Cheniere Energy, Inc.: Form 10-Q for the period ended Mar 31, 2026

Information Regarding Forward-Looking Statements

This quarterly report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical or present facts or conditions, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

• statements that we expect to commence or complete construction of our proposed LNG terminals, liquefaction facilities, pipeline facilities or other projects, or any expansions or portions thereof, by certain dates, or at all;
• statements regarding future levels of domestic and international natural gas production, supply or consumption or future levels of LNG imports into or exports from North America and other countries worldwide or purchases of natural gas, regardless of the source of such information, or the transportation or other infrastructure or demand for and prices related to natural gas, LNG or other hydrocarbon products;
• statements regarding any financing transactions or arrangements, or our ability to enter into such transactions;
• statements relating to Cheniere’s capital deployment, including intent, ability, extent and timing of capital expenditures, debt repayment, dividends, share repurchases and execution on the capital allocation plan;
• statements regarding our future sources of liquidity and cash requirements;
• statements relating to the construction of our Trains and pipelines, including statements concerning the engagement of any EPC contractor or other contractor and the anticipated terms and provisions of any agreement with any EPC or other contractor, and anticipated costs related thereto;
• statements regarding any SPA or other agreement to be entered into or performed substantially in the future, including any revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, natural gas liquefaction or storage capacities that are, or may become, subject to contracts;
• statements regarding counterparties to our commercial contracts, construction contracts and other contracts;
• statements regarding our planned development and construction of additional Trains or pipelines, including the financing of such Trains or pipelines;
• statements that our Trains, when completed, will have certain characteristics, including amounts of liquefaction capacities;
• statements regarding our business strategy, our strengths, our business and operation plans or any other plans, forecasts, projections, or objectives, including anticipated revenues, capital expenditures, maintenance and operating costs and cash flows, any or all of which are subject to change;
• statements relating to our goals, commitments and strategies in relation to environmental matters;
• statements regarding legislative, governmental, regulatory, administrative or other public body actions, approvals, requirements, permits, applications, filings, investigations, proceedings or decisions;
• statements regarding our anticipated LNG and natural gas marketing activities; and
• any other statements that relate to non-historical or future information.

All of these types of statements, other than statements of historical or present facts or conditions, are forward-looking statements. In some cases, forward-looking statements can be identified by terminology such as “may,” “will,” “could,” “should,” “achieve,” “anticipate,” “believe,” “contemplate,” “continue,” “estimate,” “expect,” “intend,” “plan,” “potential,” “predict,” “project,” “pursue,” “target,” the negative of such terms or other comparable terminology. The forward-looking statements contained in this quarterly report are largely based on our expectations, which reflect estimates and assumptions made by our management. These estimates and assumptions reflect our best judgment based on currently known market conditions and other factors. Although we believe that such estimates are reasonable, they are inherently uncertain and involve a number of risks and uncertainties beyond our control. In addition, assumptions may prove to be inaccurate. We caution that the forward-looking statements contained in this quarterly report are not guarantees of future performance and that such statements may not be realized or the forward-looking statements or events may not occur. Actual results may differ materially from those anticipated or implied in forward-looking statements as a result of a variety of factors described in this quarterly report and in the other reports and other information that we file with the SEC, including those discussed under “Risk Factors” in our annual report on Form 10-K for the fiscal year ended December 31, 2025. All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors. These forward-looking statements speak only as of the date made, and other than as required by law, we undertake no obligation to update or revise any forward-looking statement or provide reasons why actual results may differ, whether as a result of new information, future events or otherwise.

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes. This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future.

Our discussion and analysis includes the following subjects:

• Overview
• Overview of Significant Events
• Results of Operations
• Liquidity and Capital Resources
• Summary of Critical Accounting Estimates
• Recent Accounting Standards

Overview

Cheniere, a Delaware corporation, is a Houston-based energy infrastructure company primarily engaged in LNG-related businesses. We provide clean, secure and affordable LNG to integrated energy companies, utilities and energy trading companies around the world. We aspire to conduct our business in a safe and responsible manner, delivering a reliable, competitive and integrated source of LNG to our customers.

LNG is natural gas (primarily methane) in liquid form and is a cleaner dispatchable fuel for power generation. The LNG we produce is shipped all over the world, converted back into natural gas (called “regasification”) and then transported via pipeline to homes and businesses and used as an energy source that is essential for heating, cooking and other industrial uses.

As of March 31, 2026, we were the largest producer of LNG in the U.S. and the second largest LNG operator globally, based on the total production capacity of our natural gas liquefaction facilities. Our total production capacity is expected to be over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which approximately 8 mtpa was under construction and the remainder was in operation as of March 31, 2026, comprised of the following:

• over 30 mtpa of total production capacity in operation from natural gas liquefaction facilities located in Cameron Parish, Louisiana at Sabine Pass (the “SPL Project”). We own and operate the SPL Project and export facility (the “Sabine Pass LNG Terminal”), one of the largest LNG production facilities in the world, through our ownership interest in and management agreements with CQP, which is a publicly traded limited partnership. As of March 31, 2026, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP. The Sabine Pass LNG Terminal also has five LNG storage tanks with aggregate capacity of approximately 17 Bcfe and vaporizers with regasification capacity of approximately 4 Bcf/d, as well as three marine berths, two of which can accommodate vessels with nominal capacity of up to 266,000 cubic meters and the third berth, which can accommodate vessels with nominal capacity of up to 200,000 cubic meters. We also own and operate through CQP 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”).
• over 30 mtpa of total expected production capacity, inclusive of estimated debottlenecking opportunities, including approximately 8 mtpa under construction and the remainder in operation as of March 31, 2026, from our natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”), of which we have 100% ownership interest. The Corpus Christi LNG Terminal also has three LNG storage tanks with aggregate capacity of approximately 10 Bcfe and two marine berths that can each accommodate vessels with nominal capacity of up to 266,000 cubic meters. We also own and operate through CCP 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 of seven 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 approximately 3 mtpa under construction and the remainder in operation from the first five midscale Trains that have reached substantial completion as of March 31, 2026; and
• a project consisting of two 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 March 31, 2026.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows, and include SPAs, in which our customers are generally required to pay a fixed fee with respect to the contracted volumes irrespective of their election to cancel or suspend deliveries of LNG cargoes, and long-term IPM agreements, in which a gas producer sells natural gas to us on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs. The SPAs also have a variable fee component, which is primarily indexed to Henry Hub and generally structured to cover the cost of natural gas purchases, transportation and liquefaction fuel consumed to produce LNG. Since we procure most of our feedstock for LNG production from the U.S., the structure of these contracts helps limit our exposure to fluctuations in U.S. natural gas prices. Through our SPAs and long-term IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of March 31, 2026, we have contracted approximately 90% of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes from SPAs that are conditional on additional liquefaction capacity beyond what is currently in construction or operation, subject to unilateral waiver by us. LNG produced by the Liquefaction Projects that is not contracted under long-term contracts is available for Cheniere Marketing, our integrated marketing function, to sell in the global market under spot sales or other short-term agreements.

Disciplined Accretive Growth

We remain focused on safety, operational excellence and customer satisfaction. Increasing demand for LNG has allowed us to expand our liquefaction infrastructure in a financially disciplined manner. Our capital allocation plan is designed, in part, to invest in financially disciplined growth accretive to our common stock. Capital investment parameters are the foundation of our disciplined, accretive growth, and include consideration to:

• Achieve value accretive returns through long-term commercial contracts: We aim to contract approximately 90% of our current and planned liquefaction capacity under long-term SPAs and long-term IPM agreements with creditworthy counterparties under the pricing structures described above, with financial parameters that consider, among other things, targeted unlevered returns that exceed our cost of equity and return on stock at prevailing stock prices and project leverage. Our success in securing long-term commercial contracts at desired returns is influenced by global LNG and natural gas market conditions and other uncertainties described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.
• Achieve credit accretive returns: We aim to conservatively fund our projects through financing structures that sustain our long-term, run-rate leverage and credit metrics. Our ability to secure the required financing is influenced by market interest rates and other factors described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

We have increased available liquefaction capacity at our Liquefaction Projects as a result of debottlenecking and other optimization projects. We believe these factors provide a foundation for additional growth in our portfolio of customer contracts in the future. We hold significant land positions at both the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, which provide opportunity for further liquefaction capacity expansion. We are developing a two-phased expansion adjacent to the SPL Project, inclusive of three liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”) and a further expansion of the CCL Project in a phased approach, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities (the “CCL Expansion Project”). These projects and any future expansions at our sites require, among other things, regulatory approvals and acceptable commercial and financing arrangements before we make a positive FID. Risks associated with cost overruns and delays in the completion of our expansion projects are described in the risk factors of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL Expansion Project and the CCL Expansion Project:

ü indicates receipt of authorization, subject to ongoing conditionality

(1) Anticipated based on capacity, scale, location and infrastructure. Subject to regulatory review and approval and may change based on design considerations, engagement with contractors and other factors. Subject to adjustment for planned maintenance, production reliability, potential overdesign and debottlenecking opportunities.

(2) Our activities, including our expansion activities, are highly regulated and require regulatory approvals at various stages, including approvals of the FERC and DOE under Sections 3 and 7 of the NGA, as well as several other material governmental and regulatory approvals and permits. The progression of our expansion projects is dependent on receiving all regulatory approvals required within the respective stages. See our annual report on Form 10-K for the fiscal year ended December 31, 2025 for further discussion of the regulations under federal, state and local statutes, rules, regulations and laws to which we are subject and associated risk factors relating to regulations.

(3) We anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of this expansion project if we reach a positive FID.

(4) Liquefaction capacity partially contracted by Cheniere Marketing, through SPAs that are conditioned on additional liquefaction capacity beyond what is currently in construction or operation and may be available to be novated to SPL or CCL, and by SPL Stage V, through an IPM agreement.

(5) Expected to be subject to phased FID. Any positive FID is subject to achievement of or consideration to relevant milestones and capital investment parameters described herein.

Overview of Significant Events

Our significant events since January 1, 2026 and through the filing date of this Form 10-Q include the following:

Strategic

Growth

• Following our pre-filing in July 2025, in February 2026, we filed an application with the FERC under the NGA for authorization to site, construct and operate in a phased approach the CCL Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal, inclusive of four liquefaction trains and supporting infrastructure, with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.

Commercialization

• In February 2026, we announced the execution of our second long-term LNG SPA between Cheniere Marketing and CPC Corporation, Taiwan (“CPC”), under which CPC has agreed to purchase up to approximately 1.2 mtpa of LNG from Cheniere Marketing on a DAP basis from 2026 through 2050.

Operational

• As of May 1, 2026, over 4,760 cumulative LNG cargoes totaling over 325 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
• In March 2026, substantial completion of Train 5 of the Corpus Christi Stage 3 Project was achieved.

Financial

• In March 2026, Cheniere issued and sold $1.0 billion aggregate principal amount of 5.200% Senior Notes due 2036 and $750 million aggregate principal amount of 6.000% Senior Notes due 2056, and a portion of the net proceeds was used to prepay $550 million of CCH’s outstanding borrowings under the CCH Credit Facility. Concurrently, we canceled $600 million of unused commitments under the CCH Credit Facility.
• In February 2026, Moody’s Ratings (“Moody’s”) upgraded its rating of Cheniere’s senior unsecured notes from Baa3 to Baa2 with a stable outlook. Moody’s also upgraded their rating of CCH’s senior secured notes from Baa2 to Baa1 with a stable outlook.
• In February 2026, our board of directors (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.
• During the three months ended March 31, 2026, we accomplished the following pursuant to our capital allocation priorities:
• We repurchased approximately 2.7 million shares of our common stock as part of our share repurchase program for approximately $537 million.
• SPL redeemed or repaid $253 million aggregate principal amount of notes across its complex.
• We paid a dividend of $0.555 per share of common stock during the three months ended March 31, 2026.
• We continued to invest in accretive organic growth, including our investments in the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Results of Operations

Consolidated results of operations

(in millions, except per share data)

Volumes loaded and recognized from the Liquefaction Projects

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Components of LNG revenues and corresponding LNG volumes delivered

(1) Long-term agreements include agreements with an initial tenor of 12 months or more.

(2) Includes volumes sold under short-term agreements and volumes sold from natural gas procured under long-term IPM agreements.

Net income (loss) attributable to Cheniere

Net income (loss) attributable to Cheniere declined by $3.9 billion during the three months ended March 31, 2026 as compared to the same period of 2025, primarily due to $4.8 billion of unfavorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely associated with our long-term IPM agreements. These increased losses were primarily attributable to widening spreads between global and U.S. domestic natural gas benchmarks and elevated global natural gas price volatility influenced in part by the tightening supply conditions, transit constraints and heightened geopolitical uncertainties from the conflict and instabilities across parts of the Middle East during 2026. Partially offsetting these losses was $462 million of favorable change in income tax provision (benefit), the recognition of $370 million in tax credits and a $225 million decrease in net income attributable to NCI.

Our operating results, excluding these items discussed above, were favorable during the three months ended March 31, 2026 as compared to the same period of 2025 due to higher total margins primarily from higher volumes delivered, which increased by 66 TBtu, largely due to the first four Trains of the Corpus Christi Stage 3 Project in operation throughout the three months ended March 31, 2026 as compared to the first Train of the Corpus Christi Stage 3 Project in operation for only half a month during the same period in 2025 and from contributions from optimization activities, and to a lesser degree from the relative portion of our cargoes sold that is subject to global LNG pricing.

Continued tightening of global natural gas and LNG supply conditions, including upstream production constraints, liquefaction capacity limitations and shipping and transit disruptions in the Middle East, together with heightened geopolitical uncertainties in key producing and consuming regions, may result in sustained volatility in global natural gas and LNG prices. Such volatility, along with fluctuations in regional price differentials, could materially impact our results of operations, cash flows and financial condition, particularly from LNG sales under spot or short-term agreements indexed to global prices. Additionally, the potential impacts of sustained volatility in global natural gas and LNG prices may also affect the fair value of our agreements accounted for as derivatives, particularly those indexed to global natural gas benchmarks.

The following is an expanded discussion of the material drivers of the variance in net income (loss) attributable to Cheniere:

Revenues

The $424 million increase in total revenues during the three months ended March 31, 2026 as compared to the same period of 2025 was primarily attributable to:

• 1.3 billion increase primarily due to higher pricing per MMBtu from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed, as well as higher volumes of LNG delivered as LNG revenues between the periods; partially offset by:
• $952 million of unfavorable changes in the fair value of agreements accounted for as derivative instruments included in revenues, as further described above under the caption Net income (loss) attributable to Cheniere.

Operating costs and expenses

The $4.9 billion increase in total operating costs and expenses during the three months ended March 31, 2026 as compared to the same period of 2025 was primarily attributable to:

• $4.2 billion of unfavorable changes in the fair value of agreements accounted for as derivative instruments included in cost of sales indexed to global natural gas and LNG prices, primarily related to our long-term IPM agreements, as further described above under the caption Net income (loss) attributable to Cheniere, partially offset by a $316 million favorable change in the fair value of other agreements accounted for as derivative instruments included in cost of sales, largely due to changes in market-based locational forward price differentials for North American natural gas deliveries;
• $1.2 billion increase in the cost of natural gas feedstock, largely due to the increase in U.S. natural gas prices and increased volume of LNG delivered; partially offset by:
• $370 million reduction to cost of sales from the recognition of tax credits during the three months ended March 31, 2026, as further discussed in the Liquidity and Capital Resources section of our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Income tax provision (benefit)

The $462 million of favorable variance in income tax provision (benefit) during the three months ended March 31, 2026 as compared to the same period of 2025 was primarily attributable to a lower income tax expense due to a $4.5 billion decrease in pre-tax income (loss) as well as the change in our effective tax rate, as further described below.

Our effective tax rate was 9.1% and 15.3% during the three months ended March 31, 2026 and 2025, respectively, due to a decline in our pre-tax income (loss) and the proportion of such pre-tax income attributable to CQP, which is partially not taxable to us. The effective tax rate for each of the comparable three month periods were lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

Net income attributable to NCI

The $225 million decrease in net income attributable to NCI during the three months ended March 31, 2026 as compared to the same period of 2025 was primarily attributable to a $455 million decrease in CQP’s consolidated net income primarily from unfavorable changes in the fair value of agreements accounted for as derivative instruments.

Significant factors affecting our results of operations

Below are significant factors that affect our results of operations.

Gains and losses on derivative instruments

Derivative instruments, which we use to manage certain risks, are reported at fair value in our Consolidated Financial Statements, unless they satisfy criteria for, and we elect, the normal purchases and normal sales exception which applies the accrual method of accounting. For commodity derivative instruments, including those related to our long-term IPM agreements, the underlying LNG sales being economically hedged are accounted for under the accrual method of accounting, whereby revenues expected to be derived from the future LNG sales are recognized only upon delivery or realization of the underlying transaction. Notwithstanding the operational intent to mitigate risk exposure over time, the recognition of derivative instruments at fair value has the effect of recognizing gains or losses relating to future period exposure, and given the significant volumes, long-term duration and volatility in price basis for certain of our derivative contracts, the use of derivative instruments may result in continued volatility of our results of operations based on changes in market pricing, counterparty credit risk and other relevant factors that may be outside of our control. For example, as described in Note 5—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of the Liquefaction Supply Derivatives incorporates, as applicable, market participant-based assumptions pertaining to certain contractual uncertainties, including those related to the availability of market information for delivery points, which may require future development of infrastructure, 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.

Commissioning volumes

Prior to substantial completion of a Train, amounts received from the sale of commissioning volumes from that Train are offset against LNG terminal construction-in-process, because these amounts are earned or loaded during the testing phase for the construction of that Train and are necessary activities to bring the asset to the condition for its intended use. During the three months ended March 31, 2026 and 2025, we realized offsets to LNG terminal costs of $47 million corresponding to 6 TBtu of LNG and $48 million corresponding to 5 TBtu of LNG, respectively, that was related to the sale of commissioning volumes associated with the Corpus Christi Stage 3 Project.

Additional liquefaction capacities

The Corpus Christi Stage 3 Project and CCL Midscale Trains 8 & 9 Project are currently under construction and are expected to add over 15 mtpa of operational liquefaction capacity, inclusive of estimated debottlenecking opportunities, once all Trains reach substantial completion, of which approximately 8 mtpa is still under construction as of March 31, 2026. As of March 31, 2026, the first five Trains of the Corpus Christi Stage 3 Project were in operation, while as of March 31, 2025, only the first Train of the Corpus Christi Stage 3 Project was in operation. The operation and maintenance of these Trains and increased LNG volumes produced are expected to result in higher revenues and operating costs and expenses. However, prior to the commencement of long-term SPAs associated with these volumes, the additional volumes will be sold by our integrated marketing function at prevailing market prices. Additionally, potential expansion projects that increase the amount of LNG volumes produced, including those discussed above in Disciplined Accretive Growth, would also be expected to result in higher revenues and operating costs and expenses.

Business Seasonality

Our quarterly results are affected by production levels, timing of our maintenance activities and the resulting availability of volumes. Therefore, operating profit may not be generated evenly throughout the year. Weather variations, including temperature, have an impact on LNG output at our Liquefaction Projects. Our Liquefaction Projects are capable of relatively higher production volumes during the cooler months as compared to the summer months. We typically perform our scheduled major maintenance activities at our sites during shoulder months in the second and third quarters in order to mitigate the impact to our annual operating results.

Liquidity and Capital Resources

The following information describes our ability to generate and obtain adequate amounts of cash to meet our requirements in the short term and the long term. In the short term, we expect to meet our cash requirements using operating cash flows and available liquidity, consisting of cash and cash equivalents, restricted cash and cash equivalents and available commitments under our credit facilities. Additionally, we expect to meet our long term cash requirements by using operating cash flows and other future potential sources of liquidity, which may include debt and equity offerings by us or our subsidiaries.

The table below provides a summary of our available liquidity (in millions). Future material sources of liquidity are discussed below.

(1) Amounts presented include $279 million of cash and cash equivalents and $22 million of restricted cash and cash equivalents held by our consolidated VIE, all of which were related to CQP, as discussed in Note 6—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements.

(2) Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of March 31, 2026. See Note 8—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to March 31, 2026 will be driven by future sources of liquidity and future cash requirements. For a discussion of our future sources and uses of liquidity, see the liquidity and capital resources disclosures in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Although our sources and uses of cash are presented below from a consolidated standpoint, SPL, CQP, CCH and Cheniere operate with independent capital structures. Certain restrictions or requirements under debt and equity instruments executed by our subsidiaries limit the entity’s use of cash, including the following:

• SPL and CCH are required to deposit all cash received into restricted cash and cash equivalents accounts under certain of their debt agreements. The usage or withdrawal of such cash is restricted to the payment of liabilities related to the Liquefaction Projects and other restricted payments. In addition, SPL and CCH’s operating costs are managed by our subsidiaries under affiliate agreements, which may require SPL and CCH to advance cash to the respective affiliates, however the cash remains restricted for operation and construction of the Liquefaction Projects;
• CQP is required under its partnership agreement to distribute to unitholders all available cash on hand at the end of a quarter less the amount of any reserves established by its general partner. Quarterly distributions by CQP are currently comprised of a base amount plus a variable amount equal to the remaining available cash per unit, which takes into consideration, among other things, amounts reserved for annual debt repayment and capital allocation goals, anticipated capital expenditures to be funded with cash, and cash reserves to provide for the proper conduct of CQP’s business;
• Our 48.6% limited partner interest, 100% general partner interest and incentive distribution rights in CQP limit our right to receive cash held by CQP to the amounts specified by the provisions of CQP’s partnership agreement; and
• SPL and CCH are restricted by affirmative and negative covenants included in certain of their debt agreements in their ability to make certain payments, including distributions, unless specific requirements are satisfied.

Despite the restrictions noted above, we believe that sufficient flexibility exists within the Cheniere complex to enable each independent capital structure to meet its currently anticipated cash requirements. The sources of liquidity at SPL, CQP and CCH primarily fund the cash requirements of the respective entity, and any remaining liquidity not subject to restriction, as supplemented by liquidity provided by Cheniere Marketing, is available to enable Cheniere to meet its cash requirements.

Corpus Christi LNG Terminal Expansion

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as of March 31, 2026:

(1) As of March 31, 2026, substantial completions of the first five of seven midscale Trains of the Corpus Christi Stage 3 Project have been achieved.

Sources and Uses of Cash

The following table summarizes the sources and uses of our cash, cash equivalents and restricted cash and cash equivalents (in millions). The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, which are referred to elsewhere in this report. Additional discussion of these items follows the table.

Operating Cash Flows

The $148 million decrease between the periods was primarily related to a more significant decrease in net working capital in the current period as compared to prior period due to differences in timing of cash collections from the sale of LNG cargoes and payments to suppliers. Also contributing to the decrease in operating cash flows was cash used for settlement of derivative instruments during the three months ended March 31, 2026 compared to cash provided by settlement of derivative instruments during the same period in 2025. Partially offsetting these decreases was increased cash receipts from the sale of LNG cargoes due to higher revenue from increased Henry Hub pricing and higher production volume, as explained above in Results of Operations.

Investing Cash Flows

Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $414 million and $321 million during the three months ended March 31, 2026 and 2025, respectively; (2) $247 million of costs paid for the CCL Midscale Trains 8 & 9 Project during the three months ended March 31, 2026, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods. We expect to continue to incur capital expenditures for the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as construction progresses on these projects.

Financing Cash Flows

The following table summarizes our financing activities (in millions):

Proceeds from Issuances of Debt and Borrowings

The following table shows the proceeds from issuances of debt and borrowings, including intra-quarter activity (in millions):

35

Debt Redemptions and Repayments

The following table shows the redemptions and repayments of debt, including intra-quarter activity (in millions):

Repurchase of Common Stock

During the three months ended March 31, 2026 and 2025, we paid $537 million and $350 million to repurchase approximately 2.7 million and 1.6 million shares of our common stock, respectively, under our share repurchase program. Additionally, the Internal Revenue Service imposes an excise tax of 1% on the fair market value of our stock repurchases less our stock issuances, and we paid $13 million of such excise taxes during the three months ended March 31, 2025 related to our repurchases during the fiscal year 2023. In April 2026, we paid $26 million of excise taxes related to our repurchases during the fiscal year 2025. 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. As of March 31, 2026, we had approximately $9.7 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the three months ended March 31, 2026 and 2025, we paid dividends of $0.555 and $0.500 per share of common stock for a total of $117 million and $112 million, respectively.

On April 28, 2026, we declared a quarterly dividend of $0.555 per share of common stock that is payable on May 19, 2026 to stockholders of record as of the close of business on May 11, 2026.

Summary of Critical Accounting Estimates

The preparation of 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. There have been no significant changes to our critical accounting estimates from those disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025.

Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 1—Nature of Operations and Basis of Presentation of our Notes to Consolidated Financial Statements.

Marketing and Trading Commodity Price Risk

We have commodity derivatives consisting of natural gas and power supply contracts for the commissioning and operation of the Liquefaction Projects and the SPL Expansion Project, and 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”). In order to test the sensitivity of the fair value of the Liquefaction Supply Derivatives and the LNG Trading Derivatives to changes in underlying commodity prices, management modeled a 10% change in the commodity price for natural gas for each delivery location and a 10% change in the commodity price for LNG, respectively, as follows (in millions):

See Note 5—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

We maintain a set of disclosure controls and procedures that are designed to ensure that information required to be disclosed by us in the reports filed by us under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. As of the end of the period covered by this report, we evaluated, under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, the effectiveness of our disclosure controls and procedures pursuant to Rule 13a-15 of the Exchange Act. Based on that evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that our disclosure controls and procedures are effective.

During the most recent fiscal quarter, there have been no changes in our internal control over financial reporting that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

There have been no material changes from the risk factors disclosed in our annual report on Form 10-K for the fiscal year ended December 31, 2025.