Cheniere Energy, Inc. (LNG) FY 2024 MD&A

ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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. Discussion of items for the year ended December 31, 2022 and variance drivers between the year ended December 31, 2023 as compared to December 31, 2022 are not included herein and can be found in “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, 2023.

Our discussion and analysis includes the following subjects:

•Overview

•Overview of Significant Events

•Market Environment

•Results of Operations

•Liquidity and Capital Resources

•Summary of Critical Accounting Estimates

•Recent Accounting Standards

Overview

We are an 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 operate two natural gas liquefaction and export facilities at Sabine Pass, Louisiana and near Corpus Christi, Texas. For further discussion of our business, see Items 1. and 2. Business and Properties.

Our long-term counterparty arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements currently in effect, with approximately 15 years of weighted average remaining life as of December 31, 2024, we have contracted approximately 95% of the total anticipated production from 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. The majority of our contracts are fixed-priced, long-term SPAs consisting of a fixed fee per MMBtu of LNG plus a variable fee per MMBtu of LNG, with the variable fees 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. During 2024, we continued to grow our portfolio of SPA and IPM agreements, and we believe that continued global demand for natural gas and LNG, as further described in Market Factors and Competition in Items 1. and 2. Business and Properties, will provide a foundation for additional growth in our business in the future. The continued strength and stability of our long-term cash flows served as the foundation of our updated comprehensive, long-term capital allocation plan announced in June 2024, which includes an increased share repurchase authorization and increased dividends, in addition to a continued decrease in consolidated long-term leverage and investment in accretive organic growth.

Overview of Significant Events

Our significant events since January 1, 2024 and through the filing date of this Form 10-K include the following:

Strategic

•In July 2024, Cheniere Marketing entered into a long-term SPA with Galp Trading S.A. (“Galp”), a subsidiary of Galp Energia, SGPS, S.A., under which Galp has agreed to purchase approximately 0.5 mtpa of LNG from Cheniere

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Marketing on a free-on-board basis for a term of 20 years. Deliveries are expected to commence in the early 2030s and are subject to, among other things, a positive FID with respect to the second train of the SPL Expansion Project (“SPL Train 8”) and includes a limited number of early cargoes to be purchased by Galp prior to the start of SPL Train 8.

•In June 2024, we received a positive Environmental Assessment from the FERC relating to the CCL Midscale Trains 8 & 9 Project. We expect to receive all remaining necessary regulatory approvals for the project in 2025.

•In February 2024, certain subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received for the SPL Expansion Project.

Operational

•As of February 14, 2025, approximately 3,930 cumulative LNG cargoes totaling approximately 270 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

•In December 2024, we achieved first LNG production from Train 1 of the Corpus Christi Stage 3 Project and in February 2025, the first cargo of LNG was produced from the Corpus Christi Stage 3 Project.

Financial

•In June 2024, we announced updates to our ‘20/20 Vision’ comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027 and a plan to increase our quarterly dividend by approximately 15% to $2.00 per common share on an annualized basis, which commenced with the dividend pertaining to the third quarter of 2024.

•In May 2024, CQP issued $1.2 billion aggregate principal amount of 5.750% Senior Notes due 2034 (the “2034 CQP Senior Notes”). In June 2024, the net proceeds, together with cash on hand, were used to redeem $1.2 billion of the outstanding aggregate principal amount of SPL’s 5.625% Senior Secured Notes due 2025 (the “2025 SPL Senior Notes”).

•In May 2024, in connection with the 2034 CQP Senior Notes issuance, Moody’s Ratings (“Moody’s”) upgraded CQP’s issuer credit rating to Baa2 from Ba1 and revised CQP’s outlook to stable from positive. Moody’s also upgraded SPL’s issuer credit rating to Baa1 from Baa2 and revised SPL’s outlook to stable from positive. In July 2024, Fitch Ratings upgraded CCH’s issuer credit rating to BBB+ from BBB with a stable outlook. In October 2024, S&P Global Ratings changed the outlook of CCH’s senior secured debt rating to positive from stable.

•In March 2024, we issued $1.5 billion aggregate principal amount of 5.650% Senior Notes due 2034 (the “2034 Cheniere Senior Notes”). In April 2024, the net proceeds, together with cash on hand, were used to retire the approximately $1.5 billion outstanding aggregate principal amount of CCH’s 5.875% Senior Secured Notes due 2025 (the “2025 CCH Senior Notes”).

•During the year ended December 31, 2024, we accomplished the following pursuant to our capital allocation priorities:

◦We repurchased approximately 13.8 million shares of our common stock as part of our share repurchase program for approximately $2.3 billion.

◦Excluding amounts refinanced, SPL redeemed $800 million of outstanding aggregate principal amount of its senior secured notes.

◦We paid dividends of $1.805 per share of common stock during the year ended December 31, 2024.

◦We continued to invest in accretive organic growth, including our investment in the Corpus Christi Stage 3 Project, as further described under Investing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

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Market Environment

The LNG market in 2024 remained relatively tight as a result of low supply capacity growth, strong demand outside Europe and continued geopolitical tensions. Global LNG imports registered a very modest growth in 2024, increasing by less than 4 mtpa year on year due to constrained supply from delays to projects under construction, Russian sanctions and a fallow period for new projects coming on-line. Consequently, a recovery in Asia’s LNG consumption had to be satisfied at the expense of other regions. Asian demand increased significantly from 2023, adding over 20 mtpa of import year-over-year. The largest single country contribution to this growth came from China, which increased 6.8 mtpa year-over-year after a slowdown during the previous two years. Growth outside of Asia tightened the balances further this year by increasing the call on supply away from Europe. Egypt and Brazil propelled imports from the Middle East, North Africa and Latin America regions by 6.2 mtpa to a total of 25.5 mtpa in 2024. In contrast, Europe’s imports declined 19% year-over-year, down approximately 22.7 mtpa, due to weak gas-fired power generation demand and sluggish growth in the industrial sector.

These market conditions contributed to a strong spot price environment albeit annual spot prices in 2024 were overall lower than in the previous year. The TTF monthly settlement prices averaged $10.91/MMBtu in 2024, 20.5% lower than the 2023 average of $13.73/MMBtu. Similarly, the average settlement price for the Japan Korea Marker (“JKM”) was $11.83/MMBtu in 2024, 26.6% lower than the 2023 average of $16.13/MMBtu. The Henry Hub benchmark also dropped from an average settlement price of $2.74/MMBtu in 2023 to $2.27/MMBtu in 2024, down 17.1% year-over-year.

However, a drop in temperatures in Europe toward the end of 2024 and into the beginning of 2025 has resulted in faster drawdowns from underground storage and a rebound in spot prices relative to the third quarter. This, along with the expiry of the gas transit agreement between Russia and Ukraine on December 31, 2024, is likely to increase the call on LNG imports in the coming months in order to replenish European gas storage facilities to 90% capacity by November 1, as required by the EU each year.

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Results of Operations

Consolidated results of operations

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.

Net income attributable to Cheniere

Net income attributable to Cheniere declined $6.6 billion for the year ended December 31, 2024 as compared to the same period of 2023 and was primarily attributable to $6.7 billion of decreases in gains (before tax and the impact of non-controlling interests) from changes in fair value of derivatives. The majority of the decrease was attributable to our IPM agreements, where the associated gains that are primarily included in cost of sales decreased from $7.0 billion during the year ended December 31, 2023 to $1.5 billion during the year ended December 31, 2024, mainly due to the impact on fair value of the decline and sustained moderation of global LNG and gas price volatility and more subdued changes in the current period relative to the same period of 2023 as global prices and spreads narrowed as a result of market rebalancing. The remaining change in fair value of derivatives was primarily due to an unfavorable shift in long-term U.S. natural gas basis spreads. In addition, there was a $2.8 billion decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives, for the year ended December 31, 2024 as compared to the same period of 2023, the majority of which was attributable to a reduction of volumes sold under short-term agreements as a higher proportion of our LNG was sold under long-term contracts, as further described in Revenues below.

These unfavorable variances were partially offset by:

•$1.7 billion favorable variance in income tax provision between the year ended December 31, 2024 as compared to the same period of 2023, primarily due to lower taxable earnings as described above; and

•$938 million reduction in net income attributable to non-controlling interests during the year ended December 31, 2024 as compared to the same period of 2023, substantially all of which is due to a decrease in CQP’s consolidated net income between the comparable periods from declining gains related to changes in fair value of derivatives between the years.

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

Revenues

The $4.7 billion decrease in revenues between the year ended December 31, 2024 compared to the same period of 2023 was primarily attributable to:

•$3.8 billion decrease in revenues generated by our marketing function under short-term agreements between the comparative years due to declining global LNG and gas prices and a reduction of volumes sold under short-term agreements as a result of additional long-term agreements commencing in 2024 as compared to 2023; and

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•$676 million decrease in revenues attributable to declining Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed, between the years.

Operating costs and expenses

The $4.7 billion unfavorable variance between the year ended December 31, 2024 compared to the same period of 2023 was primarily attributable to:

•$6.5 billion of decreases in gains from changes in fair value of derivatives included in cost of sales, with the primary drivers of the variance described above under the caption Net income attributable to Cheniere;

This unfavorable variance was partially offset by:

•$1.7 billion decrease between the periods in cost of sales excluding the effect of derivative changes described above, primarily as a result of a $1.6 billion decrease in cost of natural gas feedstock largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices in the current year compared to the prior year.

Other income (expense)

The $86 million favorable variance between the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to:

•$131 million decrease in interest expense, net of capitalized interest, between the comparable years primarily due to a $92 million increase in interest costs qualifying for capitalization, given the higher carrying value of assets under construction, and additionally due to lower overall interest cost due to debt reduction activities associated with our long-term capital allocation plan;

These favorable variances were partially offset by:

•$24 million increase in losses on modification or extinguishment of debt between the comparable years from debt reduction activities, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources; and

•$22 million decrease in interest and dividend income between the comparable years, primarily as a result of lower average cash and cash equivalents balances between the respective periods.

Income tax provision

The $1.7 billion favorable variance between the years ended December 31, 2024 and 2023 was primarily attributable to a $9.3 billion decrease in pre-tax income and, to a lesser extent, a lower effective tax rate between the periods.

Our effective tax rate was 15.3% and 17.3% for years ended December 31, 2024 and 2023, respectively. Our effective tax rate decreased between the comparable periods and was lower than the statutory rate of 21.0% because a larger percentage of pre-tax income was attributable to CQP’s income that is not taxable to us.

Net income attributable to non-controlling interests

The $938 million decrease between the year ended December 31, 2024 as compared to the same period of 2023 was primarily attributable to a $1.7 billion decrease in CQP’s consolidated net income, primarily due to $1.5 billion of decreases in gains from the fair value of its IPM agreements accounted for as derivatives.

Significant factor affecting our results of operations

Below is a significant factor that affects our results of operations.

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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 6—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.

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 8—Non-controlling Interests and Variable Interest Entities of our Notes to Consolidated Financial Statements. As of December 31, 2024, assets of our VIEs, which are included in our Consolidated Balance Sheets, included $270 million of cash and cash equivalents and $125 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 December 31, 2024. See Note 10—Debt of our Notes to Consolidated Financial Statements for additional information on our credit facilities and other debt instruments.

Our liquidity position subsequent to December 31, 2024 will be driven by future sources of liquidity and future cash requirements, as further discussed under the caption Future Sources and Uses of Liquidity.

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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. Beginning with the distribution paid in the second quarter of 2022, 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.

Future Sources and Uses of Liquidity

The following discussion of our future sources and uses of liquidity includes estimates that reflect management’s assumptions and currently known market conditions and other factors as of December 31, 2024. Estimates are not guarantees of future performance and actual results may differ materially as a result of a variety of factors described in this annual report on Form 10-K.

Future Sources of Liquidity under Executed Contracts

We expect future material sources of liquidity to be derived from our long-term customer arrangements and structured cash flows under our SPAs and IPM agreements. As described in Items 1. and 2. Business and Properties, these contracts with creditworthy counterparties form the foundation of our business and provide us with significant, stable, long-term cash flows. Under our long-term SPAs and IPM agreements, we have contracted substantially all of our total anticipated production through the mid-2030s from our liquefaction capacity that is currently under construction or in operation.

LNG Revenues from Executed SPAs

We are contractually entitled to significant future consideration contracted under our long-term SPAs that has not yet been recognized as revenue. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be significant to our future liquidity. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We have estimated revenues under agreements with

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terms dependent on project milestone dates based on the estimated dates as of December 31, 2024. The following table summarizes our estimate of revenues to be received from executed long-term SPAs as of December 31, 2024 (in billions):

(1)LNG revenues exclude estimated revenues from contracts with unsatisfied contractual conditions precedent. We may enter into contracts to sell LNG that are conditioned upon one or both of the parties achieving certain milestones, such as reaching FID on a certain liquefaction Train.

(2)LNG revenues exclude revenues from contracts with original expected durations of one year or less. LNG revenues also exclude volumes produced from the commissioning of certain Corpus Christi Stage 3 Project Trains, as volumes related to commissioning are not recognized as revenues. We recognize proceeds from commissioning activities prior to the start of commercial operations as offsets to LNG terminal costs as a component of the testing phase of a Train’s construction.

(3)LNG revenues (variable fees) reflect the assumption of delivery of all contractual volumes, irrespective of any contractual right of non-delivery. LNG revenues (variable fees) are based on estimated forward prices and basis spreads as of December 31, 2024.

Under our SPAs, customers purchase LNG on either an FOB basis (delivered to the customer at the Sabine Pass LNG Terminal or the Corpus Christi LNG Terminal, as applicable) or a DAT basis (delivered to the customer at their specified LNG receiving terminal) generally for a price consisting of a fixed fee per MMBtu of LNG (a portion of which is subject to annual adjustment for inflation) plus a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub. The variable fees under our SPAs were generally sized with the intention to cover the supply and transportation of natural gas and the liquefaction fuel consumed to produce the LNG to be sold under each such SPA, thus limiting our exposure to future U.S. natural gas price increases. Certain customers may elect to cancel or suspend deliveries of LNG cargoes, with advance notice as governed by each respective SPA, in which case the customers would still be required to pay the fixed fee with respect to the contracted volumes that are not delivered as a result of such cancellation or suspension.

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. This LNG includes LNG produced from (1) the Liquefaction Projects prior to the date of first commercial delivery under long-term SPAs, (2) LNG production efficiencies and (3) natural gas procured under IPM agreements, as described below. These volumes may be supplemented by volumes procured from other locations worldwide to support operational requirements or take advantage of market opportunities.

Liquidity from Executed IPM Agreements

The table in the LNG Revenues from Executed SPAs section above excludes fees expected to be generated through sales of LNG produced from natural gas procured under our IPM agreements, under which we pay for natural gas feedstock based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. While IPM agreements are not revenue contracts for accounting purposes, the payment structure under the IPM agreements generates a take-or-pay style fixed liquefaction fee. Although the IPM agreements secure natural gas purchases over long-term periods, the LNG produced from that natural gas is generally sold under short-term SPAs. Over a remaining fixed term of 18 years, we expect to generate liquidity from the approximately 3,825 TBtu of LNG to be produced from natural gas not yet received under IPM agreements as of December 31, 2024, excluding approximately 665 TBtu related to an IPM agreement that is subject to unsatisfied contractual conditions precedent.

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Additional Future Sources of Liquidity

Available Commitments under Credit Facilities

As of December 31, 2024, we had $7.7 billion in available commitments under our credit facilities, as detailed earlier in the table summarizing our available liquidity, subject to compliance with the applicable covenants, to potentially meet liquidity needs. Our credit facilities mature between 2026 and 2029, based on estimated project milestone dates as of December 31, 2024.

Disciplined Accretive Growth

Our significant land positions at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal provide potential development and investment opportunities for further liquefaction capacity expansion at strategically advantaged locations with proximity to pipeline infrastructure and resources. In February 2024, certain subsidiaries of CQP submitted an application to the FERC under the NGA for authorization to site, construct and operate the SPL Expansion Project, as well as an application to the DOE requesting authorization to export LNG to FTA countries and non-FTA countries, both of which applications exclude debottlenecking. In October 2024, the authorization from the DOE to export LNG to FTA countries was received. In June 2024, we received a positive Environmental Assessment from the FERC relating to the CCL Midscale Trains 8 & 9 Project, and we expect to receive all remaining necessary regulatory approvals for the project in 2025. The development of these sites or other projects, including infrastructure projects in support of natural gas supply and LNG demand, will require, among other things, acceptable commercial and financing arrangements before we make a positive FID.

Future Cash Requirements for Operations and Capital Expenditures under Executed Contracts

We are committed to make future cash payments for operations and capital expenditures pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for operations and capital expenditures related to our core operations under executed contracts as of December 31, 2024 (in billions):

(1)Agreements in force as of December 31, 2024 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2024.

(2)Purchase obligations consist of agreements to purchase goods or services that are enforceable and legally binding that specify fixed or minimum quantities to be purchased. We include contracts for which we have an early termination option if the option is not currently expected to be exercised. We include contracts with unsatisfied contractual conditions if the conditions are currently expected to be met.

(3)Natural gas supply agreements exclude IPM agreements, which are structured to generate a fixed margin when viewed in conjunction with the sale of LNG produced from the natural gas procured under the IPM agreements, as described under Liquidity from Executed IPM Agreements.

(4)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2024. Natural gas supply agreements are presented net of $0.3 billion in contracted sales of natural gas as of December 31, 2024.

(5)Natural gas transportation and storage services agreements include $1.2 billion in obligations to related parties.

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(6)Leases include payments under (1) operating leases, (2) finance leases, (3) short-term leases and (4) vessel time charters that were executed as of December 31, 2024 but will commence in the future. Payments during future renewal option periods that are exercisable at our sole discretion are included only to the extent that the option is believed to be reasonably certain to be exercised. Leases are presented net of $1.2 billion in future income associated with vessel time charters that were subchartered to third parties.

Natural Gas Supply, Transportation and Storage Service Agreements

Excluding IPM agreements and unexercised extension options, we have secured approximately 7,980 TBtu of natural gas feedstock for our Liquefaction Projects through long-term natural gas supply agreements with remaining fixed terms of up to 15 years. As of December 31, 2024, we have secured approximately 74% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2025, excluding the 6% of which has been secured under IPM agreements. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2025. As further described in the LNG Revenues from Executed SPAs section, the pricing structure of our SPAs often incorporates a variable fee per MMBtu of LNG generally equal to 115% of Henry Hub, which is paid upon delivery, thus limiting our net exposure to future increases in natural gas prices.

To ensure that we are able to transport natural gas feedstock to the Liquefaction Projects, we have transportation precedent and other agreements to secure firm pipeline transportation capacity from interstate and intrastate pipeline companies. We have also entered into firm storage services agreements with third parties to assist in managing variability in natural gas needs for the Liquefaction Projects.

Capital Expenditures

We enter into lump sum turnkey contracts with third party contractors for the EPC of our Liquefaction Projects. The future capital expenditures included in the table above primarily consist of fixed costs under the lump sum Bechtel EPC contract for the Corpus Christi Stage 3 Project, in which Bechtel charges a lump sum and generally bears project cost, schedule and performance risks unless certain specified events occur, in which case Bechtel causes us to enter into a change order, or we agree with Bechtel to a change order. In addition to amounts presented in the table above, we expect to incur ongoing capital expenditures to maintain our facilities and other assets, as well as to optimize our existing assets and purchase new assets that are intended to grow our productive capacity.

Corpus Christi Stage 3 Project

The following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2024:

Leases

Our obligations under our lease arrangements primarily consist of LNG vessel time charters with terms of up to 15 years to ensure delivery of cargoes sold on a DAT basis. We have also entered into leases for the use of tug vessels, office space and facilities, land sites and equipment.

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Additional Future Cash Requirements for Operations and Capital Expenditures

Corporate Activities

We are required to maintain corporate and general and administrative functions to serve our business activities. During the year ended December 31, 2024, selling, general and administrative expense was $0.4 billion, a portion of which was related to leases for office space which is included in the table of cash requirements for operations and capital expenditures under executed contracts above.

Taxes

CAMT accelerates our cash tax payments for federal income taxes due to near-term deferral of the realization of our existing NOL carryforwards and may cause volatility in future cash tax payments due to variability in adjusted financial statement income. Additionally, our cash tax payments may be substantially lower in the periods that the Corpus Christi Stage 3 Project is placed into service due to anticipated tax depreciation allowances from the project. Thus, the ongoing interplay between the CAMT, the utilization of our existing NOLs and bonus depreciation eligibility of our Corpus Christi Stage 3 Project is expected to cause volatility in our cash tax payments. See the risk Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity under Risks Relating to Regulations in Item 1A. Risk Factors.

As part of our ongoing effort to mitigate our emissions from our shipping transport operations, we primarily utilize the LNG that we produce at our terminals as transport fuel in our shipping vessel operations, serving as a substitute for diesel and heavy fuel oils, which have higher emission factors. Our use of LNG as a cleaner burning fuel in our operations has enabled us to claim domestic alternative fuel excise tax credits which we are actively pursuing for the period spanning from 2018 to 2024. Although we believe we qualify and are entitled to claim such credits, we have not recognized any financial benefit of our credit claims in our results of operations to date. Our claims are currently under review by the IRS, and there is ongoing uncertainty regarding the final determination of our eligibility.

Disciplined Accretive Growth

The FID of any expansion projects will result in additional cash requirements to fund the construction and operations of such projects in excess of our current contractual obligations under executed contracts discussed above, although expansion may be designed to leverage shared infrastructure to reduce the incremental costs of any potential expansion.

Future Cash Requirements for Financing under Executed Contracts

We are committed to make future cash payments for financing pursuant to certain of our contracts. The following table summarizes our estimate of material cash requirements for financing under executed contracts as of December 31, 2024 (in billions):

(1)Debt and interest payments are based on the total debt balance, scheduled contractual maturities and fixed or estimated forward interest rates in effect at December 31, 2024. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2024, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $23.1 billion and credit facilities with no outstanding loan balances. As of December 31, 2024, each of our issuers was in compliance with all covenants related to their respective debt agreements. Further discussion of our debt obligations, including the restrictions imposed by these arrangements, can be found in Note 10—Debt of our Notes to Consolidated Financial Statements.

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Interest

As of December 31, 2024, our senior notes had a weighted average contractual interest rate of 4.69%. Borrowings under our credit facilities are indexed to SOFR. Undrawn commitments under our credit facilities are subject to commitment fees ranging from 0.075% to 0.525%, subject to change based on the applicable entity’s credit rating. Issued letters of credit under our credit facilities are subject to letter of credit fees ranging from 1.0% to 2.20%, subject to change based on the applicable entity’s credit rating. We had $334 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2024.

Additional Future Cash Requirements for Financing

CQP Distributions

CQP is required by its partnership agreement to, within 45 days after the end of each quarter, distribute to unitholders all available cash at the end of a quarter less the amount of any reserves established by its general partner. We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, 100% of the general partner interest and 100% of the incentive distribution rights, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. During the year ended December 31, 2024, $846 million in distributions were paid to our non-controlling interests.

Capital Allocation Plan

In June 2024, our Board approved an updated comprehensive long-term capital allocation plan, which included an increase to our share repurchase authorization by $4.0 billion through 2027. As of December 31, 2024, we had up to $3.9 billion available under the share repurchase program. The timing and amount of any shares of our common stock that are repurchased under the share repurchase program will be determined by management based on market conditions and other factors, with repurchases executed within trading parameters pre-established for each applicable trading period in compliance with SEC Rule 10b5-1. During the year ended December 31, 2024, we repurchased approximately 13.8 million shares of our common stock for $2.3 billion at a weighted average price per share of $163.72. A discussion of our share repurchase program can be found in Item 5. Market for Registrant’s Common Equity, Related Stockholders Matters and Issuer Purchase of Equity Securities.

Another aspect of our capital allocation plan is to lower our long-term leverage target through debt paydown to approximately 4x, which may involve the repayment, redemption or repurchase, on the open market or otherwise, of our indebtedness, including senior notes of SPL, CQP, CCH and Cheniere. The timing and amount of any paydown of our indebtedness will be determined by management based on market conditions and other factors. During the year ended December 31, 2024, we used $800 million of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.

The updated capital allocation plan also included a plan to increase our quarterly dividend by approximately 15% to $2.00 per common share on an annualized basis, which commenced with the dividend pertaining to the third quarter of 2024. On January 28, 2025, we declared a quarterly dividend of $0.50 per share of common stock that is payable on February 21, 2025 to stockholders of record as of the close of business on February 7, 2025.

Financially Disciplined Growth

To the extent that liquefaction capacity at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal is expanded beyond the Liquefaction Projects, such as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, we expect that additional financing would be used to fund construction of the expansion.

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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 $3.0 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to a reduction in both pricing per MMBtu and volumes sold under short-term agreements, although this exposed us less to declining international LNG and gas prices in the current year as a higher proportion of our LNG was sold under long-term agreements. The decrease was partially offset by lower cash outflows for natural gas feedstock, largely due to the decline and sustained moderation of global LNG and gas prices as well as lower U.S. natural gas prices during the year ended December 31, 2024 as compared to December 31, 2023.

We became subject to the 15% CAMT in 2024. For the period ended December 31, 2024, our CAMT liability exceeded our regular tax liability by $383 million which created a CAMT credit carryforward with indefinite life. Our CAMT liability exceeded our regular tax liability in 2024 primarily because we used approximately $2.8 billion of our NOL carryover from 2019 to offset our regular taxable income; however, such NOL carryover does not factor into our CAMT computation resulting in a higher CAMT tax base. We may continue to owe CAMT in future periods until the time our existing NOL carryovers are fully exhausted. Additionally, any final regulatory guidance related to the CAMT issued in the future could significantly affect the timing and amount of our CAMT obligations.

During 2024, the IRS issued Notice 2024-66 which extended the due date of our CAMT estimated payments to April 15, 2025. As a result, the majority of our current tax expense incurred for the year ended December 31, 2024 will be paid in 2025.

Additionally, our cash taxes in the near term could potentially be impacted by possible new federal tax legislation being enacted. Several key provisions of the Tax Cuts and Jobs Act (the “TCJA”) are set to expire or change after 2025, raising the prospects for a new tax bill being enacted in 2025. While the current corporate tax rate of 21% established by the TCJA is permanent and not set to expire, President Trump has proposed reducing the rate to 15% for U.S. manufacturers. Any significant changes to the corporate tax rate, Foreign-Derived Intangible Income provisions, immediate expensing rules or other key tax policies in 2025 could affect our financial position and liquidity. While we are unable to predict the timing and scope of any potential tax legislation, we continue to monitor and assess any proposed tax law changes to determine the impact on our business, cash flows and financial results.

Investing Cash Flows

Our investing net cash outflows in both periods primarily were for the construction costs for the Corpus Christi Stage 3 Project, which were $1.5 billion during both the years ended December 31, 2024 and 2023, as well as for optimization and other site improvement projects. We expect to incur a proportional level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project.

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Financing Cash Flows

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

Debt Issuances

The following table shows our debt issuances (in millions):

Debt Redemptions, Repayments and Repurchases

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

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Repurchase of Common Stock

During the years ended December 31, 2024 and 2023, we paid $2.3 billion and $1.5 billion to repurchase approximately 13.8 million and 9.5 million shares of our common stock, respectively, under our share repurchase program. As of December 31, 2024, we had approximately $3.9 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

We paid aggregate dividends of $1.805 per share of common stock for a total of $412 million during the year ended December 31, 2024 and $1.62 per share of common stock for a total of $393 million during the year ended December 31, 2023.

On January 28, 2025, we declared a quarterly dividend of $0.50 per share of common stock that is payable on February 21, 2025 to stockholders of record as of the close of business on February 7, 2025.

Summary of Critical Accounting Estimates

The preparation of our Consolidated Financial Statements in conformity with GAAP requires management to make certain estimates and assumptions that affect the amounts reported in the Consolidated Financial Statements and the accompanying notes. Management evaluates its estimates and related assumptions regularly, including those related to the valuation of derivative instruments. Changes in facts and circumstances or additional information may result in revised estimates, and actual results may differ from these estimates. Management considers the following to be its most critical accounting estimates that involve significant judgment.

Fair Value of Level 3 Liquefaction Supply Derivatives

All of our derivative instruments are recorded at fair value, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions through earnings, based on the value for which the derivative instrument could be exchanged between willing parties. Valuation of our liquefaction supply derivative contracts is often developed through the use of internal models which includes significant unobservable inputs representing Level 3 fair value measurements as further described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies. In developing our volatility assumptions, we acknowledge that the global LNG industry is inherently influenced by events such as unplanned supply constraints, geopolitical incidents, unusual climate events including drought and uncommonly mild, by historical standards, winters and summers, and real or threatened disruptive operational impacts to global energy infrastructure. Our current estimate of volatility does not exclude the impact of otherwise rare events unless we believe market participants would exclude such events on account of their assertion that those events were specific to our company and deemed within our control.

As applicable to our natural gas supply contracts, our fair value estimates incorporate market participant-based assumptions pertaining to applicable contractual uncertainties, including those related to the availability of market information for delivery points, as well as the timing of both satisfaction of contractual events or states of affairs and delivery commencement. We may recognize changes in fair value through earnings that could be significant to our results of operations if and when such uncertainties are resolved.

Additionally, the valuation of certain liquefaction supply derivatives requires significant judgment in estimating underlying forward commodity curves due to periods of unobservability or limited liquidity. Such valuations are more susceptible to variability particularly when markets are volatile. Provided below are the changes in fair value from valuation of instruments valued through the use of internal models which incorporate significant unobservable inputs for the years ended

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December 31, 2024 and 2023 (in millions), which entirely consisted of liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.

The changes in fair value on instruments held at the end of both years are primarily attributed to a significant variance in the estimated and observable forward international LNG commodity prices on our IPM agreements in effect during the years ended December 31, 2024 and 2023.

The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2024 and 2023 amounted to a liability of $801 million and $2.2 billion, respectively.

The ultimate fair value of our derivative instruments is uncertain, and we believe that it is reasonably possible that a material change in the estimated fair value could occur in the near future, particularly as it relates to commodity prices impacting the valuation of our liquefaction supply derivatives, given the level of volatility to which such prices are subjected. See Item 7A. Quantitative and Qualitative Disclosures About Market Risk for further analysis of the sensitivity of the fair value of our derivatives to hypothetical changes in underlying prices.

Recent Accounting Standards

For a summary of recently issued accounting standards, see Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements.