Cheniere Energy, Inc.: Form 10-Q for the period ended Sep 30, 2025

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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 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.

We are the largest producer of LNG in the United States and we were the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities as of September 30, 2025. Our total production capacity is expected to be over 60 mtpa of LNG, inclusive of estimated debottlenecking opportunities, of which over 12 mtpa was under construction and the remainder was in operation as of September 30, 2025, 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 September 30, 2025, 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 over 12 mtpa under construction and the remainder in operation as of September 30, 2025, 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 7 mtpa under construction and the remainder in operation from the first two midscale Trains that have reached substantial completion as of September 30, 2025, (subsequently, in October 2025, the third midscale Train reached substantial completion); 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 September 30, 2025. Our board of directors (the “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. Non-FTA export authorization on the CCL Midscale Trains 8 & 9 Project is pending with the DOE.

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 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 IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of September 30, 2025, we have contracted approximately 90% of the total anticipated production from the CCL Project and the SPL Project (collectively, the “Liquefaction Projects”) through the mid-2030s, excluding volumes from contracts with terms less than 10 years and volumes that are contractually subject to additional liquefaction capacity beyond what is currently in construction or operation. 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 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 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 an expansion adjacent to the SPL Project with an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities, and supporting infrastructure (the “SPL Expansion Project”), and we are commercializing to support the additional liquefaction capacity associated with this project. This project 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.

The following table summarizes pre-FID development efforts and certain key milestones associated with the SPL 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, 2024 and our quarterly report on Form 10-Q for the quarterly period ended March 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) Based on letter from the FERC granting our request to commence with site preparation. The FERC orders require us to comply with certain ongoing conditions and obtain certain additional FERC and other regulatory agency approvals as construction progresses.

(4) We anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the SPL Expansion Project, if we reach a positive FID.

(5) Liquefaction capacity partially contracted by Cheniere Marketing and SPL Stage V through SPA or IPM agreements conditioned on additional liquefaction capacity beyond what is currently in construction or operation.

(6) 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.

We have excluded from the table above a potential further expansion of the CCL Project with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities, and supporting infrastructure (the “CCL Stage 4 Expansion Project”), for which we commenced the pre-filing process with the FERC in July 2025, as none of the milestones within the table have yet been achieved.

Overview of Significant Events

Our significant events since January 1, 2025 and through the filing date of this Form 10-Q include the following:

Strategic

• In August 2025, Cheniere announced the execution of a long-term LNG SPA between Cheniere Marketing and JERA Co., Inc. (“JERA”), under which JERA has agreed to purchase approximately 1 mtpa of LNG from Cheniere Marketing on an FOB basis from 2029 through 2050. The purchase price for LNG under the SPA is indexed to the Henry Hub price, plus a fixed liquefaction fee.
• In July 2025, we submitted a request to initiate the pre-filing review process with the FERC under the National Environmental Policy Act for the CCL Stage 4 Expansion Project, a potential further expansion of the Corpus Christi LNG Terminal with an expected total peak production capacity of up to 24 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
• In June 2025, our Board made a positive FID with respect to the investment in the development, construction and operation of the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under a fixed price separated turnkey EPC contract.
• In June 2025, certain subsidiaries of CQP updated the SPL Expansion Project’s FERC application, originally filed in February 2024, to reflect a two-phased project, inclusive of three liquefaction trains and supporting infrastructure, maintaining an expected total peak production capacity of up to approximately 20 mtpa of LNG, inclusive of estimated debottlenecking opportunities.
• In May 2025, Cheniere Marketing entered into an IPM agreement with Canadian Natural Resources Limited to purchase 140,000 MMBtu per day of natural gas at a price based on the Japan Korea Marker, less fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing in approximately 2030. This agreement is subject to us making a positive FID with respect to the SPL Expansion Project or unilaterally waiving such condition.
• In March 2025, we received authorization from the FERC under the NGA to site, construct and operate the CCL Midscale Trains 8 & 9 Project.

Operational

• As of October 24, 2025, over 4,370 cumulative LNG cargoes totaling over 300 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.
• In March and August 2025, substantial completions of Trains 1 and 2, respectively, of the Corpus Christi Stage 3 Project were achieved. Subsequently in October 2025, Train 3 of the Corpus Christi Stage 3 Project achieved substantial completion.

Financial

• In August 2025, we amended and restated our $1.25 billion Cheniere Revolving Credit Facility to, among other things, (1) extend the maturity date thereunder, (2) reduce the interest rate and commitment fees payable thereunder and (3) make certain other changes to the terms and conditions of the existing Cheniere Revolving Credit Facility.
• In July 2025, CQP issued and sold $1.0 billion aggregate principal amount of 5.550% Senior Notes due 2035 (the “2035 CQP Senior Notes”), and the net proceeds, together with cash on hand, were used to redeem $1.0 billion of the aggregate principal amount of SPL’s 5.875% Senior Secured Notes due 2026 (the “2026 SPL Senior Notes”).
• In June 2025, we announced updates to our company outlook, which included a plan to increase our annualized dividend by over 10% to $2.22 per common share commencing with the third quarter of 2025, subject to declaration by the Board.
• In February 2025, Fitch Ratings upgraded the issuer credit rating of both Cheniere and CQP to BBB from BBB- with a stable outlook. In June 2025, S&P Global Ratings concurrently assigned a BBB rating to the 2035 CQP Senior Notes and upgraded the remaining unsecured CQP notes to BBB from BBB-.
• During the three and nine months ended September 30, 2025, we accomplished the following pursuant to our capital allocation priorities:
• We repurchased approximately 4.4 million and 7.4 million shares of our common stock, respectively, as part of our share repurchase program for approximately $1.0 billion and $1.7 billion, respectively.
• In September 2025, SPL repaid $52 million aggregate principal amount outstanding of its series of senior secured notes due 2037 with a weighted average interest rate of 4.746%, based on their respective fixed amortization schedules.
• In March 2025, SPL repaid the remaining $300 million aggregate principal amount outstanding of its 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”) at maturity.
• We paid dividends of $0.500 and $1.500 per share of common stock, respectively.
• 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)

32

Volumes loaded and recognized from the Liquefaction Projects

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 IPM agreements.

Net income attributable to Cheniere

Net income attributable to Cheniere increased $156 million and $753 million for the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, primarily due to:

• $69 million and $665 million, respectively, of favorable changes in the fair value of agreements accounted for as derivative instruments (before tax and the impact of NCI), largely due to changes in market-based locational forward price differentials for North American natural gas deliveries, which impacted our natural gas supply derivatives, and incrementally for the comparable nine month periods due to the impact of declines in short-term global gas prices and volatility within our derivatives related to financial positions to economically hedge the purchase and sale of physical LNG and our derivatives related to IPM agreements, respectively; and
• $183 million and $661 million of increases, respectively, in LNG revenues, net of cost of sales and excluding changes in fair value of derivatives, primarily as a result of higher pricing per MMBtu between the comparable nine month periods including the effect of settlement of previously entered derivative instruments, as well as increased

production volume due to the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively.

Partially offsetting these favorable changes between the comparable three and nine month periods were increased tax provisions of $72 million and $300 million, respectively, as further explained under the caption Income tax provision below, decreased sublease and subcharter income from our LNG vessels of $63 million and $207 million, respectively, due to fewer days the LNG vessels were subcontracted out and at lower rates in the current periods as compared to the same periods of 2024 and increased operating and maintenance expenses of $115 million between the comparable nine month periods primarily due to the completion of planned large-scale maintenance activities on two trains at the SPL Project.

The following is an expanded discussion of the significant drivers of the variance in net income attributable to Cheniere by line item:

Revenues

The $678 million and $3.3 billion increases in revenues between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to:

• $482 million and $2.7 billion increases, respectively, due to higher pricing per MMBtu primarily from increased Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;
• $117 million and $301 million of gains, respectively, from agreements accounted for as derivative instruments included in revenues of which the gain between the three month periods was primarily attributable to the effect of settlement of previously entered derivative instruments and the gain between the nine month periods was primarily derived from a favorable change in fair value, as further described above under the caption Net income attributable to Cheniere; and
• $149 million and $497 million increases, respectively, due to higher volumes of LNG delivered between the periods, primarily as a result of increased production volume due to the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively.

These favorable variances were partially offset by $63 million and $207 million decreases in sublease and subcharter income from our LNG vessels between the comparable three and nine month periods, respectively, due to fewer days the LNG vessels were subcontracted out and at lower rates in the current year as compared to the same periods of 2024.

Operating costs and expenses

The $508 million and $2.3 billion unfavorable variances between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to:

• $580 million and $2.6 billion increases, respectively, in cost of sales excluding the effect of derivative changes, substantially all related to the increases in cost of natural gas feedstock, largely due to the increase in U.S. natural gas prices as further described under the caption Revenues;
• $115 million increase in operating and maintenance expense between the comparable nine month periods, primarily due to the completion of planned large-scale maintenance activities on two trains at the SPL Project and additional expenses from the substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project in March 2025 and August 2025, respectively; and
• $32 million and $67 million increases, respectively, in depreciation, amortization and accretion expense, primarily as a result of substantial completions of Trains 1 and 2 of the Corpus Christi Stage 3 Project.

These unfavorable variances were partially offset by $92 million and $419 million of favorable changes in fair value of agreements accounted for as derivative instruments included in cost of sales between the comparable three and nine month periods, respectively, with the primary drivers of the variance described above under the caption Net income attributable to Cheniere.

Other income (expense)

The $9 million unfavorable variance between the three months ended September 30, 2025 and 2024 and the $34 million favorable variance between the nine months ended September 30, 2025 and 2024 were primarily attributable to:

• $11 million and $68 million decreases in interest expense, net of capitalized interest, between the comparable three and nine month periods, respectively, due to $8 million and $38 million increases, respectively, in capitalized interest costs, given the higher carrying value of assets under construction and additionally due to $3 million and $30 million lower gross interest costs, respectively, due to debt reduction activities associated with our long-term capital allocation plan; and
• $22 million increase in other income, net, between the comparable nine month periods primarily from a $26 million gain recognized on the sale of our equity interests in an equity method investment during the three months ended March 31, 2025.

These favorable variances were partially offset by $18 million and $58 million decreases in interest and dividend income between the comparable three and nine month periods, respectively, as a result of decreased interest rates and lower average cash and cash equivalents balances between the periods.

Income tax provision

The $72 million and $300 million unfavorable variances between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to increases in our effective tax rate, as described below, as well as a higher income tax expense due to $161 million and $953 million increases in pre-tax income, respectively.

Our effective tax rate was 18.9% and 18.0% for the three and nine months ended September 30, 2025, respectively, as compared to 16.1% and 14.6% for the same periods of 2024, respectively. Our effective tax rate increased between the comparable periods primarily due to a decreased proportion of our pre-tax income attributable to CQP, which is partially not taxable to us, and a reduced Foreign Derived Intangible Income (“FDII”) deduction. Additionally contributing to the unfavorable variance in our effective tax rate between the comparable nine month periods was an increased tax expense due to a valuation allowance on a capital loss carryover generated on the sale of all of our equity interests in an equity method investment during the three months ended March 31, 2025, as discussed above under the caption Other income (expense). The effective tax rate for the comparable three and nine month periods was lower than the statutory rate of 21.0% primarily due to CQP’s income that is partially not taxable to us.

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 FDII deduction rules, renamed to the Foreign Derived Deduction Eligible Income (“FDDEI”) under the OBBBA beginning in 2026.

We initially applied the relevant and effective provisions of the OBBBA in the third quarter of 2025, including provisions related to bonus depreciation. The legislation did not have a material impact on our income tax expense for the three months ended September 30, 2025, and we do not expect it to materially change our effective income tax rate for 2025. However, the 100% bonus depreciation provision under the OBBBA is expected to defer 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.

Commencing with its effectiveness in 2026, we expect that the FDDEI regime will favorably impact our effective tax rate relative to prior policy, as a larger portion of our export-related income is projected to be eligible for a preferential tax rate despite an increase in the tax rate on qualifying sales. The FDDEI regime provides for an effective tax rate of 14%, a rate lower than the statutory corporate tax rate of 21%, on eligible sales of property or services to a foreign person for foreign use. Relative to the prior FDII tax provision, the FDDEI regime increases the effective tax rate on eligible sales but broadens qualifying income by eliminating certain asset-based eligibility constraints and removing the requirement to reduce eligible income by specified allocable expenses.

On September 30, 2025, the Internal Revenue Service (the “IRS”) 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 are entitled to a refund of $380 million of previously paid CAMT, which has been recognized as a tax-related receivable as of September 30, 2025.

Net income attributable to non-controlling interests

The $67 million and $100 million decreases between the three and nine months ended September 30, 2025, respectively, as compared to the same periods of 2024, were primarily attributable to $129 million and $187 million decreases in CQP’s consolidated net income, respectively, primarily from unfavorable changes in 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. For commodity derivative instruments, including those related to our 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 and nine months ended September 30, 2025, we realized offsets to LNG terminal costs of $47 million and $102 million, respectively, corresponding to 6 TBtu and 12 TBtu, respectively, of LNG that were related to the sale of commissioning volumes. We did not record any offsets to LNG terminal costs during the three and nine months ended September 30, 2024.

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.

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 over 12 mtpa is still under construction or commissioning as of September 30, 2025. As of September 30, 2025, substantial completions for the first two Trains of the Corpus Christi Stage 3 Project have been achieved, and subsequently in October 2025, substantial completion for the third Train of the Corpus Christi Stage 3 Project was achieved. 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.

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 balances held by our consolidated variable interest entities (“VIEs”), as discussed in Note 6—Non-Controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of September 30, 2025, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $121 million of cash and cash equivalents and $61 million of restricted cash and cash equivalents.

(2) Available commitments represent total commitments less loans outstanding and letters of credit issued under each of our credit facilities as of September 30, 2025. 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 September 30, 2025 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, 2024.

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

As of September 30, 2025, substantial completions of the first two of seven midscale Trains of the Corpus Christi Stage 3 Project were achieved. Additionally, in June 2025, our Board made a positive FID with respect to the CCL Midscale Trains 8 & 9 Project and issued a full notice to proceed with construction to Bechtel under an EPC contract for a contract price of approximately $2.9 billion, subject to adjustment only by change order.

The following table summarizes the project completion and construction status of both the Corpus Christi Stage 3 Project and the CCL Midscale Trains 8 & 9 Project as of September 30, 2025:

(1) In October 2025, substantial completion of Train 3 of the Corpus Christi Stage 3 Project was 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.

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Operating Cash Flows

The $269 million decrease between the periods was primarily related to lower cash flows attributed to working capital from differences in timing of payments to suppliers and cash collections from the sale of LNG cargoes, partially offset by higher net cash inflows from LNG sales, as explained above in Results of Operations, and increased cash inflows from settlement of derivative instruments.

As described in Results of Operations, the OBBBA was signed into law during the third quarter of 2025 and includes, among other provisions, reinstating 100% accelerated tax bonus depreciation on qualifying assets acquired after January 19, 2025, which is expected to defer our income tax liability, ultimately reducing our income tax payable to a nominal amount in 2025, and modifying the export-promoting FDII deduction rules, renamed to the FDDEI under the OBBBA, which is expected to reduce our income taxes payable relative to prior policy in future periods. Additionally, the IRS issued Notice 2025-49, which revised rules for calculating CAMT adjusted financial statement income, deferring our tax obligations and entitling us to a refund of $380 million of previously paid CAMT.

Investing Cash Flows

Our investing net cash outflows primarily related to: (1) construction costs for the Corpus Christi Stage 3 Project, which were $1.1 billion and $1.3 billion during the nine months ended September 30, 2025 and 2024, respectively; (2) $750 million of costs paid for the CCL Midscale Trains 8 & 9 Project during the nine months ended September 30, 2025, primarily related to procurement and engineering; and (3) optimization and other site improvement projects during both periods. The $0.2 billion decrease in construction costs for the Corpus Christi Stage 3 Project between the periods was primarily related to the timing of cash payments under the related EPC contract. 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):

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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):

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 nine months ended September 30, 2025 and 2024, we paid $1.7 billion and $2.0 billion to repurchase approximately 7.4 million and 12.2 million shares of our common stock, respectively, under our share repurchase program. Additionally, during the nine months ended September 30, 2025, we paid $33 million of excise taxes related to our repurchase of common stock during the fiscal years 2023 and 2024. As of September 30, 2025, we had approximately $2.2 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the nine months ended September 30, 2025, we paid aggregate dividends of $1.500 per share of common stock for a total of $332 million and during the nine months ended September 30, 2024, we paid aggregate dividends of $1.305 per share of common stock for a total of $300 million.

On October 28, 2025, we declared a quarterly dividend of $0.555 per share of common stock that is payable on November 18, 2025 to stockholders of record as of the close of business on November 7, 2025.

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, 2024.

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 physical and financial derivatives to hedge 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, 2024, except for the updates presented in our quarterly report on Form 10-Q for the quarterly period ended March 31, 2025.