In addition to the SPL Project and the CCL Project (collectively, the“Liquefaction Projects”), we are developing expansion projects to provide additional liquefaction capacity at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal and are commercializing to support the additional liquefaction capacity associated with these potential expansion projects. These projects or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before our Board makes a positive FID.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

Our Consolidated Financial Statements have been prepared in accordance with GAAP. The Consolidated Financial Statements include the accounts of Cheniere, its subsidiaries in which we hold a controlling interest and VIEs we consolidate under certain criteria discussed further below. All intercompany accounts and transactions have been eliminated in consolidation.

VIEs

We make a determination at the inception of each arrangement whether an entity in which we have made an investment or in which we have other variable interests is considered a VIE. Generally, an entity is a VIE if either (1) the entity does not have sufficient equity at risk to finance its activities without additional subordinated financial support from other parties, (2) the entity’s investors lack any characteristics of a controlling financial interest or (3) the entity was established with non-substantive voting rights.

We consolidate VIEs when we are deemed to be the primary beneficiary. The primary beneficiary of a VIE is generally the party that both: (1) has the power to make decisions that most significantly affect the economic performance of the VIE and (2) has the obligation to absorb losses or the right to receive benefits that in either case could potentially be significant to the VIE. If we are not deemed to be the primary beneficiary of a VIE, we account for the investment or other variable interests in a VIE in accordance with applicable GAAP.

See Note 8—Non-controlling Interests and Variable Interest Entities for additional details about our assessment of VIEs.

Non-controlling Interests

When we consolidate an entity, we include 100% of the assets, liabilities, revenues and expenses of the entity in our Consolidated Financial Statements. For those entities that we consolidate in which our ownership is less than 100%, we record a non-controlling interest as a component of equity on our Consolidated Balance Sheets, which represents the third party ownership in the net assets of the respective consolidated subsidiary. Changes in our ownership interests in an entity that do not result in deconsolidation are generally recognized within equity.

Non-controlling interests are presented in permanent equity within our Consolidated Balance Sheets unless they are redeemable at a fixed or determinable price on a fixed or determinable date at the option of the holder or upon the occurrence of an event that is not solely within our control, in which case they are presented in temporary equity. The carrying amount of the redeemable non-controlling interest is equal to the greater of (1) the carrying value of the non-controlling interest adjusted each reporting period for income or loss attributable to the non-controlling interest as well as any applicable distributions made or (2) the redemption value. Remeasurements to the redemption value of the redeemable non-controlling interest are recognized in retained earnings within the Consolidated Balance Sheets.

The portion of the net income or loss attributable to the non-controlling interests and redeemable non-controlling interest is reported as net income or loss attributable to non-controlling interests on our Consolidated Statements of Operations. See Note 8—Non-controlling Interests and Variable Interest Entities for additional details about our non-controlling interests.

Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to fair value measurements of derivatives and other instruments, useful lives of property, plant and equipment, leases, asset retirement obligations (“AROs”) and recoverability of deferred tax assets, each as further discussed under the respective sections within this note. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates.

Fair Value Measurements

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy Levels 1, 2 and 3 are terms for the priority of inputs to valuation approaches used to measure fair value. Hierarchy Level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy Level 2 inputs are inputs that are directly or indirectly observable for the asset or liability, other than quoted prices included within Level 1. Hierarchy Level 3 inputs are inputs that are not observable in the market.

In determining fair value, we use observable market data, or models that incorporate observable market data, when such data is available. In addition to market information, we incorporate transaction-specific details that, in management’s judgment, market participants would take into account in measuring fair value. We attempt to maximize our use of observable inputs and minimize our use of unobservable inputs in arriving at fair value estimates.

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 6—Derivative Instruments, and liability-classified share-based compensation awards, as disclosed in Note 15—Share-Based Compensation.

The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 10—Debt for our debt fair value estimates, including our estimation methods.

Revenue Recognition

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the FOB or DAP delivery terms, which is generally the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer.

Sales generated during the commissioning phase of a Train are offset against the cost of construction for the respective Train, as further described under the caption Property, Plant and Equipment below. After substantial completion of a Train is achieved, fees received for LNG volumes produced are recognized as LNG revenues.

With respect to regasification revenues, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs. We have concluded that the variable fees under our TUAs meet the exception for allocating variable consideration to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation that is a series. As such, the variable consideration for the TUA is allocated to the period that the respective good or service is delivered to the customer.

For transactions where we receive consideration from the customer, we assess whether we are the principal or the agent in the arrangement. Arrangements where we have concluded that we act as a principal are presented within our Consolidated Statements of Operations on a gross basis, and arrangements where we have concluded that we act as an agent are presented within our Consolidated Statements of Operations on a net basis. For the years ended December 31, 2025, 2024 and 2023, we didnot have any material revenue arrangements that were presented within our Consolidated Statements of Operations on a net basis.

See Note 12—Revenues for additional information regarding our revenues.

Cash and Cash Equivalents

We consider all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets. Our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements. Our subsidiaries that are subject to such restrictions are required to deposit all cash received into reserve accounts controlled by the collateral trustee pursuant to the respective accounts agreement entered into with the collateral trustee for the benefit of the debt holders.

Current Expected Credit Losses

Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers contract and payment terms, the counterparty’s established credit rating and credit worthiness and other risks or available financial assurances. We calculate the allowance for credit losses under a probability-of-default method applied to pools of assets with similar risk characteristics and reflect credit enhancements such as letters of credit and guarantees to the extent that such enhancements are contractually linked to the underlying asset and with the same counterparty. Quarterly, we evaluate whether our method continues to be appropriate based on historical collections and additional information as it becomes available and adjust our reserve as necessary.

The following table reflects the changes in our current expected credit losses (in millions):

Inventory

LNG, natural gas and other commodity inventory are recorded at the lower of weighted average cost and net realizable value. Materials and other inventory are recorded at the lower of cost and net realizable value. Inventory is charged to expense when sold, or, for certain qualifying costs, capitalized to property, plant and equipment when issued, primarily using the weighted average method.

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction or acquisition of assets, commissioning activities and costs that significantly extend the useful life or increase the functionality and/or capacity of an asset are capitalized. Expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of LNG terminal construction once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction.

Generally, costs that benefit us more broadly than for a specific project are capitalized prior to a project meeting the criteria otherwise necessary for capitalization and typically include land and land acquisition costs, preliminary material and equipment procurement and engineering design work.

Sales proceeds earned from volumes produced and sold during the commissioning phase of a respective Train, which includes test activities such as production and removal of LNG from storage, are offset against the cost of construction for the respective Train, net of associated costs, as such activities are necessary to test the facility and bring the asset to the condition necessary for its intended use.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except (1) assets under finance leases which are depreciated over the lesser of the respective lease term or the useful lives and (2) land which is not depreciated. Refer to Note 5—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category and Note 11—Leases for additional details of our finance leases. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the Consolidated Balance Sheets, and any resulting gains or losses on disposal are recorded in other operating costs and expenses.

Management tests property, plant and equipment for impairment whenever events or changes in circumstances have indicated that the carrying amount of property, plant and equipment might not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets for purposes of assessing recoverability. Recoverability generally is determined by comparing the carrying value of the asset to the expected undiscounted future cash flows of the asset. If the carrying value of the asset is not recoverable, the amount of impairment loss is measured as the excess, if any, of the carrying value of the asset over its estimated fair value.

We didnot record any material impairments related to property, plant and equipment during the years ended December 31, 2025, 2024 and 2023.

Interest Capitalization

We capitalize interest costs as part of the historical cost of qualifying assets, mainly during the construction period of the qualifying assets, which primarily consists of LNG terminals and related assets. Upon placing the underlying asset in service, these costs are depreciated or amortized over the estimated useful life of the corresponding assets for which interest costs were incurred.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement, unless a derivative instrument satisfies criteria for, and we elect, the normal purchases and normal sales exception and account for the instrument under the accrual method of accounting, whereby the designated instrument’s revenues or expenses, as applicable, are recognized only upon delivery, receipt or realization of the underlying transaction.

We didnot have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2025, 2024 and 2023; therefore, the changes in the fair value of our derivative instruments are recorded in earnings.

As described in Concentration of Credit Risk below, the use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees. Variation margins or other daily margining posted for exchange-traded transactions that are contractually characterized as settlement of the respective derivative position are netted against the respective derivative asset or liability positions.

We have elected to report derivative assets and liabilities under master netting arrangements with the same counterparty on a net basis. Additionally, the fair value amounts recognized as cash collateral pledged or received, such as initial margins and other collateral that are not contractually characterized as settlement of the respective derivative positions, are offset against the fair value of derivatives executed with the same counterparty under a master netting arrangement. Collateral balances not offset against a derivative position are presented on our Consolidated Balance Sheets within margin deposits and other current liabilities. Derivative assets and liabilities not subject to master netting arrangements are presented net when we have a legally enforceable right and the intent to offset amounts with the same counterparty.

See Note 6—Derivative Instruments for additional details about our derivative instruments.

Leases

We determine if an arrangement is, or contains, a lease at inception of the arrangement. When we determine the arrangement is, or contains, a lease in which we are the lessee, we classify the lease as either an operating lease or a finance lease. Operating and finance leases are recognized on our Consolidated Balance Sheets by recording a lease liability representing the obligation to make future lease payments and a right-of-use asset representing the future right to use the underlying asset over the lease term.

Operating and finance lease right-of-use assets and liabilities are generally recognized based on the present value of minimum lease payments over the lease term. In determining the present value of minimum lease payments, we use the implicit interest rate in the lease if readily determinable. In the absence of a readily determinable implicit interest rate, we discount our expected future lease payments using the incremental borrowing rate of the relevant Cheniere entity, which can be a parent entity when the terms of the lease arrangements are significantly influenced by the parent’s credit standing. The incremental borrowing rate is an estimate of the interest rate that a given entity would have to pay to borrow on a collateralized basis over a similar term to that of the lease term. Options to renew a lease are included in the lease term and recognized as part of the right-of-use asset and lease liability when they are reasonably certain to be exercised.

We have elected practical expedients to (1) omit leases with an initial term of 12 months or less from recognition on our Consolidated Balance Sheets and (2) to combine both the lease and non-lease components of an arrangement’s contractual consideration in calculating the right-of-use asset and lease liability for all classes of leased assets.

Lease expense for operating lease payments is recognized on a straight-line basis over the lease term. Lease expense for finance leases is recognized as the sum of the amortization of the right-of-use assets on a straight-line basis and the interest on lease liabilities using the effective interest method over the lease term.

Certain of our leases also contain variable payments that are included in the right-of-use asset and lease liability only when the payments are in-substance fixed payments that are, in effect, unavoidable.

When we determine the arrangement is, or contains, a lease in which we are the lessor or sublessor, we assess classification of the lease as either an operating lease, sales-type lease or direct financing lease. All such arrangements have been assessed as operating leases and consist of sublessor arrangements in which we have not been relieved of our primary obligation under the original lease. Our sublessor arrangements are not recognized on our Consolidated Balance Sheets and we recognize income from fixed lease payments under these arrangements on a straight-line basis over the sublease term. We recognize income from variable lease payments in the period in which the changes in facts and circumstances on which the variable lease payments are based occur.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, consist principally of accounts receivable and contract assets related to our long-term SPAs, as our contracted LNG sales are primarily under SPAs with terms exceeding 10 years. As of December 31, 2025, we had SPAs with initial terms of 10 or more years with approximately 30 different third party customers, with customers under common control being considered a single customer. We are dependent on the respective customers’ creditworthiness and their ability to perform under their respective agreements. While substantially all of our long-term third party customer arrangements are executed with a creditworthy company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We havenot incurred credit losses related to these cash balances to date.

While we use derivative instruments that expose us to counterparty credit risk, our underlying arrangements typically include provisions that protect us and our counterparties against such risk. For example, our commodity derivatives executed over-the-counter or through an exchange often require collateral that is returned to us (or to the counterparty) on or near the settlement date or are settled on a daily margin basis with investment grade financial institutions, and are primarily facilitated by independent system operators and by clearing brokers. For non-exchange traded transactions, payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds the pre-established credit limit with the counterparty. Our FX derivative instruments are placed with investment grade financial institutions whom we believe have insignificant credit risks.

We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. Even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our assets.

Debt

Our debt consists of current and long-term secured and unsecured debt securities and credit facilities with banks and other lenders. Debt issuances are placed directly by us or through securities dealers or underwriters and are held by institutional and retail investors.

Term debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees and commitment fees. Costs associated with entering into a line of credit or on undrawn funds are presented as an asset and classified as current or non-current, consistent with the respective credit facility. As of December 31, 2025 and 2024, all of such costs were classified as other non-current assets, net, on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt except in the case of our credit facilities, in which such items are amortized on a straight-line basis over the contractual term of the facility. Amortization is recorded in interest expense, net of capitalized interest using the effective interest method.

We classify debt on our Consolidated Balance Sheets based on contractual maturity, with the following exceptions:

•We classify term debt that is contractually due within one year as long-term debt if management has the intent and ability to refinance the current portion of such debt with future cash proceeds from an executed long-term debt or equity agreement.

•We evaluate the classification of long-term debt extinguished after the balance sheet date but before the financial statements are issued based on facts and circumstances existing as of the balance sheet date.

Asset Retirement Obligations

We recognize AROs for legal obligations associated with the retirement of long-lived assets that result from the acquisition, construction, development and/or normal use of the asset and for conditional AROs in which the timing or method of settlement are conditional on a future event that may or may not be within our control. The fair value of a liability for an ARO is recognized in the period in which it is incurred, if a reasonable estimate of fair value can be made. The fair value of the liability is added to the carrying amount of the associated asset. This additional carrying amount is depreciated over the estimated useful life of the asset.

Our real property lease agreements at the Sabine Pass LNG Terminal require us to surrender the LNG terminal in good order and repair, with normal wear and tear and casualty excepted, at the expiration of the term of the leases, with renewal options extending such terms up to 90 years. We have determined that the cost to surrender the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty excepted, is immaterial, thus we havenot recorded an ARO associated with the Sabine Pass LNG Terminal.

Our Creole Trail Pipeline and Corpus Christi Pipeline are subject to regulations by the FERC for proper abandonment of a pipeline, including the disconnection of the pipeline from all sources and supplies of gas and other decommissioning costs. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the U.S. and intend to maintain them regularly. For these reasons, we havenot recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline.

Share-based Compensation

We have awarded share-based compensation in the form of restricted stock shares, restricted stock units, performance stock units and phantom units, as further described in Note 15—Share-based Compensation. We initially measure share-based compensation based upon the estimated fair value of awards. The recognition period for these costs begins at the earlier of the applicable service inception date or grant date and continues throughout the requisite service period.

For equity-classified share-based compensation awards, compensation cost is recognized based on the grant-date fair value and not subsequently remeasured unless modified. For liability-classified share-based compensation awards that cash settle or include an election to be cash settled, compensation costs are remeasured at fair value through settlement or maturity. Except for awards that contain market conditions, the grant-date fair value is estimated based on our stock price on the grant date. The fair value of awards containing market conditions is estimated using a Monte Carlo model as of the grant date, which utilizes inputs such as expected stock volatility, risk-free rates and dividend yield.

For awards that contain graded vesting periods, the fair value is recognized as expense (net of any capitalization in accordance with GAAP) on a straight-line basis, generally over the term of the entire award, except when modifications may require an accelerated method. For awards that contain cliff vesting periods, the fair value is recognized as expense (net of any capitalization in accordance with GAAP) on a straight-line basis over the requisite service period.

For awards with both time and performance-based conditions, we recognize compensation cost based on the probable outcome of the performance condition at each reporting period.

We account for forfeitures as they occur.

Foreign Currency

The functional currency of all of our subsidiaries is the U.S. dollar. Certain of our subsidiaries transact in currencies outside of the U.S. dollar, which gives rise to the recognition of transaction gains and losses based on the change in exchange rates between the U.S. dollar and the currency in which the foreign currency transaction is denominated. During the years ended December 31, 2025, 2024 and 2023, we recognized net transaction gains (losses) totaling $(5) million, $1 million and $1 million, respectively, excluding gains and losses from FX derivatives which are further detailed in Note 6—Derivative Instruments. Substantially all of our transaction gains and losses related to commercial transactions were executed by Cheniere Marketing, primarily consisting of Euro denominated receivables, which are presented within LNG revenues in our Consolidated Statements of Operations with the underlying activities.

Income Taxes

Provisions for income taxes are based on taxes payable or refundable for the current year and deferred taxes on temporary differences between the tax basis of assets and liabilities and their reported amounts in our Consolidated Financial Statements. Deferred tax assets and liabilities are included in our Consolidated Financial Statements at currently enacted income tax rates applicable to the period in which the deferred tax assets and liabilities are expected to be realized or settled. As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes.

A valuation allowance is recorded to reduce the carrying value of our deferred tax assets when it is more likely than not that some or all of our deferred tax assets will not be realized. We evaluate the realizability of our deferred tax assets as of each reporting date, weighing all positive and negative evidence. The assessment requires significant judgment and is performed in each of our applicable jurisdictions. In making such determination, we consider various factors such as historical profitability, future projections of sustained profitability underpinned by fixed-price long-term SPAs and reversal of existing deferred tax liabilities.

We recognize the financial statement effects of a tax position when it is more likely than not, based on the technical merits, that the position will be sustained upon examination.

The Inflation Reduction Act of 2022 (“IRA”) imposed a 15% CAMT effective in 2023, that is based on 15% of an applicable corporation’s adjusted financial statement income. We have elected to account for the effects of the CAMT on deferred tax assets, carryforwards and tax credits in the period they arise.

Net Income or Loss Per Share

Basic net income or loss per share attributable to common stockholders excludes dilution and is computed by dividing net income or loss attributable to common stockholders during the period by the weighted average number of common shares outstanding during the period. Diluted net income or loss per share reflects potential dilution from our unvested stock and is computed by dividing net income or loss attributable to common stockholders by the weighted average number of common shares outstanding during the period, which is increased by the number of additional common shares that would have been outstanding if the potential common shares had been issued. The additional common shares are calculated using the treasury stock method, which assumes the unvested shares are issued at the beginning of the period (or at the time of grant, if later) and that the amount of unrecognized compensation cost is used to purchase our common stock at the average market price during the period. However, if the effect of any additional securities are anti-dilutive (i.e., resulting in a higher net income per share or lower net loss per share), they are excluded from the dilutive net income or loss computation.

Refer to Note 17—Net Income per Share Attributable to Common Stockholders for additional details of the computation for the years ended December 31, 2025, 2024 and 2023.

Recent Accounting Standards

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740), which we adopted prospectively on December 31, 2025. This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. The adoption of this guidance did not have an impact on our results of operations and financial condition, but updated the required disclosures — see Note 14—Income Taxes.

ASU 2024-03

In November 2024, the FASB issued ASU No. 2024-03, Income Statement – Reporting Comprehensive Income – Expense Disaggregation Disclosures (Subtopic 220-40): Disaggregation of Income Statement Expenses, as clarified by ASU No. 2025-01 in January 2025. This guidance requires disaggregated disclosures about certain income statement expense line items on an annual and interim basis. We continue to evaluate the impact of the provisions of this guidance on our disclosures, but plan to adopt this guidance prospectively and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2027.

NOTE 3—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

Trade and other receivables, net of current expected credit losses, consisted of the following (in millions):

Upon collection of our receivables by SPL and CCL, cash will be immediately restricted for the payment of liabilities related to the Liquefaction Projects. See Note 2—Summary of Significant Accounting Policies for further discussion of our Restricted Cash and Cash Equivalents.

NOTE 4—INVENTORY

Inventory consisted of the following (in millions):

NOTE 5—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

Property, plant and equipment, net of accumulated depreciation consisted of the following (in millions):

The following table shows depreciation expense and offsets to terminal assets (in millions):

(1)We realize offsets to terminal assets for sales proceeds from commissioning volumes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

NOTE 6—DERIVATIVE INSTRUMENTS

We have the following derivative instruments:

•commodity derivatives consisting of the following (collectively,“Commodity Derivatives”):

◦natural gas and power supply contracts, including our IPM agreements, for the development, commissioning and operation of the Liquefaction Projects and expansion projects, as well as the associated economic hedges (collectively, the“Liquefaction Supply Derivatives”); and,

◦LNG derivatives in which we have contractual net settlement and economic hedges on the exposure to the commodity markets in which we have contractual arrangements to purchase or sell physical LNG (collectively,“LNG Trading Derivatives”); and

•FX contracts to hedge exposure to currency risk associated with cash flows denominated in currencies other than U.S. dollar (“FX Derivatives”), associated with both LNG Trading Derivatives and operations in countries outside of the U.S.

The following table shows the fair value of our derivative instruments that are required to be measured at fair value on a recurring basis, distinguished by the fair value hierarchy levels prescribed by GAAP (in millions):

We value the Liquefaction Supply Derivatives and LNG Trading Derivatives using a market or option-based approach incorporating present value techniques, as needed, which incorporates observable commodity price curves, when available, and other relevant data. We value our FX Derivatives with a market approach using observable FX rates and other relevant data.

We include a significant portion of the Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models, which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility includes the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control. As applicable to our natural gas supply contracts, our fair value estimates incorporate market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of satisfaction of certain events or development of infrastructure to support natural gas gathering and transport. We may recognize changes in fair value through earnings that could significantly impact our results of operations if and when such uncertainties are resolved.

The Level 3 fair value measurements of our natural gas positions within the Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for the Level 3 Liquefaction Supply Derivatives as of December 31, 2025:

(1)Unobservable inputs were weighted by the relative fair value of the instruments.

(2)Spread contemplates U.S. dollar-denominated pricing.

Increases or decreases in basis or pricing spreads, in isolation, would decrease or increase, respectively, the fair value of the Liquefaction Supply Derivatives.

The following table shows the changes in the fair value of the Level 3 Liquefaction Supply Derivatives (in millions):

(1)Does not include the realized value associated with derivative instruments that settle through physical delivery, as settlement is equal to the contractually fixed price from trade date multiplied by contractual volume. See settlements line item in this table.

(2)Impact to earnings on deals that existed at the beginning of the period and continue to exist at the end of the period.

(3)Impact to earnings on deals that were entered into during the reporting period and continue to exist at the end of the period.

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period, which continue to exist at the end of the period.

(5)Roll-off in the current period of amounts recognized in our Consolidated Balance Sheets at the end of the previous period due to settlement of the underlying instruments in the current period.

(6)Transferred out of Level 3 as a result of observable market for the underlying natural gas purchase agreements.

Commodity Derivatives

We hold Liquefaction Supply Derivatives, which are indexed to Henry Hub, global LNG or other natural gas price indices. As of December 31, 2025, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence or accelerate upon the satisfaction of certain events or development of infrastructure to support natural gas gathering and transport.

Cheniere Marketing has historically entered into, and may from time to time enter into, LNG transactions that provide for contractual net settlement. Such transactions are accounted for as LNG Trading Derivatives along with financial commodity contracts in the form of swaps or futures. The terms of LNG Trading Derivatives range up to approximatelyone year.

The following table shows the notional amounts of our Commodity Derivatives:

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of both December 31, 2025 and 2024.

The following table shows the effect and location of our Commodity Derivatives recorded on our Consolidated Statements of Operations (in millions):

(1)Fair value fluctuations associated with activities of our Commodity Derivatives are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

(2)Does not include the realized value associated with the Liquefaction Supply Derivatives that settle through physical delivery.

FX Derivatives

Cheniere Marketing holds FX Derivatives to protect against the volatility in future cash flows attributable to changes in international currency exchange rates. The FX Derivatives are executed primarily to economically hedge the foreign currency exposure arising from cash flows expended for both physical and financial LNG transactions that are denominated in a currency other than the U.S. dollar. The terms of FX Derivatives range up to approximatelyone year.

The total notional amount of our FX Derivatives was $783 million and $642 million as of December 31, 2025 and 2024, respectively.

The following table shows the effect and location of our FX Derivatives recorded on our Consolidated Statements of Operations (in millions):

The following table shows the fair value and location of our derivative instruments on our Consolidated Balance Sheets (in millions):

Consolidated Balance Sheets Presentation

The following table reconciles the fair value of our derivative assets and liabilities on a gross basis, by contract, to net amounts as presented on our Consolidated Balance Sheets after offsetting for any balances with the same counterparty under master netting arrangements or other relevant netting criteria under GAAP (in millions):

(1)Includes current and non-current derivative assets of $9 million and $4,663 million, respectively, as of December 31, 2025 and $155 million and $1,903 million, respectively, as of December 31, 2024.

(2)Includes current and non-current derivative liabilities of $618 million and $1,208 million, respectively, as of December 31, 2025 and $902 million and $1,865 million, respectively, as of December 31, 2024.

The table below shows the collateral balances that are recorded within margin deposits and other current liabilities that are not netted on our Consolidated Balance Sheets (in millions):

NOTE 7—OTHER NON-CURRENT ASSETS, NET

Other non-current assets, net consisted of the following (in millions):

NOTE 8—NON-CONTROLLING INTERESTS AND VARIABLE INTEREST ENTITIES

Substantially all of our consolidated VIEs’ assets and liabilities relate to CQP. We own a 48.6% limited partner interest in CQP, and we also own all of the 2% general partner interest and 100% of the incentive distribution rights in CQP. The remaining 49.4% non-controlling limited partner interest in CQP is held by affiliates of Blackstone Inc. and Brookfield Asset Management, Inc. as well as the public.

CQP is a limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG Terminal and related assets. Our wholly-owned subsidiary, Cheniere Partners GP, is the general partner of CQP. The board of directors of Cheniere Partners GP includes three directors appointed by CQP Holdco LP (an affiliate of Blackstone Inc. and Brookfield Asset Management Inc.) (“CQP Holdco”), four directors appointed by us andfour independent directors mutually agreed upon by CQP Holdco and us and appointed by us. In addition, we provided CQP Holdco with a right to maintainone board seat on our Board. A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at leasttwo directors appointed by CQP Holdco, two directors appointed by us andtwo independent directors. CQP Holdco will no longer be entitled to appoint Cheniere Partners GP directors in the event that CQP Holdco’s ownership in CQP is less than 20% of outstanding common units.

As a holder of common units of CQP, we are not obligated to fund losses of CQP. However, our capital account, which would be considered in allocating the net assets of CQP were it to be liquidated, continues to share in losses of CQP. We have determined that Cheniere Partners GP is a VIE and that we, as the holder of the equity at risk, do not have a controlling financial interest due to the rights held by CQP Holdco. However, we continue to consolidate CQP as a result of CQP Holdco’s right to maintain one board seat on our Board which creates a de facto agency relationship between CQP Holdco and us. GAAP requires that when a de facto agency relationship exists, one of the members of the de facto agency relationship must consolidate the VIE based on certain criteria. As a result, we consolidate CQP in our Consolidated Financial Statements.

The following table presents the summarized consolidated assets and liabilities (in millions) of our consolidated VIEs, which are included in our Consolidated Balance Sheets. The assets in the table below may only be used to settle obligations of the respective VIEs. In addition, there is no recourse to us for the consolidated VIEs’ liabilities. The assets and liabilities in the table below exclude intercompany balances between the respective VIEs and Cheniere that eliminate in our Consolidated Financial Statements.

NOTE 9—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions):

NOTE 10—DEBT

Debt consisted of the following (in millions):

(1)Subsequently in February 2026, SPL redeemed the remaining $200 million aggregate principal amount of its 2026 SPL Senior Notes.

(2)Includes notes that amortize based on a fixed amortization schedule as set forth in their respective indentures.

Senior Notes

SPL Senior Secured Notes

The SPL Senior Secured Notes are senior secured obligations of SPL, ranking equally in right of payment with SPL’s other existing and future senior debt that is secured by the same collateral and senior in right of payment to any of its future subordinated debt. Subject to permitted liens, the SPL Senior Secured Notes are secured on apari passu first-priority basis by a security interest in all of the membership interests in SPL and substantially all of SPL’s assets. SPL may, at any time, redeem all or part of the SPL Senior Secured Notes at specified prices set forth in the respective indentures governing the SPL Senior Secured Notes, plus accrued and unpaid interest, if any, prior to the date of redemption. The series of SPL Senior Secured Notes due in 2037 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

CQP Senior Notes

The CQP Senior Notes are jointly and severally guaranteed by each of CQP’s current and certain future subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP (each a“Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are senior obligations of CQP, ranking equally in right of payment with CQP’s other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of CQP’s secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2)10% of net tangible assets, the 2029 CQP Senior Notes, 2031 CQP Senior Notes and 2032 CQP Senior Notes will be secured by a first-priority lien (subject to permitted encumbrances) on substantially all the existing and future tangible and intangible assets and rights of CQP and the CQP Guarantors, as well as the equity interests in the CQP Guarantors. The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of any other senior secured obligations. CQP may, at any time, redeem all or part of the CQP Senior Notes at specified prices set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, prior to the date of redemption.

CCH Senior Secured Notes

The CCH Senior Secured Notes are jointly and severally guaranteed by CCH’s subsidiaries, CCL, CCP and Corpus Christi Pipeline GP, LLC (each a“CCH Guarantor” and collectively, the“CCH Guarantors”). The CCH Senior Secured Notes are senior secured obligations of CCH, ranking senior in right of payment to any and all of CCH’s future indebtedness that is subordinated to the CCH Senior Secured Notes and equal in right of payment with CCH’s other existing and future indebtedness that is senior and secured by the same collateral securing the CCH Senior Secured Notes. The CCH Senior Secured Notes are secured by a first-priority security interest in substantially all of CCH’s and the CCH Guarantors’ assets. CCH may, at any time, redeem all or part of the CCH Senior Secured Notes at specified prices set forth in the respective indentures governing the CCH Senior Secured Notes, plus accrued and unpaid interest, if any, prior to the date of redemption. The series of CCH Senior Secured Notes due in 2039 are fully amortizing according to a fixed sculpted amortization schedule, as set forth in the respective indentures.

Cheniere Senior Notes

The Cheniere Senior Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the Cheniere Senior Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The Cheniere Senior Notes are currently unsecured, but in certain instances may become secured in the future in connection with the incurrence of additional secured indebtedness by us. When required, the Cheniere Senior Notes will be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries), which liens rank pari passu with the liens securing the Cheniere Revolving Credit Facility. As of December 31, 2025, the Cheniere Senior Notes are not guaranteed by any of our subsidiaries. In the future, any subsidiary that guarantees any of our material indebtedness will also guarantee the Cheniere Senior Notes. We may, at any time, redeem all or part of the Cheniere Senior Notes at specified prices set forth in the indenture governing the Cheniere Senior Notes, plus accrued and unpaid interest, if any, prior to the date of redemption.

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2025 (in millions):

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of December 31, 2025 (in millions):

(1)The obligations of SPL under the SPL Revolving Credit Facility are secured by substantially all of the assets of SPL as well as a pledge of all of the membership interests in SPL and certain future subsidiaries of SPL on apari passu basis by a first priority lien with the SPL Senior Secured Notes. The SPL Revolving Credit Facility contains customary contractual conditions for extensions of credit.

(2)The obligations under the CQP Revolving Credit Facility are jointly, severally and unconditionally guaranteed by Cheniere Energy Investments, LLC, SPLNG, CTPL, Sabine Pass LNG-GP, LLC, Sabine Pass Tug Services, LLC and Cheniere Pipeline GP Interests, LLC, each subsidiaries of CQP.

(3)The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by Cheniere CCH Holdco I, LLC, the direct parent company of CCH, of its limited liability company interests in CCH.

(4)The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on apari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.

(5)In August 2025, we entered into an amendment and restatement of the Cheniere Revolving Credit Facility, resulting in an extended maturity date, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

(6)The margins on the interest rate, the commitment fees and the letter of credit fees are subject to change based on the applicable entity’s credit rating. The interest rate and the commitment fees of the Cheniere Revolving Credit Facility are also based on the achievement of certain methane emissions management standards.

(7)The CCH Credit Facility matures the earlier of June 15, 2029 ortwo years after the substantial completion of the last Train of the Corpus Christi Stage 3 Project.

Restrictive Debt Covenants

The agreements governing our and our subsidiaries’ indebtedness contain customary terms and events of default and certain covenants that, among other things, may limit our and our subsidiaries’ ability to make certain investments or pay dividends or distributions. For example, SPL and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. Additionally, as described in Note 2—Summary of Significant Accounting Policies, our restricted cash and cash equivalents were primarily restricted for the payment of liabilities related to the Liquefaction Projects as required under certain debt arrangements. At December 31, 2025, our restricted net assets of consolidated subsidiaries, as imposed under certain debt agreements and certain other third party agreements, were approximately $407 million.

As of December 31, 2025, we were, and each of our subsidiaries was, in compliance with all covenants related to our respective debt agreements.

Interest Expense

Total interest expense, net of capitalized interest, consisted of the following (in millions):

Fair Value Disclosures

The following table shows the carrying amount and estimated fair value of our senior notes (in millions):

(1)Carrying amounts exclude unamortized discount and debt issuance costs.

(2)As of December 31, 2025 and 2024, $3.1 billion and $3.0 billion, respectively, of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of the fair value of our senior notes was classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

The estimated fair value of any outstanding borrowings under our credit facilities approximates the principal amount outstanding because the interest rates are indexed to market rates and the debt may be repaid, in full or in part, at any time without penalty.

NOTE 11—LEASES

We are the lessee of LNG vessels leased under time charters (“vessel charters”) as well as tug vessels, office space and facilities, land sites and equipment.

The following table shows the classification and location of our right-of-use assets and lease liabilities on our Consolidated Balance Sheets (in millions):

The following table shows the classification and location of our lease costs on our Consolidated Statements of Operations (in millions):

(1)Presented in the appropriate line item within operating costs and expenses, consistent with the nature of our use of the asset under lease.

Future annual minimum lease payments for operating and finance leases as of December 31, 2025 are as follows (in millions):

(1)Does not include approximately $4.3 billion of legally binding minimum payments for leases executed as of December 31, 2025 that will commence in future periods, consisting primarily of vessel charters, with fixed minimum lease terms of up to 15 years.

The following table shows the weighted-average remaining lease term and the weighted-average discount rate for our operating leases and finance leases:

(1)The weighted average discount rate is impacted by certain finance leases that commenced prior to the adoption of the current leasing standard under GAAP. In accordance with previous accounting guidance, the implied rate is based on the fair value of the underlying assets.

The following table includes other quantitative information for our operating and finance leases (in millions):

(1)Net of $33 million reclassified from operating leases to finance leases during the year ended December 31, 2024, as a result of modifications of the underlying tug vessel leases.

(2)Net of $15 million reclassified from finance leases to operating leases during the year ended December 31, 2024, as a result of modifications of the underlying tug vessel leases.

LNG Vessel Subleases

We sublease certain LNG vessels under charter to third parties while retaining our existing obligation to the original lessor. All of our sublease arrangements have been assessed as operating leases. The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):

As of December 31, 2025, the aggregate future annual minimum sublease payment to be received from LNG vessel subleases was $5 million and is expected to be received during the year ending December 31, 2026.

NOTE 12—REVENUES

The following table represents a disaggregation of revenue earned (in millions):

(1)Includes revenues from LNG vessel subcharters that do not qualify as leases for accounting purposes.

LNG Revenues

We have numerous SPAs with third party customers for the sale of LNG on an FOB basis or a DAP basis. Our customers generally purchase LNG for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The fixed fee component is the amount payable to us regardless of a cancellation or suspension of LNG cargo deliveries by the customers. The variable fee component is the amount generally payable to us only upon delivery of LNG plus all future adjustments to the fixed fee for inflation. The SPAs and contracted volumes to be made available under the SPAs are not tied to a specific Train.

We intend to primarily use LNG sourced from our Sabine Pass LNG Terminal or our Corpus Christi LNG Terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $226 million, $280 million and $359 million for the years ended December 31, 2025, 2024 and 2023, respectively.

Regasification Revenues

The Sabine Pass LNG Terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 1 Bcf/d of the regasification capacity at the Sabine Pass LNG Terminal has been reserved under a long-term TUA with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”) under which they are required to pay fixed monthly fees to SPLNG, regardless of their use of the LNG terminal. The aggregate annual payment of approximately $125 million (indexed for inflation) they are required to pay under the 20 year contract that commenced in 2009 represents fixed consideration. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Approximately 2 Bcf/d of regasification capacity of the Sabine Pass LNG Terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

In 2012, SPL entered into a partial TUA assignment agreement with TotalEnergies, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit SPL to more flexibly manage its LNG storage capacity. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred to TotalEnergies are recognized in operating and maintenance expense. During the years ended December 31, 2025, 2024 and 2023, SPL recorded $134 million, $133 million and $132 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Contract Assets and Liabilities

The following table shows our contract assets, net of current expected credit losses, which are included in other current assets, net and other non-current assets, net on our Consolidated Balance Sheets (in millions):

Contract assets include our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due and have primarily arisen from certain SPAs that have tiered payment structures.

The following table reflects the changes in our contract liabilities, which are included in deferred revenue and other non-current liabilities on our Consolidated Balance Sheets (in millions):

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. The change in deferred revenue between the years ended December 31, 2025 and 2024 is primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

Because many of our sales contracts have long-term durations, we are contractually entitled to significant future consideration, which we have not yet recognized as revenue. The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:

(1)The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

The following potential future sources of revenue are omitted from the table above under exemptions we have elected: (1) all performance obligations that are part of a contract that has an original expected duration of one year or less and (2) substantially all variable consideration under our SPAs and TUAs that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price, and allocable to wholly unsatisfied future performance obligations or otherwise constrained, will vary based on (1) the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, (2) adjustments to the consumer price index and (3) the outcome of certain contingent events, including the achievement of milestones upon which delivery of LNG under certain contracts is conditioned.

The following table summarizes the percentage of variable consideration earned under contracts with customers included in the table above:

NOTE 13—RELATED PARTY TRANSACTIONS

Below is a summary of our related party transactions, all in the ordinary course of business, as reported on our Consolidated Statements of Operations (in millions):

(1)On February 13, 2025, we sold all of our equity interests in one of our equity method investments to a third party. Additionally, we assigned certain operating and construction management agreements to the purchaser of such interests. Included in the table above are $1 million, $9 million and $10 million of other revenues and $1 million, $8 million and $9 million of operating and maintenance expense from the investee during the years ended December 31, 2025, 2024 and 2023, respectively.

(2)These arrangements were with a party that was related to the entity that indirectly owns a portion of CQP’s limited partner interests. Due to the sale of such interests by that entity effective May 13, 2025, this party is no longer considered a related party as of that date.

Below is a summary of our related party balances, all in the ordinary course of business, as reported on our Consolidated Balance Sheets (in millions):

NOTE 14—INCOME TAXES

The jurisdictional components of income before income taxes and non-controlling interests on our Consolidated Statements of Operations are as follows (in millions):

Income tax provision included in our reported net income consisted of the following (in millions):

The table below provides the updated requirements of ASU No. 2023-09 for 2025. See Note 2—Summary of Significant Accounting Policies for additional details on the adoption of ASU No. 2023-09.

Our income tax rates do not bear a customary relationship to statutory income tax rates. A reconciliation of the U.S. federal statutory income tax rate of 21% to our effective income tax rate for the year ended December 31, 2025 is as follows:

(1)State taxes in Louisiana and Texas contributed to the majority of the tax effect in this category.

(2)The percentages in the table may not recalculate exactly due to rounding as the percentages are calculated based on whole numbers, not the rounded numbers presented.

As previously disclosed for the years ended December 31, 2024 and 2023, prior to the adoption of ASU 2023-09, a reconciliation of the U.S. federal statutory income tax rate of 21% to our effective income tax rate was as follows:

Significant components of our deferred tax assets and liabilities are as follows (in millions):

(1)Valuation allowance primarily relates to a valuation allowance recorded on U.S. federal capital loss carryforwards and state NOL carryforwards and increased by $60 million during the year ended December 31, 2025 primarily due to a capital loss carryforward generated in the current year that we do not expect to realize before expiration. The valuation allowance decreased by $37 million during the year ended December 31, 2024 and increased by $4 million during the year ended December 31, 2023.

NOL and tax credit carryforwards

As of December 31, 2025, we had U.S. federal and state NOL carryforwards of approximately $1.2 billion and $2.2 billion, respectively. All of our NOLs have an indefinite carryforward period.

As of December 31, 2025, our other tax credits expire between 2028 and 2035.

Our NOL and tax credit carryforwards are not subject to, nor impacted by, any prior tax ownership change. We continue to monitor public trading activity in our shares to identify potential tax ownership changes that could impact our timing and ability to utilize such attributes.

Tax Law Changes

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law with significant changes to the Internal Revenue Code that impact us, including, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025 and modifying the export-promoting Foreign Derived Intangible Income (“FDII”) deduction rules, renamed to the Foreign Derived Deduction Eligible Income(“FDDEI”) under the OBBBA beginning in 2026.

The legislation did not have a material impact on our income tax expense for the year ended December 31, 2025, and it did not materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA deferred our tax liability, ultimately reducing our 2025 income taxes payable to a nominal amount, primarily due to the accelerated tax deduction on qualifying Corpus Christi Stage 3 Project assets.

On September 30, 2025, the Internal Revenue Service issued Notice 2025-49, which includes, among other provisions, revised interim rules for calculating CAMT adjusted financial statement income, including rules allowing us to utilize and benefit from our existing net operating loss carryovers for both CAMT and regular tax in the same period. As a result, our cash tax obligations have been deferred, and we received a refund of $380 million of previously paid CAMT in December 2025.

Unrecognized Tax Benefits

As of December 31, 2025, 2024 and 2023, there were $63 million, $65 million and $66 million, respectively, of unrecognized tax benefits that, if recognized, would affect our effective tax rate in future periods. Interest and penalties related to income tax matters are recognized as part of income tax provision. Interest and penalties recognized as part of income tax provision was $6 million, $6 million and $4 million for the years ended December 31, 2025, 2024 and 2023, respectively, and cumulative accrued interest was $15 million and $10 million as of December 31, 2025 and 2024, respectively.

We are subject to tax in the U.S. and various state and foreign jurisdictions, and we are subject to periodic audits and reviews by taxing authorities. Federal tax returns for the years after 2017, United Kingdom tax returns for the years after 2020, Louisiana tax returns for the years after 2021 and Texas tax returns for the years after 2020 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

A reconciliation of the beginning and ending amounts of our unrecognized tax benefits is as follows (in millions):

The following is a supplemental schedule of cash paid for income taxes, net of refunds, for the year ended December 31, 2025 (in millions):

We received an aggregate of $92 million in income tax refunds, net of payments, during the year December 31, 2024 and we made an aggregate of $117 million in income tax payments, net of refunds, during the year ended December 31, 2023.

NOTE 15—SHARE-BASED COMPENSATION

Our Amended and Restated 2020 Incentive Plan (the“2020 Plan”) is a broad-based incentive plan which allows for the issuance of stock options and stock appreciation rights and awards of bonus stock, phantom stock, restricted stock, restricted stock units and performance awards and other stock-based awards to employees, consultants and non-employee directors. The 2020 Plan provides for the issuance of 12.5 million shares of our common stock, of which we had 7.5 million shares available for future issuance as of December 31, 2025. Our outstanding awards as of December 31, 2025 primarily consisted of restricted stock units (“RSUs”) and performance stock units (“PSUs”). Other outstanding awards were not material to our Consolidated Financial Statements.

Restricted Stock Units

RSUs are stock awards that contain a graded vesting period of up tothree years and, with the exception of awards to certain officers which contain a cash settlement option, as described in Liability-Classified Awards below, will settle in stock upon vesting subject to restrictions on transfer and to a risk of forfeiture if the recipient terminates employment with us prior to the lapse of the restrictions.

Performance Stock Units

PSUs provide for cliff vesting after a period of approximately three years with payouts dependent upon the achievement of metrics compared to pre-established performance targets over the defined performance period, including a performance condition consisting of cumulative distributable cash flow per share, and in certain circumstances, a market condition consisting of absolute total shareholder return (“ATSR”) of our common stock. All PSUs will settle in stock, with the exception of awards to certain officers which contain cash settlement features, either as granted or modified, as described in Liability-Classified Awards below.

Compensation cost attributed to the performance metric will vary due to changing estimates of units to be earned, based on expected achievement of the performance metric. The number of units that may be earned at the end of the vesting period ranges from 0% up to 300% of the target award amount.

Liability-Classified Awards

RSUs and PSUs granted to certain officers may be, as granted or modified, settled in cash in lieu of shares at the option of the officer following approval by the Compensation Committee, in order to limit the dilution from equity grants consistent with our share repurchase program under our long-term capital allocation plan, provided that we have sufficient liquidity to do so and the officers maintain certain stock ownership requirements. Except for those awards which contain a cash settlement option, PSUs granted to certain officers contain a cash settlement cap of $3 million.

During the years ended December 31, 2025, 2024 and 2023, we paid $108 million, $109 million and $84 million, respectively, in cash upon vesting of the liability-classified awards.

Total share-based compensation costs, net of forfeitures, consisted of the following (in millions):

The table below provides a summary of activity related to our RSUs and PSUs (in millions, except for per unit information):

(1)The Equity Awards column for PSUs includes 0.1 million PSUs granted in 2025 to certain officers containing a cash settlement cap of $3 million.

(2)Represents incremental units recognized as a result of final performance measures or changes in estimated measures. As of December 31, 2025, there were 0.1 million PSUs that would be issued if the maximum level of performance under the target awards amount is achieved.

(3)During the years ended December 31, 2025, 2024 and 2023, we recognized $5 million, $14 million and $86 million, respectively, in incremental expense as a result of significant modifications involving reclassification between equity awards and liability awards, attributable tosix, seven andsix employees, respectively.

(4)The total fair value of RSUs and PSUs vested was $175 million and $107 million, respectively, for the year ended December 31, 2025.

The table below provides the assumptions used in estimating the fair value of unvested awards containing market conditions as of the end of the respective periods, and for which the performance period had not yet ended:

(1)The performance stock units are entitled to dividend equivalents during the performance period. Therefore, when calculating simulated returns, we applied an annual dividend yield ofzero percent.

(2)Represents the range associated with individual vesting years. As of December 31, 2025, the risk-free interest rate is consistent across the individual vesting years and as such, no range is presented.

(3)The expected volatility is based on historical and implied volatilities of our common stock price.

The total unrecognized compensation cost at December 31, 2025 relating to non-vested share-based compensation arrangements was $168 million, which is expected to be recognized over a weighted average period of 1.4 years.

NOTE 16—EMPLOYEE BENEFIT PLAN

We have a defined contribution plan (“401(k) Plan”) which allows eligible employees to contribute up to 75% of their compensation up to the Internal Revenue Service maximum. We match each employee’s deferrals (contributions) up to 6% of compensation and may make additional contributions at our discretion. Employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $20 million, $18 million and $17 million for the years ended December 31, 2025, 2024 and 2023, respectively. We have madeno discretionary contributions to the 401(k) Plan to date.

NOTE 17—NET INCOME PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

We utilize the two-class method for computing earnings per share, which requires an allocation of earnings as if all earnings were distributed during the period to the common stockholders and participating securities. The redeemable NCI held by a third party in one of our consolidated VIEs is considered participating because, under certain circumstances, it is redeemable for cash at a return. Therefore, the accretion of the redeemable NCI to its redemption value, net of tax, which is recognized as a deemed dividend within retained earnings, is deducted from net income in computing net income per share attributable to common stockholders. In January 2026, we redeemed the remaining redeemable NCI in our consolidated VIE that owns the Gregory Power Plant, a natural gas-fired combined cycle facility located immediately proximal to the Corpus Christi LNG Terminal, at a price that approximated our carrying value.

The following table provides a reconciliation of net income attributable to common stockholders and basic and diluted weighted average common shares outstanding (in millions, except per share data):

(1)Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

On January 27, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on February 27, 2026 to stockholders of record as of the close of business on February 6, 2026.

NOTE 18—SHARE REPURCHASE PROGRAMS

The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

(1)Amount excludes associated commission fees and excise taxes incurred, which are excluded costs under the repurchase program.

As of December 31, 2025, we had approximately $1.2 billion remaining under our share repurchase program. Subsequently, in February 2026, our Board approved an increase in our share repurchase authorization to approximately $10 billion from 2026 through 2030 with a $9 billion increase to the existing authorization. Under the share repurchase authorization, repurchases can be made from time to time using a variety of methods, which may include open market purchases, privately negotiated transactions or otherwise, all in accordance with the rules of the Securities and Exchange Commission and other applicable legal requirements. The timing and amount of any shares of Cheniere’s common stock that are repurchased under the share repurchase authorization will be determined by Cheniere’s management based on market conditions and other factors. The share repurchase authorization does not obligate Cheniere to acquire any particular amount of common stock, and may be modified, suspended or discontinued at any time or from time to time at Cheniere’s discretion.

NOTE 19—COMMITMENTS AND CONTINGENCIES

Commitments

We have various future contractual commitments which do not meet the definition of a liability as of December 31, 2025 and thus are not recognized as liabilities in our Consolidated Financial Statements. Executed contracts containing such future commitments include agreements for capital expenditures, the use of LNG vessels contracted for future delivery, natural gas transportation and storage services, goods and services necessary to operate our Liquefaction Projects and letters of credit.

CCL has contractual commitments under lump sum turnkey contracts with Bechtel for the engineering, procurement and construction of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project. The total contract price of the EPC contracts, inclusive of amounts incurred under change orders, for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project were approximately $6.0 billion and $2.9 billion, respectively, of which we had remaining obligations of approximately $0.7 billion and $1.6 billion, respectively, as of December 31, 2025.

Environmental and Regulatory Matters

Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. Failure to comply with such laws could result in legal proceedings, which may include substantial penalties. We believe that, based on currently known information, compliance with these laws and regulations will not have a material adverse effect on our results of operations, financial condition or cash flows.

We are, and may in the future be, involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. We recognize legal costs in connection with legal and regulatory matters as they are incurred. While the results of these litigation matters and claims cannot be predicted with certainty, we believe the reasonably possible losses from such matters, individually and in the aggregate, are not material. Additionally, we believe the probable final outcome of such matters will not have a material impact on our operating results, financial position or cash flows.

NOTE 20—SEGMENT INFORMATION AND CUSTOMER CONCENTRATION

We have determined that we operate as a single operating and reportable segment. Our executive team is organized by function, rather than legal entity or discrete financial data oversight, with no business component managers reporting to the chief operating decision maker (“CODM”), who is our president and chief executive officer. The CODM regularly analyzes financial and operational data on a single basis of segmentation at the consolidated level, consistent with our integrated service offering, in order to allocate resources and assess performance.

The measure of profit and loss regularly provided to the CODM that is most consistent with GAAP is net income attributable to Cheniere, as presented in our Consolidated Statements of Operations. This measure contributes to the CODM’s assessment of performance and resource allocation, which includes monitoring of budget versus actual results, establishing compensation and deciding on capital allocation priorities. Significant expenses regularly provided to the CODM, and included in the measure of profit and loss, are cost of sales, operating and maintenance expense and selling, general and administrative expense, as reported in our Consolidated Statements of Operations. Also provided regularly to the CODM are changes in the fair value of our derivative instruments, which are inclusive of significant noncash items, which were $3.6 billion, $1.3 billion and $8.0 billion in gains for the years ended December 31, 2025, 2024 and 2023. Interest income, which is included in interest and dividend income on our Consolidated Statements of Operations, was $102 million, $188 million and $206 million for the years ended December 31, 2025, 2024 and 2023.

The measure of segment assets is reported on our Consolidated Balance Sheets as total assets. Substantially all of our tangible long-lived assets, which consist of property, plant and equipment, are located in the U.S. Total expenditures for additions to long-lived assets is reported on our Consolidated Statements of Cash Flows.

For the years ended December 31, 2025, 2024 and 2023, we hadno customers with revenues that were 10% or more of total revenues from contracts with external customers. We hadone customer with a balance of 10% or more of trade receivables and contract assets, both net of current expected credit losses, representing 15% and 21% of total trade receivables and contract assets, both net of current expected credit losses, as of December 31, 2025 and 2024. Customers under common control are considered to be a single customer.

The following table shows total revenues from contracts with external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues to the country in which the party to the applicable agreement has its principal place of business, with foreign countries that individually accounted for 10% or more of total revenues from contracts with external customers shown separately from the remaining countries. Revenues attributed to foreign countries exclude certain sales and other operating revenues for which attribution to a specific country is not practicable.

NOTE 21—SUPPLEMENTAL CASH FLOW INFORMATION

The following table provides supplemental disclosure of substantive cash flow information (in millions):

(1)Reflects unpaid portion, as of the end of each period, of assets and liabilities recognized during the respective periods.

(2)Net of proceeds not yet collected from commissioning sales of LNG of $13 million, zero andzero, respectively.

See Note 11—Leases and Note 14—Income Taxes for supplemental cash flow information related to our leases and income taxes, respectively.