Cheniere Energy Inc

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 entity, CQP, and its subsidiaries, as discussed in Note 9—Non-controlling Interest and Variable Interest Entity of our Notes to Consolidated Financial Statements. As of December 31, 2023, assets of CQP and its subsidiaries, which are included in our Consolidated Balance Sheets, included $575 million of cash and cash equivalents and $56 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, 2023. See Note 11—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, 2023 will be driven by future sources of liquidity and future cash requirements as further discussed under the caption Future Sources and Uses of Liquidity.

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 under debt and equity instruments executed by our subsidiaries limit each entity’s ability to distribute 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 unrestricted 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, 2023. 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 SPAs

As described in Items 1. and 2. Business and Properties, our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Substantially all of our future revenues are contracted under SPAs and because many of these contracts have long-term durations, we are contractually entitled to significant future consideration under these contracts which has not yet been recognized as revenue. This future consideration is, in most cases, not yet legally due to us and was not reflected on our Consolidated Balance Sheets as of December 31, 2023. In addition, a significant portion of this future consideration is subject to variability as discussed more specifically below. We anticipate that this consideration will be available to meet liquidity needs in the future. The following table summarizes our estimate of future material sources of liquidity to be received from executed SPAs as of December 31, 2023 (in billions):

(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023. The timing of revenue recognition under GAAP may not align with cash receipts, although we do not consider the timing difference to be material. 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, obtaining financing or achieving substantial completion of a Train and any related facilities. These contracts are included in the revenues above when the conditions are considered probable of being met.

(2)LNG revenues exclude revenues from contracts with original expected durations of one year or less. As of December 31, 2023, Cheniere Marketing had short term delivery commitments of approximately 88 TBtu of LNG to be delivered to third party customers in 2024. Fixed fees are fees that are due to us regardless of whether a customer exercises, in certain instances, their contractual right to not take delivery of an LNG cargo under the contract. Variable fees are receivable only in connection with LNG cargoes that are delivered.

(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, 2023. The pricing structure of many of our SPA arrangements with our customers 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.

Through our SPAs and IPM agreements, we have contracted substantially all of the total anticipated production from the Liquefaction Projects through the mid-2030s. The majority of the contracted capacity is comprised of fixed-price, long-term SPAs that SPL and CCL have executed with third parties to sell LNG from the Liquefaction Projects. In addition, we market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function, Cheniere Marketing. Cheniere Marketing has a portfolio of long-, medium- and short-term SPAs to deliver commercial LNG cargoes to locations worldwide. These volumes are expected to be primarily sourced by LNG produced by the Liquefaction Projects but supplemented by volumes procured from other locations worldwide, as needed.

Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. 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, our SPAs and IPM agreements had approximately 16 years of weighted average remaining life as of December 31, 2023. Under the SPAs, the 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. 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. The variable fees under our SPAs were generally sized with the intention to cover the costs of gas purchases, transportation and liquefaction fuel consumed to produce the LNG to be sold under each such SPA. Our long-term SPA customers consist of creditworthy counterparties, with an average credit rating of A-, A3 and A- by S&P, Moody’s and Fitch, respectively. A discussion of revenues under our SPAs can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Additional Future Sources of Liquidity

Regasification Revenues

SPLNG has a long-term, third party TUA with TotalEnergies, under which TotalEnergies is required to pay fixed fees of approximately $125 million annually, whether or not it uses the regasification capacity it has reserved. SPL has a partial TUA assignment agreement with TotalEnergies, whereby SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred by SPL to TotalEnergies under this partial TUA assignment agreement are recognized in operating and maintenance expense. Full discussion of the partial TUA assignment and SPLNG’s revenues under the TUA agreements can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Available Commitments under Credit Facilities

As of December 31, 2023, we had $7.6 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.

Uncontracted Liquefaction Supply

We expect a portion of total production capacity from the Liquefaction Projects that has not yet been contracted under executed agreements as of December 31, 2023 to be available for Cheniere Marketing to market to additional LNG customers. Debottlenecking opportunities and other optimization projects have led to increased run-rate production levels which has increased the production capacity available for Cheniere Marketing to the extent it has not already been contracted to other customers.

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 May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project. In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. 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, 2023 (in billions):

(1)Agreements in force as of December 31, 2023 that have terms dependent on project milestone dates are based on the estimated dates as of December 31, 2023.

(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)Pricing of natural gas supply agreements is based on estimated forward prices and basis spreads as of December 31, 2023. Pricing of IPM agreements is based on global gas market prices less fixed liquefaction fees and certain costs incurred by us. Global gas market prices are based on estimates as of December 31, 2023 to the extent forward prices are not available and assume the highest price in cases of price optionality available under the agreement. Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

(4)Includes $1.3 billion of purchase obligations to related parties under the natural gas transportation and storage service agreements, of which $1.0 billion had unsatisfied contractual conditions.

(5)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, 2023 but will commence in the future. Certain of our leases also contain variable payments, such as inflation, which are not included above unless the contract terms require in-substance fixed payments that are, in effect, unavoidable. Payments during renewal options 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. We subcharter certain LNG vessels while retaining our existing obligation under the original charter. Future income associated with our subcharters was $510 million, inclusive of, as described in Note 12—Leases of our Notes to Consolidated Financial Statements, $163 million qualifying as subleases.

Natural Gas Supply, Transportation and Storage Service Agreements

We have secured natural gas feedstock for the CCL Project and the SPL Project through long-term natural gas supply agreements, including IPM agreements. Under our IPM agreements, 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 for the purchase of natural gas under the IPM agreements generates a take-or-pay style fixed liquefaction fee, assuming that LNG produced from the natural gas feedstock is subsequently sold at a price approximating the global gas market price paid for the natural gas feedstock purchase.

As of December 31, 2023, we have secured approximately 82% of the natural gas supply required to support the total forecasted production capacity of the Liquefaction Projects during 2024. Natural gas supply secured decreases as a percentage of forecasted production capacity beyond 2024. Natural gas supply is generally secured on an indexed pricing basis plus a fixed fee, with title transfer occurring upon receipt of the commodity. As further described in the LNG Revenues section above, the pricing structure of our SPA arrangements with our customers 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. Inclusive of amounts under contracts with unsatisfied contractual conditions that are currently considered probable of being met and exclusive of extension options that were uncertain to be taken as of December 31, 2023, we have secured up to 12,794 TBtu of natural gas feedstock through agreements with remaining fixed terms of up to approximately 15 years. A discussion of our natural gas supply and IPM agreements can be found in Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements.

To ensure that we are able to transport natural gas feedstock to the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal, we have entered into 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 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 occurred, 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. See Financially Disciplined Growth section for further discussion.

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, 2023:

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, marine equipment and facilities and land sites. A discussion of our lease obligations can be found in Note 12—Leases of our Notes to Consolidated Financial Statements.

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, 2023, selling, general and administrative expense was $0.5 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.

Income Tax

Because the currently enacted CAMT may accelerate or cause volatility in our cash tax payments attributable to variability in AFSI, our cash tax payments may fluctuate over time, influenced by both AFSI variability and the resulting impact of the CAMT on other tax benefits, including potential near-term deferral of the realization of our existing NOL carryforwards. This could result in higher cash tax payments in the near-term relative to the year ended December 31, 2023. 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 Our Financial Mattersin Item 1A. Risk Factors.

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. However, in connection with reaching FID, we may be required to secure financing to meet the cash needs that such project will initially require, in support of commercializing the project.

Beyond the Corpus Christi Stage 3 Project, 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. We expect that any potential future expansion at the Corpus Christi LNG Terminal and the Sabine Pass LNG Terminal would increase cash requirements to support expanded operations, 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, 2023 (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, 2023. Debt and interest payments do not contemplate repurchases, repayments and retirements that we may make prior to contractual maturity.

Debt

As of December 31, 2023, our debt complex was comprised of senior notes with an aggregate outstanding principal balance of $23.9 billion and credit facilities with no outstanding loan balances. As of December 31, 2023, 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 11—Debt of our Notes to Consolidated Financial Statements.

Interest

As of December 31, 2023, our senior notes had a weighted average contractual interest rate of 4.73%. All of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities. 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 1.000% to 2.200%, subject to change based on the applicable entity’s credit rating. We had $435 million aggregate amount of issued letters of credit under our credit facilities as of December 31, 2023.

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, 2023, $1.0 billion in distributions were paid to our non-controlling interests.

Capital Allocation Plan

In September 2022, our Board approved a revised comprehensive long-term capital allocation plan. Pursuant to the revised capital allocation plan, on September 12, 2022 our Board authorized an increase in the existing share repurchase program by $4.0 billion for an additional three years, beginning on October 1, 2022. As of December 31, 2023, we had up to $2.1 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. During the year ended December 31, 2023, we repurchased a total of 9.5 million shares of our common stock for $1.5 billion at a weighted average price per share of $155.50. 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.

A further 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, 2023, we used $1.2 billion of available cash to reduce our outstanding indebtedness, all of which was pursuant to our capital allocation plan.

The capital allocation plan also includes a targeted annual dividend growth rate of approximately 10% through Corpus Christi Stage 3 Project construction. On January 26, 2024, we declared a quarterly dividend of $0.435 per share of common stock that is payable on February 23, 2024 to stockholders of record as of the close of business on February 6, 2024.

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.