10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

☒    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2023

or

☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from            to            

Commission file number 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)

Delaware	95-4352386
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

845 Texas Avenue, Suite 1250

Houston, Texas 77002

(Address of principal executive offices) (Zip Code)

(713) 375-5000

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act: 

Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock, $ 0.003 par value	LNG	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒   No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐   No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒   No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  ☒   No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ☐  No  ☒ 

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $36.5 billion as of June 30, 2023.

As of February 16, 2024, the issuer had 234,692,274 shares of Common Stock outstanding.

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

CHENIERE ENERGY, INC.

TABLE OF CONTENTS

PART I
Items 1. and 2. Business and Properties	4
Item 1A. Risk Factors	17
Item 1B. Unresolved Staff Comments	29
Item 1C. Cybersecurity	29
Item 3. Legal Proceedings	30
Item 4. Mine Safety Disclosure	30
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	31
Item 6. [Reserved]	33
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	33
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	50
Item 8. Financial Statements and Supplementary Data	51
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	97
Item 9A. Controls and Procedures	97
Item 9B. Other Information	97
Item 9C. Disclosure Regarding Foreign Jurisdictions That Prevent Inspections	97
PART III
Item 14. Principal Accountant Fees and Services	98
PART IV
Item 15. Exhibits and Financial Statement Schedules	99
Item 16. Form 10-K Summary	114
Signatures	115

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DEFINITIONS

As used in this annual report, the terms listed below have the following meanings: 

Common Industry and Other Terms

ASU	Accounting Standards Update
AFSI	adjusted financial statement income
Bcf	billion cubic feet
Bcf/d	billion cubic feet per day
Bcf/yr	billion cubic feet per year
Bcfe	billion cubic feet equivalent
CAMT	corporate alternative minimum tax
DAT	delivered at terminal
DOE	U.S. Department of Energy
EPC	engineering, procurement and construction
ESG	environmental, social and governance
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FID	final investment decision
FOB	free-on-board
FTA countries	countries with which the United States has a free trade agreement providing for national treatment for trade in natural gas
GAAP	generally accepted accounting principles in the United States
Henry Hub	the final settlement price (in U.S. dollars per MMBtu) for the New York Mercantile Exchange’s Henry Hub natural gas futures contract for the month in which a relevant cargo’s delivery window is scheduled to begin
IPM agreements	integrated production marketing agreements in which the gas producer sells to us gas on a global LNG or natural gas index price, less a fixed liquefaction fee, shipping and other costs
LIBOR	London Interbank Offered Rate
LNG	liquefied natural gas, a product of natural gas that, through a refrigeration process, has been cooled to a liquid state, which occupies a volume that is approximately 1/600th of its gaseous state
MMBtu	million British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
mtpa	million tonnes per annum
non-FTA countries	countries with which the United States does not have a free trade agreement providing for national treatment for trade in natural gas and with which trade is permitted
SEC	U.S. Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
SPA	LNG sale and purchase agreement
TBtu	trillion British thermal units; one British thermal unit measures the amount of energy required to raise the temperature of one pound of water by one degree Fahrenheit
Train	an industrial facility comprised of a series of refrigerant compressor loops used to cool natural gas into LNG
TUA	terminal use agreement

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Abbreviated Legal Entity Structure

The following diagram depicts our abbreviated legal entity structure as of December 31, 2023, including our ownership of certain subsidiaries, and the references to these entities used in this annual report:

Unless the context requires otherwise, references to “Cheniere,” the “Company,” “we,” “us” and “our” refer to Cheniere Energy, Inc. and its consolidated subsidiaries, including our publicly traded subsidiary, CQP.

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CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual 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 (the “Securities Act”), 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 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;

•any other statements that relate to non-historical or future information; and

•other factors described in Item 1A. Risk Factors in this Annual Report on Form 10-K.

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 annual 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 annual 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 annual report and in the other reports and other information that we file with the SEC. 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.

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PART I

ITEMS 1. AND 2.    BUSINESS AND PROPERTIES

General

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 (methane) in liquid form. The LNG we produce is shipped all over the world, turned 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, other industrial uses and back up for intermittent energy sources. Natural gas is a cleaner-burning, abundant and affordable source of energy. When LNG is converted back to natural gas, it can be used instead of coal, which reduces the amount of pollution traditionally produced from burning fossil fuels, like sulfur dioxide and particulate matter that enters the air we breathe. Additionally, compared to coal, it produces significantly fewer carbon emissions. By liquefying natural gas, we are able to reduce its volume by 600 times so that we can load it onto special LNG carriers designed to keep the LNG cold and in liquid form for efficient transport overseas.

We are the largest producer of LNG in the United States and the second largest LNG operator globally, based on the total production capacity of our liquefaction facilities, which totals approximately 45 mtpa as of December 31, 2023.

We own and operate a natural gas liquefaction and export facility located in Cameron Parish, Louisiana at Sabine Pass (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 that we formed in 2007. As of December 31, 2023, 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 has six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include 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 CTPL, a subsidiary of CQP, a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several interstate and intrastate pipelines (the “Creole Trail Pipeline”).

Additionally, we own and operate a natural gas liquefaction and export facility located near Corpus Christi, Texas (the “Corpus Christi LNG Terminal”) through CCL, which has natural gas liquefaction facilities consisting of three operational Trains for a total production capacity of approximately 15 mtpa of LNG, 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 are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own and operate through CCP a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).

Our long-term customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. We have contracted substantially all of our anticipated production capacity under 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 under IPM agreements, in which the 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 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, we have contracted approximately 95% of the total anticipated production from the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”) through the mid-2030s with approximately 16 years of weighted average remaining life as of

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December 31, 2023, 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. We also market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL through our integrated marketing function.

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. 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. In March 2023, certain of our subsidiaries submitted an application with the FERC under the Natural Gas Act (the “NGA”) for an expansion adjacent to the CCL Project consisting of two midscale Trains with an expected total production capacity of approximately 3 mtpa of LNG (the “CCL Midscale Trains 8 & 9 Project”). Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the National Environmental Policy Act (“NEPA”) for an expansion adjacent to the SPL Project with a potential production capacity of up to approximately 20 mtpa of total LNG capacity, inclusive of estimated debottlenecking opportunities (the “SPL Expansion Project”). The development of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project 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.

Our Business Strategy

Our primary business strategy is to be a full-service LNG provider to worldwide end-use customers. We accomplish this objective by owning, constructing and operating LNG and natural gas infrastructure facilities to meet our long-term customers’ energy demands and: 

•safely, efficiently and reliably operating and maintaining our assets;

•procuring natural gas and pipeline transport capacity to our facilities;

•providing value to our customers through destination flexibility, options not to lift cargoes and diversity of price and geography;

•continuing to secure long-term customer contracts to support our planned expansion, including the FID of potential expansion projects beyond the Corpus Christi Stage 3 Project;

•completing our construction projects safely, on-time and on-budget;

•maximizing the production of LNG to serve our customers and generating steady and stable revenues and operating cash flows;

•maintaining a flexible capital structure to finance the acquisition, development, construction and operation of the energy assets needed to supply our customers;

•executing our “all of the above” capital allocation strategy, focused on strengthening our balance sheet, funding financially disciplined growth and returning capital to our stockholders; and

•strategically identifying actionable and economic environmental solutions.

Our Business

We shipped our first LNG cargo in February 2016 and as of February 16, 2024, approximately 3,280 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects. Our LNG has been shipped to 39 countries and regions around the world.

Below is a discussion of our operations. For further discussion of our contractual obligations and cash requirements related to these operations, refer to Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

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Sabine Pass LNG Terminal

Liquefaction Facilities and Expansion Project

The Sabine Pass LNG Terminal, as described above under the caption General, is one of the largest LNG production facilities in the world with six Trains, five storage tanks and three marine berths. Additionally, in May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project.

The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the SPL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal through December 31, 2050:

	FERC Approved Volume		DOE Approved Volume
	(in Bcf/yr)	(in mtpa)	(in Bcf/yr)	(in mtpa)
FTA countries	1,661.94	33	1,661.94	33
Non-FTA countries	1,661.94	33	1,661.94	33

Natural Gas Supply, Transportation and Storage

SPL has secured natural gas feedstock for the SPL Project through long-term natural gas supply agreements, including an IPM agreement. SPL Stage V has also entered into an IPM agreement to supply the SPL Expansion Project, subject to Cheniere making a positive FID on the first train of the SPL Expansion Project. Additionally, to ensure that SPL is able to transport natural gas feedstock to the SPL Project and manage inventory levels, it has entered into firm pipeline transportation and storage contracts with third parties and CTPL.

Regasification Facilities

The Sabine Pass LNG Terminal, as described above under the caption General, has operational regasification capacity of approximately 4 Bcf/d and aggregate LNG storage capacity of approximately 17 Bcfe. SPLNG has a long-term, third party TUA for 1 Bcf/d with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), under which TotalEnergies is required to pay fixed monthly fees, whether or not it uses the regasification capacity it has reserved. Prior to its cancellation effective December 31, 2022, SPLNG also had a TUA for 1 Bcf/d with Chevron U.S.A. Inc. (“Chevron”). Approximately 2 Bcf/d of the remaining capacity has been reserved under a TUA by SPL, which also has a partial TUA assignment agreement with TotalEnergies, as further described in Note 13—Revenues of our Notes to Consolidated Financial Statements.

Corpus Christi LNG Terminal

Liquefaction Facilities and Expansion Projects

The Corpus Christi LNG Terminal, as described above under the caption General, includes three Trains, three storage tanks, two marine berths and the construction of the Corpus Christi Stage 3 Project with seven midscale Trains. Additionally, 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 following table summarizes the project completion and construction status of the Corpus Christi Stage 3 Project as of December 31, 2023:

Overall project completion percentage	51.4%
Completion percentage of:
Engineering	83.7%
Procurement	72.2%
Subcontract work	66.9%
Construction	11.1%
Date of expected substantial completion	2Q/3Q 2025 - 2H 2026

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The following summarizes the volumes of natural gas for which we have received approvals from the FERC to site, construct and operate the Trains at the CCL Project and the orders we have received from the DOE authorizing the export of domestically produced LNG by vessel from the Corpus Christi LNG Terminal through December 31, 2050:

	FERC Approved Volume		DOE Approved Volume
	(in Bcf/yr)	(in mtpa)	(in Bcf/yr)	(in mtpa)
Trains 1 through 3 of the CCL Project:
FTA countries	875.16	17	875.16	17
Non-FTA countries	875.16	17	875.16	17
Corpus Christi Stage 3 Project:
FTA countries	582.14	11.45	582.14	11.45
Non-FTA countries	582.14	11.45	582.14	11.45

Natural Gas Supply, Transportation and Storage

CCL has secured natural gas feedstock for the Corpus Christi LNG Terminal through long-term natural gas supply agreements, including IPM agreements. Additionally, to ensure that CCL is able to transport and manage the natural gas feedstock to the Corpus Christi LNG Terminal, it has entered into transportation precedent and other agreements to secure firm pipeline transportation and storage capacity from third parties and CCP.

Marketing

We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL to other customers through Cheniere Marketing, our integrated marketing function. We have, and continue to develop, a portfolio of long-, medium- and short-term SPAs to transport and deliver commercial LNG cargoes to locations worldwide.

Customers

The concentration of our customer credit risk in excess of 10% of total revenues was as follows:

	Percentage of Total Revenues from External Customers
	Year Ended December 31,
	2023	2022	2021
BG Gulf Coast LNG, LLC and affiliates	*	*	12%
Naturgy LNG GOM, Limited	*	*	12%
Korea Gas Corporation	*	*	10%

* Less than 10%

All of the above customers contribute to our LNG revenues through SPA contracts.

Additional information regarding our customer contracts can be found in Liquidity and Capital Resources in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Note 21—Customer Concentration of our Notes to Consolidated Financial Statements.

Governmental Regulation

Our LNG terminals and pipelines are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations. These rigorous regulatory requirements increase the cost of construction and operation, and failure to comply with such laws could result in substantial penalties and/or loss of necessary authorizations.

Federal Energy Regulatory Commission

The design, construction, operation, maintenance and expansion of our liquefaction facilities, the import or export of LNG and the purchase and transportation of natural gas in interstate commerce through our pipelines (including our Creole

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Trail Pipeline and Corpus Christi Pipeline) are highly regulated activities subject to the jurisdiction of the FERC pursuant to the NGA. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale for resale of natural gas in interstate commerce, to natural gas companies engaged in such transportation or sale and to the construction, operation, maintenance and expansion of LNG terminals and interstate natural gas pipelines.

The FERC’s authority to regulate interstate natural gas pipelines and the services that they provide generally includes regulation of:

•rates and charges, and terms and conditions for natural gas transportation, storage and related services;

•the certification and construction of new facilities and modification of existing facilities;

•the extension and abandonment of services and facilities;

•the administration of accounting and financial reporting regulations, including the maintenance of accounts and records;

•the acquisition and disposition of facilities;

•the initiation and discontinuation of services; and

•various other matters.

Under the NGA, our pipelines are not permitted to unduly discriminate or grant undue preference as to rates or the terms and conditions of service to any shipper, including our own marketing affiliates. Those rates, terms and conditions must be public, and on file with the FERC. In contrast to pipeline regulation, the FERC does not require LNG terminal owners to provide open-access services at cost-based or regulated rates. Although the provisions that codified the FERC’s policy in this area expired on January 1, 2015, we see no indication that the FERC intends to change its policy in this area. On February 18, 2022, the FERC updated its 1999 Policy Statement on certification of new interstate natural gas facilities and the framework for the FERC’s decision-making process, modifying the standards that the FERC uses to evaluate applications to include, among other things, reasonably foreseeable greenhouse gas (“GHG”) emissions that may be attributable to the project and the project’s impact on environmental justice communities. On March 24, 2022, the FERC rescinded the Policy Statement, re-issued it as a draft and it remains pending. At this time, we do not expect it to have a material adverse effect on our operations.

We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate granted by the FERC with the issuance of our Certificate of Public Convenience and Necessity to our marketing affiliates. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

In order to site, construct and operate our LNG terminals, we received and are required to maintain authorizations from the FERC under Section 3 of the NGA as well as other material governmental and regulatory approvals and permits. The Energy Policy Act of 2005 (the “EPAct”) amended Section 3 of the NGA to establish or clarify the FERC’s exclusive authority to approve or deny an application for the siting, construction, expansion or operation of LNG terminals, unless specifically provided otherwise in the EPAct amendments to the NGA. For example, nothing in the EPAct amendments to the NGA were intended to affect otherwise applicable law related to any other federal agency’s authorities or responsibilities related to LNG terminals or those of a state acting under federal law.

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

The FERC’s Standards of Conduct apply to interstate pipelines that conduct transmission transactions with an affiliate that engages in natural gas marketing functions. The general principles of the FERC Standards of Conduct are: (1) independent functioning, which requires transmission function employees to function independently of marketing function employees; (2) no-conduit rule, which prohibits passing transmission function information to marketing function employees; and (3) transparency, which imposes posting requirements to detect undue preference due to the improper disclosure of non-public transmission function information. We have established the required policies, procedures and training to comply with the FERC’s Standards of Conduct.

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All of our FERC construction, operation, reporting, accounting and other regulated activities are subject to audit by the FERC, which may conduct routine or special inspections and issue data requests designed to ensure compliance with FERC rules, regulations, policies and procedures. The FERC’s jurisdiction under the NGA allows it to impose civil and criminal penalties for any violations of the NGA and any rules, regulations or orders of the FERC up to approximately $1.3 million per day per violation, including any conduct that violates the NGA’s prohibition against market manipulation.

Several other governmental and regulatory approvals and permits are required throughout the life of our LNG terminals and our pipelines. In addition, our FERC orders require us to comply with certain ongoing conditions, reporting obligations and maintain other regulatory agency approvals throughout the life of our facilities. For example, throughout the life of our LNG terminals and our pipelines, we are subject to regular reporting requirements to the FERC, the Department of Transportation’s (“DOT”) Pipeline and Hazardous Materials Safety Administration (“PHMSA”) and applicable federal and state regulatory agencies regarding the operation and maintenance of our facilities. To date, we have been able to obtain and maintain required approvals as needed, and the need for these approvals and reporting obligations has not materially affected our construction or operations.

DOE Export Licenses

The DOE has authorized the export of domestically produced LNG by vessel from the Sabine Pass LNG Terminal, as discussed in Sabine Pass LNG Terminal—Liquefaction Facilities, and the Corpus Christi LNG Terminal, as discussed in Corpus Christi LNG Terminal—Liquefaction Facilities. Although it is not expected to occur, the loss of an export authorization could be a force majeure event under our SPAs.

Under Section 3 of the NGA, applications for exports of natural gas to FTA countries, which allow for national treatment for trade in natural gas, are “deemed to be consistent with the public interest” and shall be granted by the DOE without “modification or delay.” FTA countries currently recognized by the DOE for exports of LNG include Australia, Bahrain, Canada, Chile, Colombia, Dominican Republic, El Salvador, Guatemala, Honduras, Jordan, Mexico, Morocco, Nicaragua, Oman, Panama, Peru, Republic of Korea and Singapore. FTAs with Israel and Costa Rica do not require national treatment for trade in natural gas. Applications for export of LNG to non-FTA countries are considered by the DOE in a notice and comment proceeding whereby the public and other interveners are provided the opportunity to comment and may assert that such authorization would not be consistent with the public interest. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The CCL Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. We would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. See Sabine Pass LNG Terminal and Corpus Christi LNG Terminal sections above for FERC and DOE approved volumes on our existing Liquefaction Projects.

Pipeline and Hazardous Materials Safety Administration

Our LNG terminals as well as the Creole Trail Pipeline and the Corpus Christi Pipeline are subject to regulation by PHMSA. PHMSA is authorized by the applicable pipeline safety laws to establish minimum safety standards for certain pipelines and LNG facilities. The regulatory standards PHMSA has established are applicable to the design, installation, testing, construction, operation, maintenance and management of natural gas and hazardous liquid pipeline facilities and LNG facilities that affect interstate or foreign commerce. PHMSA has also established training, worker qualification and reporting requirements.

PHMSA performs inspections of pipeline and LNG facilities and has authority to undertake enforcement actions, including issuance of civil penalties up to approximately $266,000 per day per violation, with a maximum administrative civil penalty of approximately $2.7 million for any related series of violations.

Other Governmental Permits, Approvals and Authorizations

Construction and operation of the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal require additional permits, orders, approvals and consultations to be issued by various federal and state agencies, including the DOT, U.S. Army

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Corps of Engineers (“USACE”), U.S. Department of Commerce, National Marine Fisheries Service, U.S. Department of the Interior, U.S. Fish and Wildlife Service, the U.S. Environmental Protection Agency (the “EPA”), U.S. Department of Homeland Security, the Louisiana Department of Environmental Quality (the “LDEQ”), the Texas Commission on Environmental Quality (“TCEQ”) and the Railroad Commission of Texas.

The USACE issues its permits under the authority of the Clean Water Act (“CWA”) (Section 404) and the Rivers and Harbors Act (Section 10). The EPA administers the Clean Air Act (“CAA”), and has delegated authority to the TCEQ and LDEQ to issue the Title V Operating Permit and the Prevention of Significant Deterioration Permit. These two permits are issued by the LDEQ for the Sabine Pass LNG Terminal and CTPL and by the TCEQ for the CCL Project.

Commodity Futures Trading Commission (“CFTC”)

The Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act to provide for federal regulation of the over-the-counter derivatives market and entities, such as us, that participate in those markets. The CFTC has enacted a number of regulations pursuant to the Dodd-Frank Act, including the speculative position limit rules. Given the enactment of the speculative position limit rules, as well as the impact of other rules and regulations under the Dodd-Frank Act, the impact of such rules and regulations on our business continues to be uncertain, but is not expected to be material.

As required by the Dodd-Frank Act, the CFTC and federal banking regulators also adopted rules requiring swap dealers (as defined in the Dodd-Frank Act), including those that are regulated financial institutions, to collect initial and/or variation margin with respect to uncleared swaps from their counterparties that are financial end users, registered swap dealers or major swap participants. These rules do not require collection of margin from non-financial-entity end users who qualify for the end user exception from the mandatory clearing requirement or from non-financial end users or certain other counterparties in certain instances. We qualify as a non-financial-entity end user with respect to the swaps that we enter into to hedge our commercial risks.

Pursuant to the Dodd-Frank Act, the CFTC adopted additional anti-manipulation and anti-disruptive trading practices regulations that prohibit, among other things, manipulative, deceptive or fraudulent schemes or material misrepresentation in the futures, options, swaps and cash markets. In addition, separate from the Dodd-Frank Act, our use of futures and options on commodities is subject to the Commodity Exchange Act and CFTC regulations, as well as the rules of futures exchanges on which any of these instruments are executed. Should we violate any of these laws and regulations, we could be subject to a CFTC or an exchange enforcement action and material penalties, possibly resulting in changes in the rates we can charge.

United Kingdom / European Regulations

Our European trading activities, which are primarily established in and operated out of the United Kingdom (“U.K.”), are subject to a number of European Union (“EU”) and U.K. laws and regulations, including but not limited to:

•the European Market Infrastructure Regulation, which was designed to increase the transparency and stability of the European Economic Area (“EEA”) derivatives markets;

•the Regulation on Wholesale Energy Market Integrity and Transparency, which prohibits market manipulation and insider trading in EEA wholesale energy markets and imposes various transparency and other obligations on participants active in these markets;

•the Markets in Financial Instruments Directive and Regulation (“MiFID II”), which sets forth a financial services framework across the EEA, including rules for firms engaging in investment services and activities in connection with certain financial instruments, including a range of commodity derivatives; and

•the Market Abuse Regulation, which was implemented to create an enhanced market abuse framework, and which applies generally to all financial instruments listed or traded on EEA trading venues (“Traded Instruments”) as well as other over-the-counter financial instruments priced on, or impacting, the price or value of the Traded Instrument.

Following the U.K.'s departure from the EU (“Brexit”), the EU-wide rules that applied to the U.K. while it was a member of the EU (and during the transition period) have been replicated, subject to certain amendments, to create a parallel set of rules applicable only in the U.K. As a result, we are subject to two sets of substantively similar rules based on the same

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underlying legislation: (i) one set of rules that apply in the EEA (i.e. not including the U.K.) (the “EEA Rules”); and (ii) one set of rules that apply only in the U.K. (the “U.K. Onshored Rules”).

To the extent our trading activities have a nexus with the EEA, we comply with the EEA Rules. However, as our trading activities are primarily operated out of the U.K., the main rules that impact and apply to us on a day-to-day basis are the U.K. Onshored Rules.

In particular, under the U.K. Onshored Rules, firms engaging in investment services and activities under U.K. MiFID II must be authorized unless an exemption applies. We meet the criteria for an exemption and therefore do not need to be authorized under U.K. MiFID II.

In addition to the U.K. Onshored Rules, we are also subject to a separate, U.K.-specific regime that is not based on prior EU/EEA legislation. This is primarily set out in the U.K.’s Financial Services and Markets Act 2000 (“FSMA”) and Financial Services and Markets Act 2000 (Regulated Activities) Order 2001 (“RAO”), which, among other things, governs the regulation of financial services and markets in the U.K., and contains a definitive list of the specified kinds of activities and products that are regulated. Under these U.K.-specific rules, a firm engaging in regulated activities must be authorized unless an exclusion applies. We qualify under applicable exclusions and therefore are not required to be authorized under the U.K. FSMA/RAO regime.

In December 2022, the EU enacted regulations, which among other things established a market correction mechanism against excessively high LNG prices and provided for the collection of information though new reporting obligations that would be utilized to provide for a new LNG pricing assessment/benchmark. The applicable regulations are set forth in Council Regulation (EU) 2022/2576-2581. The impact of such regulations on our business remains uncertain, but is not expected to be material.

Violation of the foregoing laws and regulations could result in investigations, possible fines and penalties, and in some scenarios, criminal offenses, as well as reputational damage.

Brexit and Equivalence

As referenced above, the U.K. ceased to be a member of the EU on January 31, 2020. On December 24, 2020, the EU and the U.K. reached an agreement in principle on the terms of certain agreements and declarations governing the ongoing relationship between the EU and the U.K., including the EU-U.K. Trade and Cooperation Agreement (the “TCA”). The TCA is limited in its scope; in particular the TCA does not make any meaningful provision for the financial services sector. Uncertainties remain relating to certain aspects of the U.K.’s future economic, trading and legal relationships with the EU and with other countries.

The Financial Services and Markets Act 2023 (“FSMA 2023”) came into U.K. law in June 2023. FSMA 2023 is the framework for the U.K.’s post-Brexit financial legislative and regulatory landscape. It is intended to provide the foundations for a significant overhaul and re-structuring of the U.K. financial services and markets regimes. The changes include the revocation of retained EU laws, the introduction of new powers and objectives for the regulators of such markets, as well as a number of measures relevant to financial market infrastructure operators and market participants. Changes will be implemented pursuant to subsidiary legislation or directly by regulators. However, at this time it is not possible to determine whether any such actions would have a material impact on our business.

Environmental Regulation

Our LNG terminals are subject to various federal, state and local laws and regulations relating to the protection of the environment and natural resources. These environmental laws and regulations can affect the cost and output of operations and may impose substantial penalties for non-compliance and substantial liabilities for pollution, as further described in the risk factor Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions in Risks Relating to Regulations within Item 1A. Risk Factors. Many of these laws and regulations, such as those noted below, restrict or prohibit impacts to the environment or the types, quantities and concentration of substances that can be released into the environment and can lead to substantial administrative, civil and criminal fines and penalties for non-compliance.

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Clean Air Act

Our LNG terminals are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing air emission-related issues. However, we do not believe any such requirements will have a material adverse effect on our operations, or the construction and operations of our liquefaction facilities.

On February 28, 2022, the EPA removed a stay of formaldehyde standards in the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) Subpart YYYY for stationary combustion turbines located at major sources of hazardous air pollutant (“HAP”) emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that the construction and operations of our liquefaction facilities will be materially and adversely affected by such regulatory actions.

We are supportive of regulations reducing GHG emissions over time. Since 2009, the EPA has promulgated and finalized multiple GHG emissions regulations related to reporting and reductions of GHG emissions from our facilities. On December 2, 2023, the EPA issued final rules to reduce methane and volatile organic compounds (“VOC”) emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. We do not believe such regulations will have a material adverse effect on our operations, financial condition or results of operations.

From time to time, Congress has considered proposed legislation directed at reducing GHG emissions. On August 16, 2022, President Biden signed H.R. 5376(P.L. 117-169), the Inflation Reduction Act of 2022 (“IRA”) which includes a charge on methane emissions above a certain methane intensity threshold for facilities that report their GHG emissions under the EPA’s Greenhouse Gas Emissions Reporting Program Part 98 regulations. The charge starts at $900 per metric ton of methane in 2024, $1,200 per metric ton in 2025, and increasing to $1,500 per metric ton in 2026 and beyond. In January 2024, the EPA issued a proposed rule to impose and collect the methane emissions charge authorized under the IRA. We do not believe the methane charge will have a material adverse effect on our operations, financial condition or results of operations.

Coastal Zone Management Act (“CZMA”)

The siting and construction of our LNG terminals within the coastal zone is subject to the requirements of the CZMA. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the General Land Office). This program is implemented to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act

Our LNG terminals are subject to the federal CWA and analogous state and local laws. The CWA imposes strict controls on the discharge of pollutants into the navigable waters of the United States, including discharges of wastewater and storm water runoff and fill/discharges into waters of the United States. Permits must be obtained prior to discharging pollutants into state and federal waters. The CWA is administered by the EPA, the USACE and by the states (in Louisiana, by the LDEQ, and in Texas, by the TCEQ). The CWA regulatory programs, including the Section 404 dredge and fill permitting program and Section 401 water quality certification program carried out by the states, are frequently the subject of shifting agency interpretations and legal challenges, which at times can result in permitting delays.

Resource Conservation and Recovery Act (“RCRA”)

The federal RCRA and comparable state statutes govern the generation, handling and disposal of solid and hazardous wastes and require corrective action for releases into the environment. When such wastes are generated in connection with the operations of our facilities, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

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Protection of Species, Habitats and Wetlands

Various federal and state statutes, such as the Endangered Species Act, the Migratory Bird Treaty Act, the CWA and the Oil Pollution Act, prohibit certain activities that may adversely affect endangered or threatened animal, fish and plant species and/or their designated habitats, wetlands, or other natural resources. If one of our LNG terminals or pipelines adversely affects a protected species or its habitat, we may be required to develop and follow a plan to avoid those impacts. In that case, siting, construction or operations may be delayed or restricted and cause us to incur increased costs.

It is not possible at this time to predict how future regulations or legislation may address protection of species, habitats and wetlands and impact our business. However, we do not believe such regulatory actions will have a material adverse effect on our operations, or the construction and operations of our liquefaction facilities.

Market Factors and Competition

Market Factors

Our ability to enter into additional long-term SPAs to underpin the development of additional Trains, sell LNG through Cheniere Marketing or develop new projects is subject to market factors. These factors include changes in worldwide supply and demand for natural gas, LNG and substitute products, the relative prices for natural gas, crude oil and substitute products in North America and international markets, the extent of energy security needs in the EU and elsewhere, the rate of fuel switching for power generation from coal, nuclear or oil to natural gas and other overarching factors such as global economic growth and the pace of any transition from fossil-based systems of energy production and consumption to alternative energy sources. In addition, our ability to obtain additional funding to execute our business strategy is subject to the investment community’s appetite for investment in LNG and natural gas infrastructure and our ability to access capital markets.

We expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Market participants around the globe have shown commitments to environmental goals consistent with many policy initiatives that we believe are constructive for LNG demand and infrastructure growth. Currently, significant amounts of money are being invested across Europe, Asia and Latin America in natural gas projects under construction, and more continues to be earmarked to planned projects globally. In Europe, there are various plans to install more than 85 mtpa of import capacity over the near-term to secure access to LNG and displace Russian gas imports. In India, there are more than 11,000 kilometers of gas pipelines under construction to expand the gas distribution network and increase access to natural gas. And in China, billions of U.S. dollars have already been invested and hundreds of billions of U.S. dollars are expected to be further invested all along the natural gas value chain to enable growth and decrease harmful emissions. Furthermore, some of the existing integrated liquefaction facilities outside of the U.S. have been experiencing issues related to reduced feed gas as a result of depleting upstream resources. Global supply contributions from these plants have been decreasing and LNG supply growth is expected to help support these shortages.

As a result of these dynamics, we expect natural gas and LNG to continue to play an important role in satisfying energy demand going forward. In its forecast published in the third quarter of 2023, Wood Mackenzie Limited (“WoodMac”) forecasted that global demand for LNG would increase by approximately 60%, from approximately 411 mtpa, or 19.7 Tcf, in 2022, to 657 mtpa, or 31.5 Tcf, in 2040 and to 709 mtpa or 34 Tcf in 2050. In its forecast published in the third quarter of 2023, WoodMac also forecasted LNG production from existing operational facilities and new facilities already under construction would be able to supply the market with approximately 544 mtpa in 2040, declining to 477 mtpa in 2050. This could result in a market need for construction of an additional approximately 113 mtpa of LNG production by 2040 and about 231 mtpa by 2050. As a cleaner burning fuel with lower emissions than coal or liquid fuels in power generation, we expect natural gas and LNG to play a central role in balancing grids, serving as back up for intermittent energy sources and contributing to a low carbon energy system globally. We believe the capital and operating costs of the uncommitted capacity of our Liquefaction Projects, as well as our proposed expansions at Sabine Pass and Corpus Christi, are competitive with new proposed projects globally and we are well-positioned to capture a portion of this incremental market need.

We have limited exposure to oil price movements as we have contracted a significant portion of our LNG production capacity under long-term sale and purchase agreements indexed to Henry Hub. These agreements contain fixed fees that are required to be paid even if the customers elect to cancel or suspend delivery of LNG cargoes.  Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, excluding volumes

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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.

Competition

Despite the long term nature of our SPAs, when SPL, CCL or our integrated marketing function need to replace or amend any existing SPA or enter into new SPAs, they will compete with each other and other natural gas liquefaction projects throughout the world on the basis of price per contracted volume of LNG at that time. Revenues associated with any incremental volumes, including those sold by our integrated marketing function, will also be subject to market-based price competition. Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to LNG markets than us.

Corporate Responsibility

As described in Market Factors and Competition, we expect that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to oil and coal. Our vision is to provide clean, secure and affordable energy to the world. This vision underpins our focus on responding to the world’s shared energy challenges—expanding the global supply of clean, secure and affordable energy, improving air quality, reducing emissions and supporting the transition to a lower-carbon future. Our approach to corporate responsibility is guided by our Climate and Sustainability Principles: Transparency, Science, Supply Chain and Operational Excellence. In August 2023, we published The Power of Connection, our fourth Corporate Responsibility (“CR”) report, which details our approach and progress on ESG matters. Our CR report is available at www.cheniere.com/our-responsibility/reporting-center. Information on our website, including the CR report, is not incorporated by reference into this Annual Report on Form 10-K. For further discussion on social and governance matters, see Human Capital Resources.

Our climate strategy is to measure and mitigate emissions – to better position our LNG supplies to remain competitive in a lower carbon future, providing energy, economic and environmental security to our customers across the world. To maximize the environmental benefits of our LNG, we believe it is important to develop future climate goals and strategies based on an accurate and holistic assessment of the emissions profile of our LNG, accounting for all steps in the supply chain.

Consequently, we have collaborated with natural gas midstream companies, technology providers and leading academic institutions on life-cycle assessment (“LCA”) models, quantification, monitoring, reporting and verification (“QMRV”) of GHG emissions and other research and development projects. We also co-founded and sponsored the Energy Emissions Modeling and Data Lab (“EEMDL”), a multidisciplinary research and education initiative led by the University of Texas at Austin in collaboration with Colorado State University and the Colorado School of Mines. In addition, we commenced providing Cargo Emissions Tags (“CE Tags”) to our long-term customers in June 2022, and in October 2022 joined the Oil and Gas Methane Partnership (“OGMP”) 2.0, the United Nations Environment Programme’s (“UNEP”) flagship oil and gas methane emissions reporting and mitigation initiative.

Our total incremental expenditures related to climate initiatives, including capital expenditures, were not material to our Consolidated Financial Statements during the years ended December 31, 2023, 2022 and 2021. However, as governments consider and implement actions to reduce GHG emissions and the transition to a lower-carbon economy continues to evolve, as described in Market Factors and Competition, we expect the scope and extent of our future climate and sustainability initiatives to evolve accordingly. While we have not incurred material direct expenditures related to climate change, we are proactive in our management of climate risks and opportunities, including compliance with existing and future government regulations. We face certain business and operational risks associated with physical impacts from climate change, such as exposure to severe weather events or changes in weather patterns, in addition to transition risks. Please see Item 1A. Risk Factors for additional discussion.

Subsidiaries

Substantially all of our assets are held by our subsidiaries. We conduct most of our business through these subsidiaries, including the development, construction and operation of our LNG terminal business and the development and operation of our LNG and natural gas marketing business.

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Human Capital Resources

We are in a unique position as the first U.S. LNG company in the lower 48. As the first mover, we invest in the core human capital priorities — attracting, engaging and developing diverse talent and building an inclusive and equitable workplace — because they underpin our current and future success and ability to generate long-term value.

As of December 31, 2023, we had 1,605 full-time employees with 1,511 located in the U.S. and 94 located outside of the U.S. (primarily in the U.K.).

Our strength comes from the collective expertise of our diverse workforce and through our core values of teamwork, respect, accountability, integrity, nimble and safety (“TRAINS”). Our employees help drive our success, build our reputation, establish our legacy and deliver on our commitments to our customers. Through fulfilling career opportunities, training, development and a competitive compensation program, we aim to keep our employees engaged. Our voluntary turnover was 6.1% for 2023.

Our Chief Human Resources Officer oversees human capital management. This includes our approach to talent attraction and retention, rewards and remuneration, employee relations, employee engagement and training and development. Our Chief Compliance and Ethics Officer oversees the diversity, equity and inclusion (“DEI”) program. Both officers communicate progress on our programs to our board of directors (our “Board”) quarterly.  

Talent Attraction, Engagement and Retention

Our recruitment strategy is focused on attracting diverse and highly skilled talent. We offer competitive compensation and benefits, and work to develop and attract a strong talent pipeline through a range of internship, apprenticeship and vocational programs. We invest in opportunities to help local students and underserved communities gain specialized skills and create local jobs through sponsorship of apprenticeships and internships. On an annual basis, we participate in workforce availability studies in the geographic areas where we operate to ensure representation of the local workforce. Internally and externally, we post openings to attract individuals with a range of backgrounds, skills and experience, offering employee bonuses for referring highly qualified candidates.

We manage and measure organizational health with a view to gaining insight into employees’ experiences, levels of workplace satisfaction and feelings of engagement and inclusion with the company. Employees are encouraged to share ideas and concerns through multiple feedback channels including townhalls and hotlines which can be reached anonymously. Insights from these channels are used to develop both company-wide and business unit level talent development plans and training programs.

Compensation and Benefits

We provide robust compensation and benefits programs to our employees. In addition to salaries, all employees are eligible for annual bonuses and stock awards. Benefit plans, which vary by country, include a 401(k) plan, healthcare and insurance benefits, health savings and flexible spending accounts, paid time off, family leave, family care resources, employee assistance programs and tuition assistance. We link our annual incentive program to financial and non-financial performance metrics, including but not limited to, ESG and DEI performance criteria.

Diversity, Equity and Inclusion

We are committed to supporting a diverse and inclusive culture where all employees can thrive and feel welcomed and valued. To create this environment, we are committed to equal employment opportunity and to compliance with all federal, state and local laws that prohibit workplace discrimination, harassment and unlawful retaliation. Our Code of Business Conduct and Ethics, our TRAINS values and both our discrimination and harassment and equal employment opportunity policies demonstrate our commitment to building an inclusive workplace, regardless of race, beliefs, nationality, gender and sexual orientation or any other status protected by our policy. We are committed to providing fair and equitable employee programs including compensation and benefits. We provide executives and senior management with DEI training and Unconscious Bias training to all employees. In addition, we will continue our “Values in Action” efforts, which supports employees in identifying and implementing actions and behaviors that align with our TRAINS values.

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Through our strategic recruitment efforts, we attract a variety of candidates with a diversity of backgrounds, skills, experience and expertise. Since 2019, we have had a 28.4% increase in racially or ethnically diverse employees and a 42% increase in racially or ethnically diverse management. In the past five years, the percentage of female employees remained steady at 26%. In 2023, we contributed over $1 million to DEI community efforts, of which approximately $250,000 was used to fund scholarship programs for students attending historically black colleges and universities in our communities. In addition, scholarship recipients are provided the opportunity to network with employees and apply for summer internships. We also committed to other scholarships and community efforts furthering our commitment to DEI.

We encourage our employees to leverage their unique backgrounds through involvement in various employee resource groups and employee networks. Groups such as WILS (Women Inspiring Leadership Success), EPN (Emerging Professional Network), Cultural Champions Teams and MVN (Military and Veterans Network), our newest employee resource group focused on military veterans help build a culture of inclusion.

Development and Training

As the first exporter of LNG in the lower 48 of the US, we faced the unique challenge of developing our own LNG talent. Our apprenticeship program prepares local students for careers in LNG. This program combines classroom education with training and on-site learning experiences at our facilities.

We strive to provide our people with all of the tools and support necessary for them to succeed. We actively encourage our employees to take ownership of their careers and offer a number of resources to do so. Employees receive mid-year and annual performance reviews, as well as frequent informal discussions to help meet their career goals. We also conduct annual talent reviews and succession planning sessions to ensure future organizational talent trends are met. To ensure safe, reliable and efficient operations in a highly regulated environment, we offer online and site-specific learning opportunities. We also provide employees, leaders and executives with targeted development programming to solidify internal talent pipelines and succession plans.

Employee Safety, Health and Wellness

The safety of our employees, contractors and communities is one of our core values, and is carried out through our required safety programs and safety and health related procedures. Safety efforts are led by our Executive Safety Committee, which includes the Chief Executive Officer, senior leaders from across the company and representatives from our sites. We focus our efforts on continuously improving our performance. For the year ended December 31, 2023, we had zero employee recordable injuries and five contractor recordable injuries. Our total recordable incident rate (employees and contractors combined) was 0.10, placing us in the top quartile of industry benchmarks based on Bureau of Labor safety statistics.

To support the well-being of our employees, we provide a wellness program that offers employees incentives to maintain an active lifestyle and set personal wellness goals. Incentives include online education related to health, nutrition, emotional health and vaccinations, as well as subsidies for fitness devices and gym memberships. We also offer mammography screenings, rooms for nursing mothers and biometric screenings on site.

Available Information

Our common stock has been publicly traded since March 24, 2003 and is traded on the New York Stock Exchange under the symbol “LNG.” Our principal executive offices are located at 845 Texas Avenue, Suite 1250, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the SEC under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our annual report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 845 Texas Avenue Suite 1250, Houston, Texas 77002 or call (713) 375-5000. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers.

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Additionally, we encourage you to review our CR Report (located on our internet site at www.cheniere.com), for more detailed information regarding our Human Capital programs and initiatives, as well as our initiatives and metrics related to ESG. Nothing on our website, including our CR Report or sections thereof, shall be deemed incorporated by reference into this Annual Report.

ITEM 1A.    RISK FACTORS

The following are some of the important factors that should be considered when investing in us, as such risk factors could adversely affect our business, financial condition, results of operation or cash flows or have other adverse impacts, and could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also adversely affect our business, contracts, financial condition, operating results, cash flows, liquidity and prospects.

The risk factors in this report are grouped into the following categories:

•Risks Relating to Our Financial Matters;

•Risks Relating to Our Operations and Industry; and

•Risks Relating to Regulations.

Risks Relating to Our Financial Matters

An inability to source capital to supplement our available cash resources and existing credit facilities could cause us to have inadequate liquidity and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

As of December 31, 2023, we had, on a consolidated basis, $4.1 billion of cash and cash equivalents (of which $575 million was held by CQP), $459 million of restricted cash and cash equivalents (of which $56 million was held by CQP), a total of $7.6 billion of available commitments under our credit facilities and $23.9 billion of total debt outstanding (before unamortized discount and debt issuance costs). SPL, CQP, CCH and Cheniere operate with independent capital structures as further detailed in Note 11—Debt of our Notes to Consolidated Financial Statements. We incur, and will incur, significant interest expense relating to financing the assets at the Sabine Pass LNG Terminal and the Corpus Christi LNG Terminal, and we anticipate drawing on current committed facilities and/or incurring additional debt to finance the construction of the Corpus Christi Stage 3 Project, as well as the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project if a positive FID is made on these expansion projects. Our ability to fund our capital expenditures and refinance our indebtedness will depend on our ability to access additional project financing as well as the debt and equity capital markets. A variety of factors beyond our control could impact the availability or cost of capital, including domestic or international economic conditions, increases in key benchmark interest rates and/or credit spreads, the adoption of new or amended banking or capital market laws or regulations, lending institutions’ evolving policies on financing businesses linked to fossil fuels and the repricing of market risks and volatility in capital and financial markets. Our financing costs could increase or future borrowings or equity offerings may be unavailable to us or unsuccessful, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs. We also rely on borrowings under our credit facilities to fund our capital expenditures. If any of the lenders in the syndicates backing these facilities was unable to perform on its commitments, we may need to seek replacement financing, which may not be available as needed, or may be available in more limited amounts or on more expensive or otherwise unfavorable terms.

Our ability to generate cash is substantially dependent upon the performance by customers under long-term contracts that we have entered into, and we could be materially and adversely affected if any significant portion of our customers fails to perform its contractual obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by our customers to make payments under long-term contracts. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers.

While substantially all of our long-term third party customer arrangements are executed with a creditworthy parent company or secured by a parent company guarantee or other form of collateral, we are nonetheless exposed to credit risk in the event of a customer default that requires us to seek recourse.

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Additionally, our long-term SPAs entitle the customer to terminate their contractual obligations upon the occurrence of certain events which include, but are not limited to: (1) if we fail to make available specified scheduled cargo quantities; (2) delays in the commencement of commercial operations; and (3) under the majority of our SPAs, upon the occurrence of certain events of force majeure.

Although we have not had a history of material customer default or termination events, the occurrence of such events are largely outside of our control and may expose us to unrecoverable losses. We may not be able to replace these customer arrangements on desirable terms, or at all, if they are terminated. As a result, our business, contracts, financial condition, operating results, cash flow, liquidity and prospects could be materially and adversely affected.

Our subsidiaries may be restricted under the terms of their indebtedness from making distributions under certain circumstances, which may limit CQP’s ability to pay or increase distributions to us or inhibit our access to cash flows from the CCL Project and could materially and adversely affect us.

The agreements governing our subsidiaries’ indebtedness restrict payments that our subsidiaries can make to CQP or us in certain events. For example, SPL is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied.

CCH is restricted from making distributions under agreements governing its indebtedness generally unless, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a debt service coverage ratio of 1.25:1.00 is satisfied. In addition, prior to completion of the Corpus Christi Stage 3 Project, CCH is also required to confirm that it has sufficient funds, including senior debt commitments, equity funding and projected contracted cash flows from the fixed price component of its third party SPAs, to meet remaining expenditures required for the Corpus Christi Stage 3 Project in order to achieve completion by a certain specified date.

Our subsidiaries’ inability to pay distributions to CQP or us as a result of the foregoing restrictions in the agreements governing their indebtedness may inhibit CQP’s ability to pay or increase distributions to us and its other unitholders or inhibit our access to cash flows from the CCL Project, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our efforts to manage commodity and financial risks through derivative instruments, including our IPM agreements, could adversely affect our earnings reported under GAAP and our liquidity.

We use derivative instruments to manage commodity, currency and financial market risks. The extent of our derivative position at any given time depends on our assessments of the markets for these commodities and related exposures. We currently account for our derivatives at fair value, with immediate recognition of changes in the fair value in earnings, as described in Note 2—Summary of Significant Accounting Policies of our Notes to Consolidated Financial Statements. Such valuations are primarily valued based on estimated forward commodity prices and are more susceptible to variability particularly when markets are volatile, which could have a significant adverse effect on our earnings reported under GAAP. For example, as described in Results of Operations in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, our net income for the year ended December 31, 2022 included $5.7 billion of losses resulting from changes in the fair values of our derivatives, of which substantially all of such losses were related to commodity derivative instruments indexed to international LNG prices, mainly our IPM agreements.

These transactions and other derivative transactions have and may continue to result in substantial volatility in results of operations reported under GAAP, particularly in periods of significant commodity, currency or financial market variability. For certain of these instruments, in the absence of actively quoted market prices and pricing information from external sources, the value of these financial instruments involves management’s judgment or use of estimates. Changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

In addition, our liquidity may be adversely impacted by the cash margin requirements of the commodities exchanges or the failure of a counterparty to perform in accordance with a contract. As of December 31, 2023 and 2022, we had collateral posted with counterparties by us of $18 million and $134 million, respectively, which are included in margin deposits in our Consolidated Balance Sheets.

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Restrictions in agreements governing us and our subsidiaries’ indebtedness may prevent us and our subsidiaries from engaging in certain beneficial transactions, which could materially and adversely affect us.

In addition to restrictions on the ability of us, CQP, SPL and CCH to make distributions or incur additional indebtedness, the agreements governing our indebtedness also contain various other covenants that may prevent us from engaging in beneficial transactions, including limitations on our ability to:

•make certain investments;

•purchase, redeem or retire equity interests;

•issue preferred stock;

•sell or transfer assets;

•incur liens;

•enter into transactions with affiliates;

•consolidate, merge, sell or lease all or substantially all of our assets; and

•enter into sale and leaseback transactions.

Any restrictions on the ability to engage in beneficial transactions could materially and adversely affect us.

Our ability to declare and pay dividends and repurchase shares is subject to certain considerations.

Dividends are authorized and determined by our Board in its sole discretion and depend upon a number of factors, including:

•Cash available for distribution;

•Our results of operations and anticipated future results of operations;

•Our financial condition, especially in relation to the anticipated future capital needs of any expansion of our Liquefaction Facilities;

•The level of distributions paid by comparable companies;

•Our operating expenses; and

•Other factors our Board deems relevant.

We expect to continue to pay quarterly dividends to our stockholders; however, our Board may reduce our dividend or cease declaring dividends at any time, including if it determines that our current or forecasted future cash flows provided by our operating activities, after deducting capital expenditures, investments and other commitments, are not sufficient to pay our desired levels of dividends to our stockholders or to pay dividends to our stockholders at all.

Additionally as of December 31, 2023, $2.1 billion of repurchase authority remained under our share repurchase program our Board had authorized. Our share repurchase program does not obligate us to acquire a specific number of shares during any period, and our decision to commence, discontinue or resume repurchases in any period will depend on the same factors that our Board may consider when declaring dividends, among others.

Any downward revision in the amount of dividends we pay to stockholders or the number of shares we purchase under our share repurchase program could have an adverse effect on the market price of our common stock.

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Risks Relating to Our Operations and Industry

Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us.

Weather events such as major hurricanes and winter storms have caused interruptions or temporary suspension in construction or operations at our facilities or caused minor damage to our facilities. Our risk of loss related to weather events or other disasters is limited by contractual provisions in our SPAs, which can provide under certain circumstances relief from operational events, and partially mitigated by insurance we maintain. Aggregate direct and indirect losses associated with the aforementioned weather events, net of insurance reimbursements, have not historically been material to our Consolidated Financial Statements, and we believe our insurance coverages maintained, existence of certain protective clauses within our SPAs and other risk management strategies mitigate our exposure to material losses. However, future adverse weather events and collateral effects, or other disasters such as explosions, fires, floods or severe droughts, could cause damage to, or interruption of operations at our terminals or related infrastructure, which could impact our operating results, increase insurance premiums or deductibles paid and delay or increase costs associated with the construction and development of the Liquefaction Projects or our other facilities. Our LNG terminal infrastructure and LNG facilities located in or near Corpus Christi, Texas and Sabine Pass, Louisiana are designed in accordance with requirements of 49 Code of Federal Regulations Part 193, Liquefied Natural Gas Facilities: Federal Safety Standards, and all applicable industry codes and standards.

Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We depend upon third party pipelines and other facilities that provide gas delivery options to our liquefaction facilities and pipelines. If any pipeline connection were to become unavailable for current or future volumes of natural gas due to repairs, damage to the facility, lack of capacity, failure to replace contracted firm pipeline transportation capacity on economic terms, or any other reason, our ability to receive natural gas volumes to produce LNG or to continue shipping natural gas from producing regions or to end markets could be adversely impacted. Such disruptions to our third party supply of natural gas may also be caused by weather events or other disasters described in the risk factor Catastrophic weather events or other disasters could result in an interruption of our operations, a delay in the construction of our Liquefaction Projects, damage to our Liquefaction Projects and increased insurance costs, all of which could adversely affect us. While certain contractual provisions in our SPAs can limit the potential impact of disruptions, and historical indirect losses incurred by us as a result of disruptions to our third party supply of natural gas have not been material, any significant disruption to our natural gas supply where we may not be protected could result in a substantial reduction in our revenues under our long-term SPAs or other customer arrangements, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We may not be able to purchase or receive physical delivery of sufficient natural gas to satisfy our delivery obligations under the SPAs, which could have a material adverse effect on us.

Under the SPAs with our customers, we are required to make available to them a specified amount of LNG at specified times. The supply of natural gas to our Liquefaction Projects to meet our LNG production requirements timely and at sufficient quantities is critical to our operations and the fulfillment of our customer contracts. However, we may not be able to purchase or receive physical delivery of natural gas as a result of various factors, including non-delivery or untimely delivery by our suppliers, depletion of natural gas reserves within regional basins and disruptions to pipeline operations as described in the risk factor Disruptions to the third party supply of natural gas to our pipelines and facilities could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Our risk is in part mitigated by the diversification of our natural gas supply and transportation across suppliers and pipelines, and regionally across basins, and additionally, we have provisions within our supplier contracts that provide certain protections against non-performance. Further, provisions within our SPAs provide certain protection against force majeure events. While historically we have not incurred significant or prolonged disruptions to our natural gas supply that have resulted in a material adverse impact to our operations, due to the criticality of natural gas supply to our production of LNG, our failure to purchase or receive physical delivery of sufficient quantities of natural gas under circumstances where we may not be protected could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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Our ability to complete development and/or construction of additional Trains, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, will be contingent on our ability to obtain additional funding. If we are unable to obtain sufficient funding, we may be unable to fully execute our business strategy.

We continuously pursue liquefaction expansion opportunities and other projects along the LNG value chain. As described further in Items 1. and 2. Business and Properties, we are currently developing the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project. The commercial development of an LNG facility takes a number of years and requires a substantial capital investment that is dependent on sufficient funding and commercial interest, among other factors.

We will require significant additional funding to be able to commence construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and any additional expansion projects, which we may not be able to obtain at a cost that results in positive economics, or at all. The inability to achieve acceptable funding may cause a delay in the development or construction of the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project or any additional expansion projects, and we may not be able to complete our business plan, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Cost overruns and delays in the completion of our expansion projects, including the Corpus Christi Stage 3 Project, the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, as well as difficulties in obtaining sufficient financing to pay for such costs and delays, could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our investment decision on the Corpus Christi Stage 3 Project and any potential future expansion of LNG facilities, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, relies on cost estimates developed initially through front end engineering and design studies. However, due to the size and duration of construction of an LNG facility, the actual construction costs may be significantly higher than our current estimates as a result of many factors, including but not limited to changes in scope, the ability of Bechtel Energy Inc. (“Bechtel”) and our other contractors to execute successfully under their agreements, changes in commodity prices (particularly nickel and steel), escalating labor costs and the potential need for additional funds to be expended to maintain construction schedules or comply with existing or future environmental or other regulations. As construction progresses, we may decide or be forced to submit change orders to our contractor that could result in longer construction periods, higher construction costs or both, including change orders to comply with existing or future environmental or other regulations. Additionally, our SPAs generally provide that the customer may terminate that SPA if the relevant Train does not timely commence commercial operations. As a result, any significant construction delay, whatever the cause, could have a material adverse impact on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Significant increases in the cost of a liquefaction project beyond the amounts that we estimate could impact the commercial viability of the project as well as require us to obtain additional sources of financing to fund our operations until the applicable liquefaction project is fully constructed (which could cause further delays), thereby negatively impacting our business and limiting our growth prospects. While historically we have not experienced cost overruns or construction delays that have had a significant adverse impact on our operations, factors giving rise to such events in the future may be outside of our control and could have a material adverse effect on our current or future business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are subject to significant construction and operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals and our pipelines are, and will be, subject to the inherent risks associated with these types of operations as discussed throughout our risk factors, including explosions, breakdowns or failures of equipment, operational errors by vessel or tug operators, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

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We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. Although losses incurred as a result of self insured risk have not been material historically, the occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We are dependent on our EPC partners and other contractors for the successful completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project.

Timely and cost-effective completion of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, in compliance with agreed specifications is central to our business strategy and is highly dependent on the performance of our EPC partners, including Bechtel, and our other contractors under their agreements. The ability of our EPC partners and our other contractors to perform successfully under their agreements is dependent on a number of factors, including their ability to:

•design and engineer each Train to operate in accordance with specifications;

•engage and retain third party subcontractors and procure equipment and supplies;

•respond to difficulties such as equipment failure, delivery delays, schedule changes and failure to perform by subcontractors, some of which are beyond their control;

•attract, develop and retain skilled personnel, including engineers;

•post required construction bonds and comply with the terms thereof;

•manage the construction process generally, including coordinating with other contractors and regulatory agencies; and

•maintain their own financial condition, including adequate working capital.

Although some agreements may provide for liquidated damages if the contractor fails to perform in the manner required with respect to certain of its obligations, the events that trigger a requirement to pay liquidated damages may delay or impair the operation of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, and any liquidated damages that we receive may not be sufficient to cover the damages that we suffer as a result of any such delay or impairment. The obligations of EPC partners and our other contractors to pay liquidated damages under their agreements are subject to caps on liability, as set forth therein.

Furthermore, we may have disagreements with our contractors about different elements of the construction process, which could lead to the assertion of rights and remedies under their contracts and increase the cost of the Corpus Christi Stage 3 Project and any potential expansion projects, including the CCL Midscale Trains 8 & 9 Project and the SPL Expansion Project, or result in a contractor’s unwillingness to perform further work. If any contractor is unable or unwilling to perform according to the negotiated terms and timetable of its respective agreement for any reason or terminates its agreement, we would be required to engage a substitute contractor. This would likely result in significant project delays and increased costs, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

There may be impediments to the transport of LNG, such as shortages of LNG vessels worldwide or operational impacts on LNG shipping, which could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

We sell a significant amount of our LNG under delivered at terminal (“DAT”) terms requiring delivery to international destinations. To fulfill our transportation requirements under these arrangements, including those under long term SPAs, we depend on the ability to secure chartered vessels often through long term lease arrangements. The construction and delivery of LNG vessels require significant capital and long construction lead times, and we may execute charters several years before the lease arrangements commence.

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Although we actively manage our vessel requirements in response to the market and our customer contracts, the availability of LNG vessels and transportation costs could be impacted to the detriment of our business and our customers because of:

•an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;

•shortages of or delays in the receipt of necessary construction materials;

•political or economic disturbances;

•acts of war or piracy;

•changes in governmental regulations or maritime self-regulatory organizations;

•work stoppages or other labor disturbances;

•bankruptcy or other financial crisis of shipbuilders or shipowners;

•quality or engineering problems;

•disruptions to maritime transportation routes, such as the recent security situation in the Gulf of Aden and congestion at the Panama Canal resulting from decreased water levels caused by prolonged drought conditions; and

•weather interference or a catastrophic event, such as a major earthquake, tsunami or fire.

While our chartered vessels are operated by the ship owners and we are exposed to risks outside of our own control, we are generally protected through provisions in our charter agreements from transportation disruptions on the part of the ship owner, including disruptions due to off-hire and downtime periods or shipping delays. However, other events outside of our control where we may not be protected may have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Additionally, while our vessel charters allow us to secure fixed rates under long term contracts (in certain cases subject to inflation) and we generally structure our SPAs to recover any increase in such costs, our profitability, particularly relating to our short term or spot LNG sales outside of our SPAs, is largely dependent on the strength of international LNG markets. While historical downturns have not had a material adverse impact to our operations or results, any prolonged weakening of such markets could result in depressed or negative margins. See the risk factor Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects for additional discussion.

Cyclical or other changes in the demand for and price of LNG and natural gas may adversely affect our LNG business and the performance of our customers and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Our LNG business and the development of domestic LNG facilities and projects generally is based on assumptions about the future availability and price of natural gas and LNG and the prospects for international natural gas and LNG markets. Natural gas and LNG prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:

•competitive liquefaction capacity in North America;

•insufficient or oversupply of natural gas liquefaction or receiving capacity worldwide;

•insufficient LNG tanker capacity;

•weather conditions, including temperature volatility resulting from climate change, and extreme weather events may lead to unexpected distortion in the balance of international LNG supply and demand;

•reduced demand and lower prices for natural gas;

•increased natural gas production deliverable by pipelines, which could suppress demand for LNG;

•decreased oil and natural gas exploration activities which may decrease the production of natural gas, including as a result of any potential ban on production of natural gas through hydraulic fracturing;

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•cost improvements that allow competitors to provide natural gas liquefaction capabilities at reduced prices;

•changes in supplies of, and prices for, alternative energy sources which may reduce the demand for natural gas;

•changes in regulatory, tax or other governmental policies regarding imported LNG, natural gas or alternative energy sources, which may reduce the demand for imported LNG and/or natural gas;

•political conditions in customer regions;

•sudden decreases in demand for LNG as a result of natural disasters or public health crises, including the occurrence of a pandemic, and other catastrophic events;

•adverse relative demand for LNG compared to other markets, which may decrease LNG imports from North America; and

•cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

Adverse trends or developments affecting any of these factors could result in decreases in the price of LNG and/or natural gas, which could materially and adversely affect our LNG business and the performance of our customers, and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Failure of exported LNG to be a long term competitive source of energy for international markets could adversely affect our customers and could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Operations of the Liquefaction Projects are dependent upon the ability of our SPA customers to deliver LNG supplies from the United States, which is primarily dependent upon LNG being a competitive source of energy internationally. The success of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be supplied from the United States and delivered to international markets at a lower cost than the cost of alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas may be discovered outside the United States, which could increase the available supply of natural gas outside the United States and could result in natural gas in those markets being available at a lower cost than LNG exported to those markets.

Political instability in foreign countries that import or export natural gas, or strained relations between such countries and the United States, may also impede the willingness or ability of LNG purchasers or suppliers and merchants in such countries to import LNG from the United States. Furthermore, some foreign purchasers or suppliers of LNG may have economic or other reasons to obtain their LNG from, or direct their LNG to, non-U.S. markets or from or to our competitors’ liquefaction facilities in the United States.

As described in Market Factors and Competition, it is expected that global demand for natural gas and LNG will continue to increase as nations seek more abundant, reliable and environmentally cleaner fuel alternatives to alternative fossil fuel energy sources such as oil and coal. However, as a result of transitions globally from fossil-based systems of energy production and consumption to renewable energy sources, LNG may face increased competition from alternative, cleaner sources of energy as such alternative sources emerge. Additionally, LNG from the Liquefaction Projects also competes with other sources of LNG, including LNG that is priced to indices other than Henry Hub. Some of these sources of energy may be available at a lower cost than LNG from the Liquefaction Projects in certain markets. The cost of LNG supplies from the United States, including the Liquefaction Projects, may also be impacted by an increase in natural gas prices in the United States.

As described in Market Factors and Competition, we have contracted through our SPAs and IPM agreements 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. However, as a result of the factors described above and other factors, the LNG we produce may not remain a long term competitive source of energy internationally, particularly when our existing long term contracts begin to expire. Any significant impediment to the ability to continue to secure long term commercial contracts or deliver LNG from the United States could have a material adverse effect on our customers and on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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We face competition based upon the international market price for LNG.

Our Liquefaction Projects are subject to the risk of LNG price competition at times when we need to replace any existing SPA, whether due to natural expiration, default or otherwise, or enter into new SPAs. Factors relating to competition may prevent us from entering into a new or replacement SPA on economically comparable terms as existing SPAs, or at all. Such an event could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Factors which may negatively affect potential demand for LNG from our Liquefaction Projects are diverse and include, among others:

•increases in worldwide LNG production capacity and availability of LNG for market supply;

•increases in demand for LNG but at levels below those required to maintain current price equilibrium with respect to supply;

•increases in the cost to supply natural gas feedstock to our Liquefaction Projects;

•decreases in the cost of competing sources of natural gas or alternate fuels such as coal, heavy fuel oil and diesel;

•decreases in the price of non-U.S. LNG, including decreases in price as a result of contracts indexed to lower oil prices;

•increases in capacity and utilization of nuclear power and related facilities; and

•displacement of LNG by pipeline natural gas or alternate fuels in locations where access to these energy sources is not currently available.

A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

The pipeline and LNG industries are increasingly dependent on business and operational control technologies to conduct daily operations. We rely on control systems, technologies and networks to run our business and to control and manage our trading, marketing, pipeline, liquefaction and shipping operations. Cyber attacks on businesses have escalated in recent years, including as a result of geopolitical tensions, and use of the internet, cloud services, mobile communication systems and other public networks exposes our business and that of other third parties with whom we do business to potential cyber attacks, including third party pipelines which supply natural gas to our Liquefaction Facilities. For example, in 2021 Colonial Pipeline suffered a ransomware attack that led to the complete shutdown of its pipeline system for six days. Should a multiple of the third party pipelines which supply our Liquefaction Facilities suffer similar concurrent attacks, the Liquefaction Facilities may not be able to obtain sufficient natural gas to operate at full capacity, or at all. A cyber attack involving our business or operational control systems or related infrastructure, or that of third party pipelines with which we do business, could negatively impact our operations, result in data security breaches, impede the processing of transactions, or delay financial or compliance reporting. These impacts could materially and adversely affect our business, contracts, financial condition, operating results, cash flow and liquidity.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain qualified personnel could adversely affect us. In addition, changes in our senior management or other key personnel could affect our business results.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our facilities and pipelines and to provide our customers with the highest quality service. We are also subject to the Fair Labor Standards Act, which governs such matters as minimum wage, overtime and other working conditions. A shortage in the labor pool of skilled workers, remoteness of our site locations, general inflationary pressures, changes in applicable laws and regulations or labor disputes could make it more difficult for us to attract and retain qualified personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. In addition, we are also subject to increased competition for skilled workers from new entrants to the LNG market. Any increase in our operating costs could materially and adversely affect our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term, other than our employment agreement with our President and Chief Executive Officer. The loss of the services of any of these individuals could have a material adverse effect on our business.

Outbreaks of infectious diseases, such as COVID-19, at one or more of our facilities could adversely affect our operations.

Our facilities at the Sabine Pass LNG Terminal and Corpus Christi LNG Terminal are critical infrastructure and continued to operate during the COVID-19 pandemic through our implementation of workplace controls and pandemic risk reduction measures. While the COVID-19 pandemic, including subsequent variants, had no adverse impact on our on-going operations, the risk of future variants and other infectious diseases is unknown. While we believe we can continue to mitigate any significant adverse impact to our employees and operations at our critical facilities related to the virus in its current form, the outbreak of a more potent variant or another infectious disease in the future at one or more of our facilities could adversely affect our operations.

Risks Relating to Regulations

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the design, construction and operation of our facilities, the development and operation of our pipelines and the export of LNG could impede operations and construction and could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

The design, construction and operation of interstate natural gas pipelines, LNG terminals, including the Liquefaction Projects, the CCL Midscale Trains 8 & 9 Project, the SPL Expansion Project and other facilities, as well as the import and export of LNG and the purchase and transportation of natural gas, are highly regulated activities. Approvals of the FERC and DOE under Section 3 and Section 7 of the NGA, as well as several other material governmental and regulatory approvals and permits, including several under the CAA and the CWA, are required in order to construct and operate an LNG facility and an interstate natural gas pipeline and export LNG.

To date, the FERC has issued orders under Section 3 of the NGA authorizing the siting, construction and operation of the six Trains and related facilities of the SPL Project, the three Trains and related facilities of the CCL Project and the seven midscale Trains and related facilities for the Corpus Christi Stage 3 Project, as well as orders under Section 7 of the NGA authorizing the construction and operation of the Creole Trail Pipeline and the Corpus Christi Pipeline. In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project and in March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project. To date, the DOE has also issued orders under Section 4 of the NGA authorizing SPL, CCL and the Corpus Christi Stage 3 Project to export domestically produced LNG. In January 2024, the Biden Administration announced a temporary pause on pending decisions on exports of LNG to non-FTA countries until the DOE can update the underlying analyses for authorizations. We do not believe such a pause will have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, or liquidity. The CCL Midscale Trains 8 & 9 Project is currently our only project pending non-FTA export approval with the DOE, although such approval is first subject to the receipt of regulatory permit approval from the FERC, responsive to our formal application in March 2023. We would anticipate seeking non-FTA export authorization from the DOE on the SPL Expansion Project in the future, having entered the pre-filing review process with the FERC in May 2023. Additionally, we hold certificates under Section 7(c) of the NGA that grant us land use rights relating to the situation of our pipelines on land owned by third parties. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Authorizations obtained from the FERC, DOE and other federal and state regulatory agencies contain ongoing conditions that we must comply with. Failure to comply with or our inability to obtain and maintain existing or newly imposed approvals, permits and filings that may arise due to factors outside of our control such as a U.S. government disruption or shutdown, political opposition or local community resistance to our operations could impede the operation and construction of our infrastructure. In addition, certain of these governmental permits, approvals and authorizations are or may be subject to rehearing requests, appeals and other challenges. There is no assurance that we will obtain and maintain these governmental permits, approvals and authorizations, or that we will be able to obtain them on a timely basis. Any impediment could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

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  Our interstate natural gas pipelines and their FERC gas tariffs are subject to FERC regulation. If we fail to comply with such regulation, we could be subject to substantial penalties and fines.

Our interstate natural gas pipelines are subject to regulation by the FERC under the NGA and the Natural Gas Policy Act of 1978 (the “NGPA”). The FERC regulates the purchase and transportation of natural gas in interstate commerce, including the construction and operation of pipelines, the rates, terms and conditions of service and abandonment of facilities. Under the NGA, the rates charged by our interstate natural gas pipelines must be just and reasonable, and we are prohibited from unduly preferring or unreasonably discriminating against any potential shipper with respect to pipeline rates or terms and conditions of service. If we fail to comply with all applicable statutes, rules, regulations and orders, our interstate pipelines could be subject to substantial penalties and fines.

In addition, as a natural gas market participant, should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA and the NGPA to impose penalties for current violations of up to $1.5 million per day for each violation.

Although the FERC has not imposed fines or penalties on us to date, we are exposed to substantial penalties and fines if we fail to comply with such regulations.

Existing and future safety, environmental and similar laws and governmental regulations could result in increased compliance costs or additional operating costs or construction costs and restrictions.

Our business is and will be subject to extensive federal, state and local laws, rules and regulations applicable to our construction and operation activities relating to, among other things, air quality, water quality, waste management, natural resources and health and safety. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operation of our facilities, and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. In addition, certain laws and regulations authorize regulators having jurisdiction over the construction and operation of our LNG terminals, docks and pipelines, including FERC, PHMSA, EPA and the United States Coast Guard, to issue regulatory enforcement actions, which may restrict or limit operations or increase compliance or operating costs. Violation of these laws and regulations could lead to substantial liabilities, compliance orders, fines and penalties, difficulty obtaining and maintaining permits from regulatory agencies or increased capital expenditures that could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of our facilities, we could be liable for the costs of cleaning up hazardous substances released into the environment at or from our facilities and for resulting damage to natural resources.

The EPA has finalized or proposed multiple GHG regulations that impact our assets and supply chain. On December 2, 2023, the EPA issued final rules to reduce methane and VOC emissions from new, existing and modified emission sources in the oil and gas sector. These regulations will require monitoring of methane and VOC emissions at our compressor stations. Further, the IRA includes a charge on methane emissions above certain emissions thresholds employing empirical emissions data that will apply to our facilities beginning in calendar year 2024. In January 2024, the EPA issued a proposed rule to impose and collect methane emissions charges authorized under the IRA. In addition, other international, federal and state initiatives may be considered in the future to address GHG emissions through treaty commitments, direct regulation, market-based regulations such as a GHG emissions tax or cap-and-trade programs or clean energy or performance-based standards. Such initiatives could affect the demand for or cost of natural gas, which we consume at our terminals, or could increase compliance costs for our operations.

Revised, reinterpreted or additional guidance, laws and regulations at local, state, federal or international levels that result in increased compliance costs or additional operating or construction costs and restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects. It is not possible at this time to predict how future regulations or legislation may address GHG emissions and impact our business.

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On February 28, 2022, the EPA removed a stay of formaldehyde standards in the NESHAP Subpart YYYY for stationary combustion turbines located at major sources of HAP emissions. Owners and operators of lean remix gas-fired turbines and diffusion flame gas-fired turbines at major sources of HAP that were installed after January 14, 2003 were required to comply with NESHAP Subpart YYYY by March 9, 2022 and demonstrate initial compliance with those requirements by September 5, 2022. We do not believe that our operations, or the construction and operations of our liquefaction facilities, will be materially and adversely affected by such regulatory actions.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from our terminals or climate policies of destination countries in relation to their obligations under the Paris Agreement or other national or international climate change-related policies, could cause additional expenditures, restrictions and delays in our business and to our proposed construction activities, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances.

Total expenditures related to environmental and similar laws and governmental regulations, including capital expenditures, were immaterial to our Consolidated Financial Statements for the years ended December 31, 2023, 2022 and 2021. Revised, reinterpreted or additional laws and regulations that result in increased compliance, operating or construction costs or restrictions could have a material adverse effect on our business, contracts, financial condition, operating results, cash flow, liquidity and prospects.

Pipeline safety and compliance programs and repairs may impose significant costs and liabilities on us.

The PHMSA requires pipeline operators to develop management programs to safely operate and maintain their pipelines and to comprehensively evaluate certain areas along their pipelines and take additional measures where necessary to protect pipeline segments located in “high or moderate consequence areas” where a leak or rupture could potentially do the most harm. As an operator, we are required to:

•perform ongoing assessments of pipeline safety and compliance;

•identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

•improve data collection, integration and analysis;

•repair and remediate the pipeline as necessary; and

•implement preventative and mitigating actions.

We are required to utilize pipeline integrity management programs that are intended to maintain pipeline integrity. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with applicable statutes and the Office of Pipeline Safety’s rules and related regulations and orders, we could be subject to significant penalties and fines, which for certain violations can aggregate up to as high as $2.7 million.

Additions or changes in tax laws and regulations could potentially affect our financial results or liquidity.

We are subject to various types of tax arising from normal business operations in the jurisdictions in which we operate and transact. Any changes to local, domestic or international tax laws and regulations, or their interpretation and application, including the Organization for Economic Cooperation and Development’s (the “OECD”) adopted model rules for a 15% global minimum tax (commonly referred to as Pillar Two), could affect our tax obligations, profitability and cash flows in the future. In addition, tax rates in the various jurisdictions in which we operate may change significantly due to political or economic factors beyond our control. We continuously monitor and assess proposed tax legislation that could negatively impact our business.

The IRA imposes a 15% CAMT effective in 2023, on an applicable corporation with average AFSI in excess of $1 billion for any three consecutive years preceding the current year. Cheniere expects to be an applicable corporation beginning in 2024. Based on the CAMT rules as currently enacted, the CAMT tax base would include any gains or losses arising from changes in fair value of our commodity derivatives that are recorded to our Consolidated Statements of Operations. Volatility in underlying commodity and financial markets could accelerate and cause volatility in our future cash tax payments, particularly in periods of significant commodity, currency or financial market variability. If the CAMT applies, we could be subject to an additional tax liability beyond the regular federal corporate tax liability, despite our federal net operating loss carryforwards, which could adversely impact our liquidity. Additionally, any implementing regulatory guidance related to the

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CAMT issued by the U.S. Department of Treasury and the Internal Revenue Service in the future could potentially affect both the timing and amount of our CAMT cash tax payments.

Our ability to utilize our net operating loss carryforwards and certain other tax attributes may be limited.

As of December 31, 2023, our federal net operating loss (“NOL”) carryforwards were approximately $4.3 billion and not subject to expiration. We may experience an ownership change as a result of future changes in our stock ownership (some of which changes may not be within our control). If Cheniere undergoes an ownership change (generally defined as a greater than 50% cumulative change in the equity ownership of certain shareholders over a rolling three-year period) under Section 382 of the Internal Revenue Code, our ability to use our pre-ownership change NOL carryforwards to offset future taxable income may be limited. This, in turn, could materially delay our ability to use our NOLs to offset future taxable income and have an adverse effect on our future cash flows.

ITEM 1B.    UNRESOLVED STAFF COMMENTS

None.

ITEM 1C.    CYBERSECURITY

Cyberattacks represent a potentially significant risk to the Company and our industry. We have implemented policies and procedures that are intended to manage and reduce this risk.

Risk Management and Strategy

As part of our broader approach to risk management, our cybersecurity program is designed to follow an “identify, protect, detect, respond and recover” approach to cybersecurity that is based off of the National Institute of Standards and Technology Cybersecurity Framework (“CSF”). Our strategy also includes segmentation of corporate and operations networks, defense in depth and the least privileged access principle. Operational networks have fundamentally distinct safety and reliability standards and pose unique threats in comparison to information technology networks. Realizing these differences, we routinely evaluate opportunities to refine our cybersecurity program in order to mitigate operational network risks. We include business continuity planning as a component of our strategy to help ensure critical systems are available to support our company in the instance of a disruptive event. We also participate in various industry organizations to stay abreast of recent trends and developments.

On an ongoing basis, we assess our people, processes and technology and, when necessary, adjust the overall program in an effort to adapt to the ever-evolving cyber and geopolitical landscapes. We conduct regular assessments and audits, cross-functional risk mitigation exercises and risk strategy sessions to identify cybersecurity risks, applicable regulatory requirements and industry standards. These engagements are also designed to exercise, assess the maturity of and enhance our Cyber Incident Response Plan. To support these efforts, we have contracted with third parties to perform facility and system penetration tests, compromise assessments of information technology systems, and security maturity assessments of our corporate and operational networks. We maintain a training program to help our personnel identify and assist in mitigating cybersecurity and data security risks. Our employees and Board members participate in annual training, user awareness campaigns and additional issue-specific training as needed. We also provide annual training for certain contractors who have access to our information technology networks.

With respect to third party service providers, our information security program includes conducting risk-based due diligence of certain service providers’ information security programs prior to onboarding. We seek to contractually require third party service providers with access to our information technology systems, sensitive business data or personal information to maintain reasonable security controls and restrict their ability to use our data, including personal information, for purposes other than to provide services to us, except as required by applicable law. We also seek to negotiate contractual requirements which compel our service providers to notify us of information security incidents occurring on their systems which may affect our systems or data, including personal information.

During the year ended December 31, 2023, cybersecurity incidents and threats did not materially affect our business, results of operations or financial condition.

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Governance

Our cybersecurity leadership team consists of our Director and Chief Information Security Officer (our “CISO”), Vice President and Chief Information Officer and Senior Vice President of Shared Services. These individuals collectively provide the strategic oversight of our cybersecurity governance, cyber risk management and security operations and are responsible for maintaining our technology defense posture and program. They have decades of experience managing strategic technology operations, including the identification of cybersecurity risk and the defense of information technology assets from global threats. Our CISO’s experience includes assessing risks, implementing governance programs, and responding to threats in oil and gas, electric and natural gas utilities and nuclear power generation companies. He maintains a Certified Information Security Manager certification from ISACA, secret clearance from the Department of Homeland Security and has played an active role in the development of various cybersecurity standards including the CSF.

Risks that could affect us are an integral part of our Board and Audit Committee deliberations throughout the year. Cybersecurity risks are integrated into our enterprise risk assessment process, which is reviewed by our Board at least annually. Our Board has oversight responsibility for assessing the primary risks facing us (including cybersecurity risks), the relative magnitude of these risks and management’s plan for mitigating these risks, while the Audit Committee has been delegated the authority to oversee and periodically review the security of our information technology systems and controls, including programs and defenses against cybersecurity threats. The Audit Committee discusses with management our cybersecurity risk exposures and the steps management has taken to mitigate such exposures, including our risk assessment and risk management policies. On a quarterly basis, our cybersecurity leadership team updates the Audit Committee on the overall status of our cybersecurity program, key operational metrics, current assessments, cybersecurity issues or events and pertinent events related to cybersecurity.

For additional information about cybersecurity risks, see the risk A cyber attack involving our business, operational control systems or related infrastructure, or that of third party pipelines which supply the Liquefaction Facilities, could negatively impact our operations, result in data security breaches, impede the processing of transactions or delay financial or compliance reporting under Risks Relating to Our Operations and Industry in Item 1A.Risk Factors.

ITEM 3. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters.

LDEQ Matter

Certain of our subsidiaries are in discussions with the LDEQ to resolve alleged non-compliance with national emission standards for formaldehyde from combustion turbines at the Sabine Pass LNG Terminal. The allegations are identified in a Consolidated Compliance Order and Notice of Potential Penalty, Tracking No. AE-CN-22-00833 (the “2023 Compliance Order”) issued by the LDEQ on April 12, 2023. In August 2004, the EPA stayed the application of the emission standard to combustion turbines such as those at the Sabine Pass LNG Terminal. In March 2022, the EPA lifted the stay, and in June 2022 our subsidiaries petitioned the EPA and LDEQ for approval of additional operating parameters to demonstrate compliance with the emission limitation. The petition remains pending. Our subsidiaries continue to work with the LDEQ to resolve the matters identified in the 2023 Compliance Order, including the petition pending with the EPA. As of December 2023, our subsidiaries have filed test results with the LDEQ indicating that for the initial compliance period all 44 turbines meet the relevant compliance standard. We do not expect that any ultimate penalty will have a material adverse impact on our financial results.

ITEM 4.    MINE SAFETY DISCLOSURE

Not applicable.

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PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Market Information, Holders and Dividend Policy

Our common stock has traded on the New York Stock Exchange under the symbol “LNG” since February 5, 2024, and previously traded on the NYSE American or its predecessors under the symbol “LNG” from March 24, 2003 through February 3, 2024. As of February 16, 2024, we had approximately 234.7 million shares of common stock outstanding held by 75 record owners.

We intend to continue to declare and pay quarterly dividends, with the goal of increasing the dividend over time. The declaration of dividends is subject to the discretion of our Board, and will depend on our financial condition and other factors deemed relevant by the Board. See the risk Our ability to declare and pay dividends and repurchase shares is subject to certain considerations under Risks Relating to Our Financial Matters in Item 1A. Risk Factors.

Purchase of Equity Securities by the Issuer and Affiliated Purchasers

The following table summarizes stock repurchases for the three months ended December 31, 2023:

Period	Total Number of Shares Purchased	Average Price Paid Per Share	Total Number of Shares Purchased as a Part of Publicly Announced Plans	Approximate Dollar Value of Shares That May Yet Be Purchased Under the Plans (in millions) (1)
October 1 - 31, 2023	732,055	$167.95	732,055	$2,357
November 1 - 30, 2023	634,274	$174.28	634,274	$2,247
December 1 - 31, 2023	607,966	$173.21	607,966	$2,141
Total	1,974,295	$171.60	1,974,295

(1)See Note 19—Share Repurchase Programs of our Notes to Consolidated Financial Statements for details on the amount authorized by our Board under our share repurchase programs.

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Total Stockholder Return

The following is a customized peer group consisting of 17 companies (the “Peer Group”) that were selected because they are publicly traded companies that have comparable Global Industry Classification Standards. We also took into consideration those companies that have similar market capitalization, enterprise values and operating characteristics and capital intensity.

Peer Group
Air Products and Chemicals, Inc. (APD)	Marathon Petroleum Corporation (MPC)
Baker Hughes Company (BKR)	Occidental Petroleum Corporation (OXY)
ConocoPhillips (COP)	ONEOK, Inc. (OKE)
Enterprise Products Partners L.P. (EPD)	Phillips 66 (PSX)
EOG Resources, Inc. (EOG)	Suncor Energy Inc. (SU)
Halliburton Company (HAL)	Targa Resources Corp. (TRGP)
Hess Corporation (HES)	Valero Energy Corporation (VLO)
Kinder Morgan, Inc. (KMI)	The Williams Companies, Inc. (WMB)
LyondellBasell Industries N.V. (LYB)

The following graph compares the five-year total return on our common stock, the S&P 500 Index and our Peer Group. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P 500 Index and our Peer Group on December 31, 2018 and that any dividends were fully reinvested.

	December 31,
Company / Index	2018		2019		2020	2021		2022		2023
Cheniere Energy, Inc.	$	100.00	$	103.18	101.42	$	171.88	$	256.67	$	295.20
S&P 500 Index	100.00		131.48		155.65	200.29		163.98		207.04
Peer Group	100.00		122.09		90.09	130.28		193.39		212.27

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ITEM 6.    [Reserved]

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 2021 items and variance drivers between the year ended December 31, 2022 as compared to December 31, 2021 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, 2022.

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 customer arrangements form the foundation of our business and provide us with significant, stable, long-term cash flows. Through our SPAs and IPM agreements, we have contracted approximately 95% of the total anticipated production from the Liquefaction Projects through the mid-2030s with approximately 16 years of weighted average remaining life as of December 31, 2023, 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 2023, 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 portfolio of customer contracts in the future. The continued strength and stability of our long-term cash flows served as the foundation of our revised comprehensive, long-term capital allocation plan announced in 2022, which includes an increased share repurchase authorization, decreased consolidated long-term leverage target, increased dividends and continued investment in accretive organic growth.

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Overview of Significant Events

Our significant events since January 1, 2023 and through the filing date of this Form 10-K include the following:

Strategic

•In November 2023, we announced that SPL Stage V entered into an IPM agreement with ARC Resources U.S. Corp., a subsidiary of ARC Resources Ltd., to purchase 140,000 MMBtu per day of natural gas at a price based on the Dutch Title Transfer Facility (“TTF”), less a fixed regasification fee, fixed LNG shipping costs and a fixed liquefaction fee, for a term of approximately 15 years commencing with commercial operations of the first train of the SPL Expansion Project. This agreement is subject to CQP making a positive FID on the first train of the SPL Expansion Project or CQP unilaterally waiving that requirement.

•Cheniere Marketing entered into long-term SPAs with Foran Energy Group Co. Ltd., BASF, ENN LNG (Singapore) Pte. Ltd., Equinor ASA and Korea Southern Power Co. Ltd. with estimated volumes totaling approximately 106 million tonnes of LNG and expected deliveries between 2026 and 2050. Approximately 65 million tonnes is subject to CQP making a positive FID on the first or second trains of the SPL Expansion Project, as applicable, or us unilaterally waiving that requirement. Each of these SPAs permit Cheniere Marketing to assign or novate the agreement to certain affiliates at a later date.

•In May 2023, certain subsidiaries of CQP entered the pre-filing review process with the FERC under the NEPA for the SPL Expansion Project, and in April 2023, one of our subsidiaries executed a contract with Bechtel to provide the front end engineering and design work on the project.

•In April 2023, certain of our subsidiaries filed an application with the DOE with respect to the CCL Midscale Trains 8 & 9 Project, requesting authorization to export LNG to FTA countries and non-FTA countries. In July 2023, we received authorization from the DOE to export LNG to FTA countries.

•In March 2023, certain of our subsidiaries submitted an application with the FERC under the NGA for the CCL Midscale Trains 8 & 9 Project.

•On January 2, 2023, Corey Grindal, formerly Executive Vice President, Worldwide Trading, was promoted to Executive Vice President and Chief Operating Officer of the Company.

Operational

•As of February 16, 2024, approximately 3,280 cumulative LNG cargoes totaling over 225 million tonnes of LNG have been produced, loaded and exported from the Liquefaction Projects.

Financial

•We closed the following debt transactions:

◦In June 2023, CQP issued $1.4 billion aggregate principal amount of 5.950% Senior Notes due 2033 (the “2033 CQP Senior Notes”). Using contributed proceeds from the 2033 CQP Senior Notes together with cash on hand, SPL redeemed $1.4 billion of its 5.750% Senior Secured Notes due 2024 (the “2024 SPL Senior Notes”) in July 2023.

◦In June 2023, CQP entered into a $1.0 billion Senior Unsecured Revolving Credit and Guaranty Agreement (the “CQP Revolving Credit Facility”), and SPL entered into a $1.0 billion Senior Secured Revolving Credit and Guaranty Agreement (the “SPL Revolving Credit Facility”). The CQP Revolving Credit Facility and SPL Revolving Credit Facility each refinanced and replaced the respective existing credit facilities to, among other things, (1) extend the maturity date thereunder, (2) reduce the rate of interest and commitment fees applicable thereunder and (3) make certain other changes to the terms and conditions of the prior credit facilities.

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•We received the following upgrades from credit rating agencies, including S&P Global Ratings (“S&P”), Moody’s Investor Service (“Moody’s”) and Fitch Ratings (“Fitch”), each with a stable outlook:

Date	Entity	Previous Rating	Upgraded Rating	Rating Agency
October 2023	CCH	BBB-	BBB	S&P
August 2023	Cheniere	Ba1	Baa3	Moody’s
August 2023	CCH	Baa3	Baa2	Moody’s
August 2023	SPL	BBB	BBB+	Fitch
July 2023	CCH	BBB-	BBB	Fitch
February 2023	SPL	BBB	BBB+	S&P
January 2023	Cheniere	—	BBB-	Fitch

•During the year ended December 31, 2023, we accomplished the following pursuant to our capital allocation priorities:

◦We prepaid $1.2 billion of consolidated long-term indebtedness, which excludes prepayments associated with debt refinancing and includes $600 million of debt repurchases in the open market.

◦We repurchased approximately 9.5 million shares of our common stock as part of our share repurchase program for $1.5 billion.

◦We paid dividends of $1.620 per share of common stock during the year ended December 31, 2023.

◦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.

Market Environment

In 2023, the LNG market continued to rebalance with robust LNG flows to Europe maintaining the region’s underground storage inventories at high levels, and weak demand in Japan and Korea largely offsetting a modest rebound in China and other emerging economies in Asia. Price levels started moving towards pre-Russia-Ukraine war levels in the second quarter of 2023 and have for the most part normalized versus pre-war levels, as concerns about physical market tightness dissipated. However, extensive upstream maintenance in Norway and concerns about tight supply capacity amid strike threats in Australia elevated prices during the third quarter of 2023 and brought some volatility back to the market, albeit not at much lower levels than those seen in 2022. These conditions were quickly resolved, and winter prices remained within a more normal level, despite the eruption of military conflict in the Middle East in October.

The TTF monthly settlement prices averaged $13.73/MMBtu in 2023, over 66% lower year-over-year and 4.6% lower than 2021. Similarly, the 2023 average settlement price for the Japan Korea Marker (“JKM”) decreased 53% year-over-year to an average of $16.13/MMBtu in 2023. Prices in the fourth quarter of 2023 also decreased, with TTF averaging $13.66/MMBtu and JKM $14.97/MMBtu - both significantly below levels seen in the previous two years. The Henry Hub benchmark also witnessed a similar year-over-year drop albeit from a much lower base. The Henry Hub average settlement price in 2023 was $2.74, down approximately 59% from $6.64/MMBtu in 2022 during the height of the energy crisis in Europe.

The U.S. played a significant role in balancing the global market in 2023, exporting approximately 86 million tonnes of LNG, a gain of approximately 13% from 2022, due in part to the return of Freeport LNG to operations. Exports from our Liquefaction Projects reached 44 million tonnes in aggregate, representing over 50% of total U.S. exports for the year, according to Kpler data.

Global LNG demand grew by approximately 3% from 2022, adding 10.5 million tonnes to the overall market. Although overall Asian demand has increased from 2022, weakness in Japan, mainly due to improved nuclear availability, along with continued gas demand destruction in Europe, especially in the residential sector, exerted downward pressure on the market and kept LNG and gas prices from increasing. Despite the decrease in Japanese demand, which was down approximately 8% or 6 mtpa year-over-year, Asia’s LNG imports increased roughly 4% year-over-year in 2023 to approximately 263 mtpa. This uptick was largely due to an approximately 8.4 mtpa year-over-year growth in South and Southeast Asia’s demand and a modest rebound in China’s economy, which resulted in approximately 12% or 7.5 mtpa increase in LNG imports into the

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country. In Europe, despite continued declines in gas demand, LNG imports were flat year-over-year as pipeline flows from Russia to the EU remained low at 27 billion cubic meters (“Bcm”), down 36 Bcm or 57% year-over-year.

The market dynamics brought on by the need to displace and replace Russian gas into Europe in 2023 resulted in a notable uptick in long-term LNG contracting and a push for LNG project FIDs. Commercial activity in 2023 continued to build on last year’s momentum with executed long-term SPAs in the U.S. reaching approximately 23 mtpa for the year, of which our SPAs and IPM agreements totaled approximately 6.5 mtpa. This contractual momentum over the past two years led to the positive FID of nearly 40 mtpa of U.S. LNG capacity in 2023, and we anticipate that a portion of these contracts will support our future growth.

Despite the global impacts of the Russia-Ukraine war, we do not believe we have significant exposure to adverse direct or indirect impacts of the war, as we do not conduct business in Russia and refrain from business dealings with Russian entities. Additionally, we are not aware of any specific adverse direct or indirect effects of the Russia-Ukraine war or the Israel-Hamas war on our supply chain. Consequently, we believe we are well positioned to help meet the increased demand of our international LNG customers to overcome their supply shortages.

Results of Operations

Consolidated results of operations

	Year Ended December 31,
(in millions, except per share data)	2023		2022		Variance
Revenues
LNG revenues	$	19,569	$	31,804	$	(12,235)
Regasification revenues	135		1,068		(933)
Other revenues	690		556		134
Total revenues	20,394		33,428		(13,034)
Operating costs and expenses
Cost of sales (excluding items shown separately below)	1,356		25,632		(24,276)
Operating and maintenance expense	1,835		1,681		154
Selling, general and administrative expense	474		416		58
Depreciation and amortization expense	1,196		1,119		77
Other	44		21		23
Total operating costs and expenses	4,905		28,869		(23,964)
Income from operations	15,489		4,559		10,930
Other income (expense)
Interest expense, net of capitalized interest	(1,141)		(1,406)		265
Gain (loss) on modification or extinguishment of debt	15		(66)		81
Interest and dividend income	211		57		154
Other income (expense), net	4		(50)		54
Total other expense	(911)		(1,465)		554
Income before income taxes and non-controlling interest	14,578		3,094		11,484
Less: income tax provision	2,519		459		2,060
Net income	12,059		2,635		9,424
Less: net income attributable to non-controlling interest	2,178		1,207		971
Net income attributable to common stockholders	$	9,881	$	1,428	$	8,453
Net income per share attributable to common stockholders—basic	$	40.99	$	5.69	$	35.30
Net income per share attributable to common stockholders—diluted	$	40.72	$	5.64	$	35.08

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Volumes loaded and recognized from the Liquefaction Projects

	Year Ended December 31,
(in TBtu)	2023	2022	Variance
Volumes loaded during the current period	2,299	2,295	4
Volumes loaded during the prior period but recognized during the current period	56	49	7
Less: volumes loaded during the current period and in transit at the end of the period	(37)	(56)	19
Total volumes recognized in the current period	2,318	2,288	30

Components of LNG revenues and corresponding LNG volumes delivered

	Year Ended December 31,
	2023		2022		Variance
LNG revenues (in millions):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	$	12,820	$	20,702	$	(7,882)
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	6,028		10,169		(4,141)
LNG procured from third parties	359		760		(401)
Net derivative gains (losses)	110		(328)		438
Other revenues	252		501		(249)
Total LNG revenues	$	19,569	$	31,804	$	(12,235)
Volumes delivered as LNG revenues (in TBtu):
LNG from the Liquefaction Projects sold under third party long-term agreements (1)	2,034		1,926		108
LNG from the Liquefaction Projects sold by our integrated marketing function under short-term agreements	284		362		(78)
LNG procured from third parties	35		29		6
Total volumes delivered as LNG revenues	2,353		2,317		36

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

Net income attributable to common stockholders

The favorable variance of $8.5 billion for the year ended December 31, 2023 as compared to the same period of 2022 was primarily attributable to a favorable variance of $14.4 billion (before tax and the impact of non-controlling interest), from changes in fair value and settlement of derivatives between the periods. The majority of the variance related to derivatives was due to non-cash favorable changes in fair value of our IPM agreements as a result of lower volatility in international gas prices and declines in international forward commodity curves, which changed from a loss of $5.0 billion in the year ended December 31, 2022 to a gain of $7.0 billion in the year ended December 31, 2023.

The favorable variance was partially offset by:

•decrease in LNG revenues, net of cost of sales and excluding the effect of derivatives (as further described above), of $2.4 billion, the majority of which was attributable to lower margins on LNG delivered;

•unfavorable variance of $2.1 billion in income tax provision due to higher taxable earnings; and

•unfavorable variance of $971 million in net income attributable to non-controlling interest due to an increase in CQP’s consolidated net income between the comparable periods.

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

Revenues

The decrease of $13.0 billion between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$9.1 billion decrease in Henry Hub pricing, to which the majority of our long-term LNG sales contracts are indexed;

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•decrease in revenues generated by our marketing function of $2.5 billion due to declining international prices and a reduction of volumes sold under short-term agreements; and

•decrease in regasification revenues of $933 million due to the accelerated recognition of revenues associated with the termination of one of our TUA agreements in December 2022. See Note 13—Revenues of our Notes to Consolidated Financial Statements for additional information on the termination agreement.

Operating costs and expenses (recoveries)

The $24.0 billion favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$14.0 billion favorable variance from changes in fair value and settlements of derivatives included in cost of sales, from $6.2 billion of loss in the year ended December 31, 2022 to $7.8 billion of gain in the year ended December 31, 2023, primarily related to non-cash favorable changes in fair value of our IPM agreements as described above under the caption Net income attributable to common stockholders; and

•$10.3 billion decrease in cost of sales excluding the effect of derivative changes described above, primarily as a result of $9.6 billion in decreased cost of natural gas feedstock largely due to lower U.S. natural gas prices.

The favorable variance was partially offset by an increase in operating and maintenance expense of $154 million between the comparable periods, which was due to the completion of planned large-scale maintenance activities on two trains at the SPL Project during June 2023, other third party service and maintenance contract costs and natural gas transportation and storage capacity demand charges.

Other income (expense)

The $554 million favorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to:

•$265 million decrease in interest expense, net of capitalized interest, primarily as a result of lower debt balances due to $1.2 billion of repayment of debt in 2023, which excludes prepayments associated with debt refinancing;

•$154 million increase in interest and dividend income as a result of higher interest income earned on cash and cash equivalents from higher interest rates in 2023; and

•$81 million favorable variance in gain (loss) on modification or extinguishment of debt, primarily due to higher losses recognized from the amendment and restatement of CCH’s term loan facility agreement (the “CCH Credit Facility”) and CCH’s working capital facility agreement (the “CCH Working Capital Facility”) during the second quarter of 2022 and the redemption of our 4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) during the first quarter of 2022. Further contributing to the favorable variance during the year ended December 31, 2023 was a reduction in premiums paid for the early redemption or repayment of debt principal, as a result of near-maturity debt being redeemed or repaid or repurchased in the open market resulting in lower make-whole payments, as further detailed under Financing Cash Flows in Sources and Uses of Cash within Liquidity and Capital Resources.

Income tax provision

The $2.1 billion unfavorable variance between the years ended December 31, 2023 and 2022 was primarily attributable to an increase in pre-tax income.

Our effective tax rate was 17.3% and 14.8% for the years ended December 31, 2023 and 2022, respectively. The effective tax rate for both the years ended December 31, 2023 and 2022 was lower than the statutory rate of 21% primarily due to CQP’s income that is not taxable to us.

In December 2021, the OECD released a framework for Pillar Two model rules, which introduced a global minimum corporate tax rate of 15% for large multinational groups. We are a large multinational group with substantial operations in the U.S. and U.K. The U.K. enacted legislation implementing Pillar Two on July 18, 2023, effective beginning January 1, 2024. The U.S. has not enacted legislation implementing Pillar Two. We are continuing to evaluate the Pillar Two rules and their potential impact on future periods, but we do not expect the rules to have a material impact on our effective tax rate.

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Net income attributable to non-controlling interest

The $971 million increase between the years ended December 31, 2023 and 2022 was primarily attributable to $1.8 billion increase in CQP’s consolidated net income between the years ended December 31, 2023 and 2022.

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 in addition to managing exposure to commodity-related marketing and price risks, are utilized to manage exposure to changing interest rates and foreign exchange volatility, are reported at fair value on our Consolidated Financial Statements. For commodity derivative instruments 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 7—Derivative Instruments of our Notes to Consolidated Financial Statements, the fair value of our Liquefaction Supply Derivatives and LNG Trading Derivatives incorporates, as applicable to our natural gas supply contracts, 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 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.

Commissioning cargoes

Prior to substantial completion of a Train, amounts received from the sale of commissioning cargoes 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. During the year ended December 31, 2022, we realized offsets to LNG terminal costs of $204 million corresponding to 15 TBtu attributable to the sale of commissioning cargoes from Train 6 of the SPL Project. We did not have any commissioning cargoes during the year ended December 31, 2023.

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.

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	December 31, 2023
Cash and cash equivalents (1)	$	4,066
Restricted cash and cash equivalents (1)	459
Available commitments under our credit facilities (2):
SPL Revolving Credit Facility	720
CQP Revolving Credit Facility	1,000
CCH Credit Facility	3,260
CCH Working Capital Facility	1,345
Cheniere’s revolving credit agreement (the “Cheniere Revolving Credit Facility”)	1,250
Total available commitments under our credit facilities	7,575
Total available liquidity	$	12,100

(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.

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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):

	Estimated Revenues Under Executed SPAs by Period (1) (2)
	2024		2025 - 2028		Thereafter		Total
LNG revenues (fixed fees)	$	6.3	$	27.1	$	77.6	$	111.0
LNG revenues (variable fees) (3)	7.0		40.8		140.5		188.3
Total	$	13.3	$	67.9	$	218.1	$	299.3

(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

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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.

Financially Disciplined 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 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.

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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):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2024		2025 - 2028		Thereafter		Total
Purchase obligations (2):
Natural gas supply agreements (3)	$	5.8	$	20.2	$	25.4	$	51.4
Natural gas transportation and storage service agreements (4)	0.5		2.0		4.9		7.4
Capital expenditures	1.2		1.7		—		2.9
Leases (5)	0.9		3.0		3.7		7.6
Total	$	8.4	$	26.9	$	34.0	$	69.3

(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

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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:

Overall project completion percentage	51.4%
Completion percentage of:
Engineering	83.7%
Procurement	72.2%
Subcontract work	66.9%
Construction	11.1%
Date of expected substantial completion	2Q/3Q 2025 - 2H 2026

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,

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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 Matters in Item 1A. Risk Factors.

Financially Disciplined 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. 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):

	Estimated Payments Due Under Executed Contracts by Period (1)
	2024		2025 - 2028		Thereafter		Total
Debt	$	0.3	$	11.1	$	12.5	$	23.9
Interest payments	1.3		3.3		1.8		6.4
Total	$	1.6	$	14.4	$	14.3	$	30.3

(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.

45

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.

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.

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. 

	Year Ended December 31,
	2023		2022
Net cash provided by operating activities	$	8,418	$	10,523
Net cash used in investing activities	(2,202)		(1,844)
Net cash used in financing activities	(4,180)		(8,014)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2		5
Net increase in cash, cash equivalents and restricted cash and cash equivalents	$	2,038	$	670

46

Operating Cash Flows

The $2.1 billion decrease between the periods was primarily related to lower cash receipts from the sale of LNG cargoes due to lower pricing per MMBtu as a result of decreased pricing and a reduction of volumes sold under short-term agreements, as well as a decrease in regasification revenues. A discussion of our revenues, including LNG and regasification revenues, can be found in Note 13—Revenues of our Notes to Consolidated Financial Statements. The decrease was partially offset by lower cash outflows for natural gas feedstock, mostly due to lower U.S. natural gas prices.

As described in Future Sources and Uses of Liquidity, our future operating cash flows will be impacted by CAMT, which may result in greater volatility in our cash tax payments, including potentially higher cash payments in the near-term relative to the year ended December 31, 2023. See Future Sources and Uses of Liquidity for additional discussion.

Investing Cash Flows

Our investing net cash outflows in both years primarily were for the construction costs for the Liquefaction Projects. The $358 million increase in 2023 compared to 2022 was primarily due to $1.5 billion of cash outflows during the year ended December 31, 2023 related to construction of the Corpus Christi Stage 3 Project following our issuance of full notice to proceed to Bechtel in June 2022 compared to $880 million in the comparable period of 2022, partially offset by a decrease in spend due to the completion of Train 6 of the SPL Project in February 2022. We expect to incur a similar level of capital expenditures in the upcoming year as construction work progresses on the Corpus Christi Stage 3 Project. During the year ended December 31, 2023, we also made investments in infrastructure expected to support the development, construction and operations of the Corpus Christi Stage 3 Project, including an investment in pipeline capacity for natural gas feedstock. Also during the year ended December 31, 2023, we acquired an existing power generation facility located near Corpus Christi, Texas to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

Financing Cash Flows

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

	Year Ended December 31,
	2023		2022
Proceeds from issuances of debt	$	1,397	$	1,575
Redemptions, repayments and repurchases of debt	(2,598)		(6,771)
Distributions to non-controlling interest	(1,016)		(947)
Repurchase of common stock	(1,473)		(1,373)
Dividends to stockholders	(393)		(349)
Other, net	(97)		(149)
Net cash used in financing activities	$	(4,180)	$	(8,014)

Debt Issuances

During the year ended December 31, 2023, CQP issued an aggregate principal amount of $1.4 billion of 2033 CQP Senior Notes, the proceeds of which were used, together with cash on hand, to redeem $1.4 billion of the 2024 SPL Senior Notes. Additionally, during the year ended December 31, 2023, SPL purchased $200 million of the 2024 SPL Senior Notes in the open market and redeemed an additional $100 million of the 2024 SPL Senior Notes. As of December 31, 2023, the only bonds maturing in 2024 are the remaining $300 million outstanding of the 2024 SPL Senior Notes. During the year ended December 31, 2022, SPL issued $430 million of 5.900% Senior Secured Amortizing Notes due 2037 and $70 million of 2037 SPL Private Placement Senior Secured Notes, and we had total borrowings of $1.1 billion under our credit facilities. The proceeds from the borrowings during the year ended December 31, 2022, together with cash on hand, were used to redeem or repurchase $6.8 billion of outstanding indebtedness, entirely associated with redemptions of our outstanding notes or repayment of amounts outstanding under our credit facilities.

47

Debt Redemptions, Repayments and Repurchases

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

	Year Ended December 31,
	2023		2022
Redemptions, repayments and repurchases of debt
SPL:
2024 SPL Senior Notes	$	(1,700)	$	—
2023 SPL Senior Notes	—		(1,500)
SPL Working Capital Facility	—		(60)
CCH:
CCH Credit Facility	—		(2,169)
CCH Working Capital Facility	—		(250)
7.000% Senior Notes due 2024	(498)		(752)
5.625% Senior Notes due 2025	—		(9)
5.125% Senior Notes due 2027	(69)		(230)
3.700% Senior Notes due 2029	(237)		(138)
2.742% Senior Notes due 2039	(94)		—
3.788% weighted average Senior Notes rate due 2039	—		(88)
Cheniere:
2045 Cheniere Convertible Senior Notes	—		(500)
Cheniere Revolving Credit Facility	—		(575)
4.625% Senior Notes due 2028	—		(500)
Total redemptions, repayments and repurchases of debt	$	(2,598)	$	(6,771)

Non-Controlling Interest Distributions

We own a 48.6% limited partner interest in CQP with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management Inc. and the public. Distributions of $1.0 billion and $947 million were paid during the years ended December 31, 2023 and 2022, respectively, to non-controlling interests.

Repurchase of Common Stock

During the years ended December 31, 2023 and 2022, we paid $1.5 billion and $1.4 billion to repurchase 9.5 million and 9.4 million shares of our common stock, respectively, under our share repurchase program. As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program.

Cash Dividends to Stockholders

During the year ended December 31, 2023, we paid aggregate dividends of $1.62 per share of common stock, for a total of $393 million. We paid aggregate dividends of $1.385 per share of common stock, for a total of $349 million during the year ended December 31, 2022.

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.

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

48

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 Physical 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 physical 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 physical 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 December 31, 2023 and 2022 (in millions), which entirely consisted of physical liquefaction supply derivatives. The changes in fair value shown are limited to instruments still held at the end of each respective period.

	Year Ended December 31,
	2023		2022
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	5,700	$	(6,493)

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 during the years ended December 31, 2023 and 2022.

The estimated fair value of level 3 derivatives recognized in our Consolidated Balance Sheets as of December 31, 2023 and 2022 amounted to a liability of $2.2 billion and $9.9 billion, respectively, consisting entirely of physical liquefaction supply derivatives.

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 given the level of volatility in the current year. 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.

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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.

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Marketing and Trading Commodity Price Risk

We have commodity derivatives consisting of natural gas supply contracts for the commissioning and operation of the SPL Project and the CCL Project, and associated economic hedges (collectively, the “Liquefaction Supply Derivatives”). We have also entered into 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):

	December 31, 2023				December 31, 2022
	Fair Value		Change in Fair Value		Fair Value		Change in Fair Value
Liquefaction Supply Derivatives	$	(2,117)	$	1,526	$	(10,019)	$	2,249
LNG Trading Derivatives	10		12		(46)		15

See Note 7—Derivative Instruments of our Notes to Consolidated Financial Statements for additional details about our commodity derivative instruments.

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ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES

Management’s Report to the Stockholders of Cheniere Energy, Inc.	52
Reports of Independent Registered Public Accounting Firm	53
Consolidated Statements of Operations	56
Consolidated Balance Sheets	57
Consolidated Statements of Stockholders’ Equity (Deficit)	58
Consolidated Statements of Cash Flows	59
Notes to Consolidated Financial Statements	60
Note 1—Organization and Nature of Operations	60
Note 2—Summary of Significant Accounting Policies	60
Note 3—Restricted Cash and Cash Equivalents	67
Note 4—Trade and Other Receivables, Net of Current Expected Credit Losses	67
Note 5—Inventory	67
Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation	68
Note 7—Derivative Instruments	69
Note 8—Other Non-current Assets, Net	74
Note 9—Non-controlling Interest and Variable Interest Entities	74
Note 10—Accrued Liabilities	76
Note 11—Debt	77
Note 12—Leases	81
Note 13—Revenues	83
Note 14—Related Party Transactions	86
Note 15—Income Taxes	87
Note 16—Share-based Compensation	89
Note 17—Employee Benefit Plan	92
Note 18—Net Income (Loss) per Share Attributable to Common Stockholders	92
Note 19—Share Repurchase Programs	93
Note 20—Commitments and Contingencies	93
Note 21—Customer Concentration	95
Note 22—Supplemental Cash Flow Information	96

51

MANAGEMENT’S REPORT TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries (“Cheniere”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2023, based on criteria in Internal Control—Integrated Framework (2013) issued by the COSO.

Cheniere’s independent registered public accounting firm, KPMG LLP, has issued an audit report on Cheniere’s internal control over financial reporting as of December 31, 2023, which is contained in this Form 10-K.

Management’s Certifications

The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.

CHENIERE ENERGY, INC.

By:	/s/ Jack A. Fusco	By:	/s/ Zach Davis
	Jack A. Fusco		Zach Davis
	President and Chief Executive Officer (Principal Executive Officer)		Executive Vice President and Chief Financial Officer (Principal Financial Officer)

52

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Cheniere Energy, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries (the Company) as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 21, 2024 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Fair value of the level 3 liquefaction supply derivatives

As discussed in Notes 2 and 7 to the consolidated financial statements, the Company recorded fair value of level 3 liquefaction supply derivatives of $(2,178) million as of December 31, 2023, which included the fair value of IPM agreements. The IPM agreements are natural gas supply contracts for the operation of the liquefied natural gas facilities. The fair value of the IPM agreements is developed using internal models, including option pricing models. The models incorporate significant unobservable inputs, including future prices of energy units in unobservable periods and volatility.

We identified the evaluation of the fair value of the level 3 liquefaction supply derivatives for certain IPM agreements as a critical audit matter. Specifically, complex auditor judgment and specialized skills and knowledge were required to evaluate the appropriateness and application of the option pricing model as well as the assumptions for future prices of energy units in unobservable periods and volatility.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the valuation of liquefaction supply derivatives,

53

including those under certain IPM agreements. This included controls related to the appropriateness and application of the option pricing model and the evaluation of assumptions for future prices of energy units in unobservable periods and volatility. We involved valuation professionals with specialized skills and knowledge who assisted in testing management’s process for developing the fair value of certain IPM agreements by:

•evaluating the design and testing the operating effectiveness of certain internal controls related to the appropriateness and application of the option pricing model

•evaluating the appropriateness and application of the option pricing model by inspecting the contractual agreements and model documentation to determine whether the model is suitable for its intended use

•evaluating the reasonableness of management’s assumptions for future prices of energy units in unobservable periods and volatility by comparing to market data.

/s/    KPMG LLP

KPMG LLP

We have served as the Company’s auditor since 2014.

Houston, Texas

February 21, 2024

54

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and Board of Directors

Cheniere Energy, Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Cheniere Energy, Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2023 and 2022, the related consolidated statements of operations, stockholders’ equity (deficit), and cash flows for each of the years in the three-year period ended December 31, 2023, and the related notes (collectively, the consolidated financial statements), and our report dated February 21, 2024 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/    KPMG LLP

KPMG LLP

Houston, Texas

February 21, 2024

55

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in millions, except per share data)

	Year Ended December 31,
	2023		2022		2021
Revenues
LNG revenues	$	19,569	$	31,804	$	15,395
Regasification revenues	135		1,068		269
Other revenues	690		556		200
Total revenues	20,394		33,428		15,864
Operating costs and expenses
Cost of sales (excluding items shown separately below)	1,356		25,632		13,773
Operating and maintenance expense	1,835		1,681		1,444
Selling, general and administrative expense	474		416		325
Depreciation and amortization expense	1,196		1,119		1,011
Other	44		21		12
Total operating costs and expenses	4,905		28,869		16,565
Income (loss) from operations	15,489		4,559		(701)
Other income (expense)
Interest expense, net of capitalized interest	(1,141)		(1,406)		(1,438)
Gain (loss) on modification or extinguishment of debt	15		(66)		(116)
Interest and dividend income	211		57		3
Other income (expense), net	4		(50)		(26)
Total other expense	(911)		(1,465)		(1,577)
Income (loss) before income taxes and non-controlling interest	14,578		3,094		(2,278)
Less: income tax provision (benefit)	2,519		459		(713)
Net income (loss)	12,059		2,635		(1,565)
Less: net income attributable to non-controlling interest	2,178		1,207		778
Net income (loss) attributable to common stockholders	$	9,881	$	1,428	$	(2,343)
Net income (loss) per share attributable to common stockholders—basic (1)	$	40.99	$	5.69	$	(9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	40.72	$	5.64	$	(9.25)
Weighted average number of common shares outstanding—basic	241.0		251.1		253.4
Weighted average number of common shares outstanding—diluted	242.6		253.4		253.4
___________________
(1)Earnings per share in the table may not recalculate exactly due to rounding because it is calculated based on whole numbers, not the rounded numbers presented.

The accompanying notes are an integral part of these consolidated financial statements.

56

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS (1)

(in millions, except share data)

	December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	4,066	$	1,353
Restricted cash and cash equivalents	459		1,134
Trade and other receivables, net of current expected credit losses	1,106		1,944
Inventory	445		826
Current derivative assets	141		120
Margin deposits	18		134
Other current assets, net	96		97
Total current assets	6,331		5,608
Property, plant and equipment, net of accumulated depreciation	32,456		31,528
Operating lease assets	2,641		2,625
Derivative assets	863		35
Deferred tax assets	26		864
Other non-current assets, net	759		606
Total assets	$	43,076	$	41,266
LIABILITIES AND STOCKHOLDERS’ EQUITY (DEFICIT)
Current liabilities
Accounts payable	$	181	$	124
Accrued liabilities	1,780		2,679
Current debt, net of discount and debt issuance costs	300		813
Deferred revenue	179		234
Current operating lease liabilities	655		616
Current derivative liabilities	750		2,301
Other current liabilities	43		28
Total current liabilities	3,888		6,795
Long-term debt, net of discount and debt issuance costs	23,397		24,055
Operating lease liabilities	1,971		1,971
Finance lease liabilities	467		494
Derivative liabilities	2,378		7,947
Deferred tax liabilities	1,545		—
Other non-current liabilities	410		175
Commitments and contingencies (see Note 20)
Stockholders’ equity (deficit)
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	—		—
Common stock: $0.003 par value, 480.0 million shares authorized; 277.9 million shares and 276.7 million shares issued at December 31, 2023 and 2022, respectively	1		1
Treasury stock: 40.9 million shares and 31.2 million shares at December 31, 2023 and 2022, respectively, at cost	(3,864)		(2,342)
Additional paid-in-capital	4,377		4,314
Accumulated income (deficit)	4,546		(4,942)
Total Cheniere stockholders’ equity (deficit)	5,060		(2,969)
Non-controlling interest	3,960		2,798
Total stockholders’ equity (deficit)	9,020		(171)
Total liabilities and stockholders’ equity (deficit)	$	43,076	$	41,266

(1)Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (DEFICIT)

(in millions)

	Total Stockholders’ Equity (Deficit)
	Common Stock			Treasury Stock			Additional Paid-in Capital		Accumulated Income (Deficit)		Non-controlling Interest		Total Equity (Deficit)
	Shares	Par Value Amount		Shares	Amount
Balance at December 31, 2020	252.3	$	1	20.8	$	(872)	$	4,273	$	(3,593)	$	2,409	$	2,218
Vesting of share-based compensation awards	2.1	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		105		—		—		105
Issued shares withheld from employees related to share-based compensation, at cost	(0.7)	—		0.7	(47)		(1)		—		—		(48)
Shares repurchased, at cost	(0.1)	—		0.1	(9)		—		—		—		(9)
Net income attributable to non-controlling interest	—	—		—	—		—		—		778		778
Distributions and dividends to non-controlling interest	—	—		—	—		—		—		(649)		(649)
Dividends declared ($0.33 per common share)	—	—		—	—		—		(85)		—		(85)
Net loss attributable to common stockholders	—	—		—	—		—		(2,343)		—		(2,343)
Balance at December 31, 2021	253.6	1		21.6	(928)		4,377		(6,021)		2,538		(33)
Vesting of share-based compensation awards	1.5	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		112		—		—		112
Issued shares withheld from employees related to share-based compensation, at cost	(0.3)	—		0.3	(41)		(22)		—		—		(63)
Shares repurchased, at cost	(9.3)	—		9.3	(1,373)		—		—		—		(1,373)
Adoption of ASU 2020-06, net of tax	—	—		—	—		(153)		4		—		(149)
Net income attributable to non-controlling interest	—	—		—	—		—		—		1,207		1,207
Distributions to non-controlling interest	—	—		—	—		—		—		(947)		(947)
Dividends declared ($1.385 per common share)	—	—		—	—		—		(353)		—		(353)
Net income attributable to common stockholders	—	—		—	—		—		1,428		—		1,428
Balance at December 31, 2022	245.5	1		31.2	(2,342)		4,314		(4,942)		2,798		(171)
Vesting of share-based compensation awards	1.2	—		—	—		—		—		—		—
Share-based compensation	—	—		—	—		100		—		—		100
Issued shares withheld from employees related to share-based compensation, at cost	(0.2)	—		0.2	(26)		(37)		—		—		(63)
Shares repurchased, at cost	(9.5)	—		9.5	(1,496)		—		—		—		(1,496)
Net income attributable to non-controlling interest	—	—		—	—		—		—		2,178		2,178
Distributions to non-controlling interest	—	—		—	—		—		—		(1,016)		(1,016)
Dividends declared ($1.62 per common share)	—	—		—	—		—		(393)		—		(393)
Net income attributable to common stockholders	—	—		—	—		—		9,881		—		9,881
Balance at December 31, 2023	237.0	$	1	40.9	$	(3,864)	$	4,377	$	4,546	$	3,960	$	9,020

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in millions)

	Year Ended December 31,
	2023		2022		2021
Cash flows from operating activities
Net income (loss)	$	12,059	$	2,635	$	(1,565)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(2)		(5)		—
Depreciation and amortization expense	1,196		1,119		1,011
Share-based compensation expense	250		205		140
Amortization of debt issuance costs, premium and discount	44		57		72
Reduction of right-of-use assets	623		607		393
Loss (gain) on modification or extinguishment of debt	(15)		66		116
Total losses (gains) on derivative instruments, net	(7,890)		6,531		5,989
Net cash used for settlement of derivative instruments	(79)		(904)		(1,579)
Deferred taxes	2,389		440		(715)
Repayment of paid-in-kind interest related to repurchase of convertible notes	—		(13)		(190)
Other, net	20		92		52
Changes in operating assets and liabilities:
Trade and other receivables	840		(502)		(799)
Inventory	377		(123)		(409)
Margin deposits	116		631		(741)
Accounts payable and accrued liabilities	(982)		250		1,144
Total deferred revenue	3		124		55
Total operating lease liabilities	(607)		(622)		(418)
Other, net	76		(65)		(87)
Net cash provided by operating activities	8,418		10,523		2,469
Cash flows from investing activities
Property, plant and equipment, net	(2,121)		(1,830)		(966)
Proceeds from sale of property, plant and equipment	—		1		68
Investment in equity method investments	(61)		(15)		—
Other, net	(20)		—		(14)
Net cash used in investing activities	(2,202)		(1,844)		(912)
Cash flows from financing activities
Proceeds from issuances of debt	1,397		1,575		5,911
Redemptions, repayments and repurchases of debt	(2,598)		(6,771)		(6,810)
Distributions to non-controlling interest	(1,016)		(947)		(649)
Payments related to tax withholdings for share-based compensation	(63)		(63)		(48)
Repurchase of common stock	(1,473)		(1,373)		(9)
Dividends to stockholders	(393)		(349)		(85)
Other, net	(34)		(86)		(127)
Net cash used in financing activities	(4,180)		(8,014)		(1,817)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2		5		—
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	2,038		670		(260)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	2,487		1,817		2,077
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$	4,525	$	2,487	$	1,817

Balances per Consolidated Balance Sheets:

	December 31, 2023		December 31, 2022
Cash and cash equivalents	$	4,066	$	1,353
Restricted cash and cash equivalents	459		1,134
Total cash, cash equivalents and restricted cash and cash equivalents	$	4,525	$	2,487

The accompanying notes are an integral part of these consolidated financial statements.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

NOTE 1—ORGANIZATION AND NATURE OF OPERATIONS

We operate two natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”).

CQP owns the Sabine Pass LNG Terminal, which has natural gas liquefaction facilities consisting of six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and three marine berths. We also own and operate a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several interstate and intrastate pipelines (the “Creole Trail Pipeline”). As of December 31, 2023, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.

The Corpus Christi LNG Terminal currently has three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks and two marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).

We are pursuing expansion projects to provide additional liquefaction capacity at the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”), and we have commenced commercialization to support the additional liquefaction capacity associated with these expansion projects.

NOTE 2—SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

VIEs

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

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

Non-controlling Interests

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

recognized within equity. See Note 9—Non-controlling Interest and Variable Interest Entities for additional details about our non-controlling interest.

Estimates

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

Fair Value Measurements

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

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

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 7—Derivative Instruments, and liability-classified share-based compensation awards, as disclosed in Note 16—Share-Based Compensation.

The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 11—Debt for our debt fair value estimates, including our estimation methods.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 13—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition.

Cash and Cash Equivalents

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

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

Current Expected Credit Losses

Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. We record charges and reversals of current expected credit losses in selling, general and administrative in our Consolidated Statements of Operations.

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

	Year Ended December 31,
	2023		2022		2021
Current expected credit losses, beginning of period	$	5	$	9	$	7
Charges (reversals)	(2)		(4)		2
Current expected credit losses, end of period	$	3	$	5	$	9

Inventory

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

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of our LNG terminals once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary review and selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.

We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except land which is not depreciated. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.

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

We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2023, 2022 and 2021.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Advances of Cash and Conveyed Assets to Service Providers

We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances are recognized within other non-current assets on our Consolidated Balance Sheets and amortized within depreciation and amortization expense on our Consolidated Statements of Operations over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately 31 years as of both December 31, 2023 and 2022.

Interest Capitalization

We capitalize interest costs mainly during the construction period of our LNG terminals and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings. We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Leases

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

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

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

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

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

When we determine the arrangement is, or contains, a lease in which we are the lessor or sublessor, we assess classification of the lease as either an operating lease, sales-type lease or direct financing lease. All of our arrangements have been assessed as operating leases and consist of sublessor arrangements in which we have not been relieved of our primary

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

obligation under the original lease. Our sublessor arrangements are not recognized on our Consolidated Balance Sheets and we recognize income from these arrangements on a straight-line basis over the sublease term.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets related to our long-term SPAs and regasification contracts, each discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits on our Consolidated Balance Sheets. Our FX derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

We have contracted our anticipated production capacity under SPAs and under IPM agreements. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers. 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. We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL’s customers through our integrated marketing function. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective agreements.

Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.

Debt

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

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method.

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CHENIERE ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

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

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

Asset Retirement Obligations

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

We have not recorded an ARO associated with the Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Share-based Compensation

We have awarded share-based compensation in the form of restricted stock shares, restricted stock units, performance stock units and phantom units. The awards and our related accounting policies are more fully described in Note 16—Share-based Compensation.

Foreign Currency

The functional currency of all of our subsidiaries is the U.S. dollar. Certain of our subsidiaries transact in currencies outside of the U.S. dollar, which gives rise to the recognition of transaction gains and losses based on the change in exchange rates between the U.S. dollar and the currency in which the foreign currency transaction is denominated. During the years ended December 31, 2023, 2022 and 2021, we recognized net transaction gains (losses) totaling $(20) million, $60 million and $33 million, respectively, substantially all of which related to commercial transactions executed by Cheniere Marketing. The transaction gains and losses on such commercial transactions primarily consisted of those on Euro denominated receivables and related foreign currency hedges arising from the sale of cargoes, which are presented within LNG revenues in our Consolidated Statements of Operations with the underlying activities. The remaining transaction gains and losses are presented primarily within other income (expense), net in our Consolidated Statements of Operations.

Income Taxes

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes.

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

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

We account for our federal investment tax credits under the flow-through method.

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

Net Income (Loss) Per Share

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

Refer to Note 18—Net Income (Loss) per Share Attributable to Common Stockholders for additional details of the computation for the years ended December 31, 2023, 2022 and 2021.

Business Segment

We have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker is regularly provided with consolidated financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our customers. The financial measures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) attributable to common stockholders and total consolidated assets, as presented in our Consolidated Financial Statements.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 11—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the

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impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

ASU 2023-07

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. We plan to adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

NOTE 3—RESTRICTED CASH AND CASH EQUIVALENTS

As of December 31, 2023 and 2022, we had $459 million and $1.1 billion of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted, primarily to the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements.

NOTE 4—TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

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

	December 31,
	2023		2022
Trade receivables
SPL and CCL	$	525	$	922
Cheniere Marketing	451		917
Other	4		4
Other receivables	126		101
Total trade and other receivables, net of current expected credit losses	$	1,106	$	1,944

NOTE 5—INVENTORY

Inventory consisted of the following (in millions):

	December 31,
	2023		2022
LNG in-transit	$	112	$	356
LNG	88		212
Materials	207		194
Natural gas	35		60
Other	3		4
Total inventory	$	445	$	826

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NOTE 6—PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	December 31,
	2023		2022
Terminal and related assets
Terminal and interconnecting pipeline facilities (1)	$	34,069	$	33,815
Land	463		451
Construction-in-process	3,480		1,685
Accumulated depreciation	(6,099)		(4,985)
Total terminal and related assets, net of accumulated depreciation	31,913		30,966
Fixed assets and other
Computer and office equipment	37		33
Furniture and fixtures	31		20
Computer software	125		121
Leasehold improvements	43		48
Other	21		20
Accumulated depreciation	(183)		(191)
Total fixed assets and other, net of accumulated depreciation	74		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(63)		(22)
Total assets under finance leases, net of accumulated depreciation	469		511
Property, plant and equipment, net of accumulated depreciation	$	32,456	$	31,528

(1)Includes power generation facility and associated power infrastructure located near Corpus Christi, Texas that was acquired during the year ended December 31, 2023 to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

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

	Year Ended December 31,
	2023		2022		2021
Depreciation expense	$	1,190	$	1,113	$	1,006
Offsets to LNG terminal costs (1)	—		204		319

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Projects during the testing phase for its construction.

Terminal and related assets

Our terminal and related assets are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of our terminal and related assets have depreciable lives between 6 and 50 years, as follows:

Components	Useful life (years)
LNG storage tanks	50
Natural gas pipeline facilities	40
Marine berth, electrical, facility and roads	35
Water pipelines	30
Regasification processing equipment	30
Sendout pumps	20
Liquefaction processing equipment	6-50
Other	10-30

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Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

Assets under Finance Leases

Our assets under finance leases primarily consist of certain tug vessels and LNG vessel time charters that meet the classification of a finance lease. These assets are depreciated on a straight-line method over the respective lease term. See Note 12—Leases for additional details of our finance leases.

NOTE 7—DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

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

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

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

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow, fair value or net investment hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case such changes are capitalized.

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

	Fair Value Measurements as of
	December 31, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	25	$	36	$	(2,178)	$	(2,117)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	30		(20)		—		10		1		(47)		—		(46)
FX Derivatives liability	—		(17)		—		(17)		—		(28)		—		(28)

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

We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market

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data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

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

The Level 3 fair value measurements of our natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(2,178)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.090) - $0.505 / $(0.060)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	87% - 379% / 196%

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

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

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

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

	Year Ended December 31,
	2023		2022		2021
Balance, beginning of period	$	(9,924)	$	(4,036)	$	241
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	5,685		(5,120)		(2,509)
Included in cost of sales, new deals (3)	15		(1,373)		(1,796)
Purchases and settlements:
Purchases (4)	—		—		(1)
Settlements (5)	2,045		605		29
Transfers out of level 3 (6)	1		—		—
Balance, end of period	$	(2,178)	$	(9,924)	$	(4,036)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	5,700	$	(6,493)	$	(4,305)

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

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

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

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

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

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

All existing counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2023, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

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

The following table shows the notional amounts of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”):

	December 31, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	14,019	49	14,504	50

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of December 31, 2023.

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location (1)		Year Ended December 31,
			2023		2022		2021
LNG Trading Derivatives	LNG revenues		$	139	$	(387)	$	(1,812)
LNG Trading Derivatives	Recovery (cost) of sales		(132)		(2)		91
Liquefaction Supply Derivatives (2)	LNG revenues		(5)		2		3
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales		7,912		(6,203)		(4,303)

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

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

FX Derivatives

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

The total notional amount of our FX Derivatives was $789 million and $619 million as of December 31, 2023 and 2022, respectively.

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location		Year Ended December 31,
			2023		2022		2021
FX Derivatives	LNG revenues		$	(24)	$	57	$	33

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Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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

	December 31, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	49	$	92	$	—	$	141
Derivative assets	863		—		—		863
Total derivative assets	912		92		—		1,004
Current derivative liabilities	(651)		(82)		(17)		(750)
Derivative liabilities	(2,378)		—		—		(2,378)
Total derivative liabilities	(3,029)		(82)		(17)		(3,128)
Derivative asset (liability), net	$	(2,117)	$	10	$	(17)	$	(2,124)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $3 million and $111 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $4 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $15 million and $23 million, as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $3 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

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Consolidated Balance Sheets Presentation

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:

	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives
As of December 31, 2023
Gross assets	$	1,272	$	94	$	—
Offsetting amounts	(360)		(2)		—
Net assets (1)	$	912	$	92	$	—
Gross liabilities	$	(3,095)	$	(110)	$	(17)
Offsetting amounts	66		28		—
Net liabilities (2)	$	(3,029)	$	(82)	$	(17)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $141 million and $863 million, respectively, as of December 31, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $750 million and $2,378 million, respectively, as of December 31, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

NOTE 8—OTHER NON-CURRENT ASSETS, NET

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	244	$	171
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminals, net of accumulated amortization	175		170
Equity method investments (1)	111		16
Goodwill	77		77
Debt issuance costs and debt discount, net of accumulated amortization	58		60
Advance tax-related payments and receivables	20		20
Other, net	74		92
Total other non-current assets, net	$	759	$	606

(1)Includes investment in equity interest and capacity agreements with a pipeline developer and operator, expected to support delivery of natural gas feedstock to the Corpus Christi LNG Terminal for the Corpus Christi Stage 3 Project.

NOTE 9—NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITIES

We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management, Inc. (“Brookfield”) and the public. We also own 100% of the general partner interest and the incentive distribution rights in CQP.

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CQP is a limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG Terminal and related assets. Our subsidiary, Cheniere Partners GP, is the general partner of CQP. In 2012, CQP, Cheniere and Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) entered into a unit purchase agreement whereby CQP sold 100.0 million Class B units to Blackstone CQP Holdco in a private placement. The board of directors of Cheniere Partners GP was modified to include three directors appointed by Blackstone CQP Holdco, four directors appointed by us and four independent directors mutually agreed upon by Blackstone CQP Holdco and us and appointed by us. In addition, we provided Blackstone CQP Holdco with a right to maintain one board seat on our Board of Directors (our “Board”). A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by Blackstone CQP Holdco, two directors appointed by us and two independent directors. Blackstone CQP Holdco will no longer be entitled to appoint Cheniere Partners GP directors in the event that Blackstone CQP Holdco’s ownership in CQP is less than 20% of outstanding common units and subordinated units.

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

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

	December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	575	$	904
Restricted cash and cash equivalents	56		92
Trade and other receivables, net of current expected credit losses	373		627
Other current assets	215		269
Total current assets	1,219		1,892
Property, plant and equipment, net of accumulated depreciation	16,212		16,725
Other non-current assets, net	309		288
Total assets	$	17,740	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	811	$	1,384
Current debt, net of discount and debt issuance costs	300		—
Current derivative liabilities	196		769
Other current liabilities	201		191
Total current liabilities	1,508		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,606		16,198
Derivative liabilities	1,531		3,024
Other non-current liabilities	160		98
Total liabilities	$	18,805	$	21,664

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NOTE 10—ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	December 31,
	2023		2022
Natural gas purchases	$	729	$	1,621
Interest costs and related debt fees	399		383
LNG terminals and related pipeline costs	235		240
Compensation and benefits	266		245
LNG purchases	23		88
Other accrued liabilities	128		102
Total accrued liabilities	$	1,780	$	2,679

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NOTE 11—DEBT

Debt consisted of the following (in millions): 

	December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.750% due 2024 (the “2024 SPL Senior Notes”)	$	300	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,432		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,432		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.950% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,888		25,086
Current debt, net of discount and debt issuance costs	(300)		(813)
Long-term portion of discount and debt issuance costs, net	(191)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,397	$	24,055

(1)The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.

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Senior Notes

SPL Senior Secured Notes

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

CQP Senior Notes

The CQP Senior Notes, except the 2033 CQP Senior Notes, are jointly and severally guaranteed by each of CQP’s subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP and the 2033 CQP Senior Notes are jointly and severally guaranteed by each of CQP’s current and future subsidiaries who guarantee the CQP Revolving Credit Facility from time to time (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are senior obligations of CQP, ranking equally in right of payment with CQP’s other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of CQP’s secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets (or 15% in the case of 2033 CQP Senior Notes), the CQP Senior Notes will be secured by a first-priority lien (subject to permitted encumbrances) on substantially all the existing and future tangible and intangible assets and rights of CQP and the CQP Guarantors and equity interests in the CQP Guarantors. The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of any other senior secured obligations. CQP may, at any time, redeem all or part of the CQP Senior Notes at specified prices set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

CCH Senior Secured Notes

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

Cheniere Senior Notes

The Cheniere Senior Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the Cheniere Senior Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The Cheniere Senior Notes are currently unsecured, but in certain instances may become secured in the future in connection with the incurrence of additional secured indebtedness by us. When required, the Cheniere Senior Notes will be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries), which liens rank pari passu with the liens securing the Cheniere Revolving Credit Facility. As of December 31, 2023, the Cheniere Senior Notes are not guaranteed by any of our subsidiaries. In the future, any subsidiary that guarantees any of our material indebtedness will also guarantee the Cheniere Senior Notes. We may, at any time, redeem all or part of the Cheniere Senior Notes at specified prices set forth in the indenture governing the Cheniere Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

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Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):

Years Ending December 31,	Principal Payments
2024	$	300
2025	3,543
2026	1,607
2027	2,889
2028	3,091
Thereafter	12,458
Total	$	23,888

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of December 31, 2023 (in millions):

	SPL Revolving Credit Facility (1)(2)		CQP Revolving Credit Facility (1)(3)		CCH Credit Facility (4)		CCH Working Capital Facility (5)		Cheniere Revolving Credit Facility (6)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	280		—		—		155		—
Available commitment	$	720	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (7)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.075% - 2.20% or base rate plus 0.075% - 1.2%
Commitment fees on undrawn balance (7)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (8)
Maturity date	June 23, 2028		June 23, 2028		(9)		June 15, 2027		October 28, 2026

(1)In June 2023, CQP and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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

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

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

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

(6)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR. The Cheniere Revolving Credit Facility contains a financial covenant requiring us to maintain a non-consolidated leverage ratio not to exceed 5.50:1.00 as of the end of any fiscal quarter if (i) as of the last day of such fiscal quarter the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit is greater than 35% of

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the aggregate commitments under the Cheniere Revolving Credit Facility (a “Covenant Trigger Event”) or (ii) a Covenant Trigger Event had occurred and been continuing as of the last day of the immediately preceding fiscal quarter and as of the last day of such ending fiscal quarter such Covenant Trigger Event had not ceased for a period of at least thirty consecutive days.

(7)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

(8)In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.

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

Loss on Extinguishment of Debt Related to Termination of Agreement with Chevron

Our loss on modification or extinguishment of debt for the year ended December 31, 2022 includes a loss on extinguishment of prospective payment obligations of $31 million associated with a premium paid to Chevron U.S.A. Inc. (“Chevron”) to terminate a revenue sharing arrangement under the terminal marine services agreement with them. See Note 13—Revenue for further discussion of the termination of agreements with Chevron.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us, our subsidiaries’ and its restricted subsidiaries’ ability to make certain investments or pay dividends or distributions. SPL and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. At December 31, 2023, our restricted net assets of consolidated subsidiaries were approximately $203 million.

As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Year Ended December 31,
	2023		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	—	$	36
Amortization of debt discount and debt issuance costs	—		—		10
Total interest cost related to convertible notes	—		—		46
Interest cost on debt and finance leases excluding convertible notes	1,265		1,485		1,558
Total interest cost	$	1,265	$	1,485	1,604
Capitalized interest	(124)		(79)		(166)
Total interest expense, net of capitalized interest	$	1,141	$	1,406	$	1,438

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Fair Value Disclosures

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

	December 31, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,888	$	23,062	$	25,086	$	23,500

(1)As of both December 31, 2023 and 2022, $3.0 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

NOTE 12—LEASES

Our leased assets consist primarily of LNG vessels leased under time charters (“vessel charters”) and additionally include tug vessels, office space and facilities and land sites. All of our leases are classified as operating leases except for certain of our vessel charters, tug vessels and marine equipment, which are classified as finance leases.

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

		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,641	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	469		511
Total right-of-use assets		$	3,110	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	655	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,971		1,971
Non-current finance lease liabilities	Finance lease liabilities	467		494
Total lease liabilities		$	3,128	$	3,109

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

	Consolidated Statements of Operations Location	Year Ended December 31,
		2023		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	783	$	828	$	621
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	50		12		3
Interest on lease liabilities	Interest expense, net of capitalized interest	35		14		9
Total lease cost		$	868	$	854	$	633
(a) Included in operating lease cost:
Short-term lease costs		$	33	$	122	$	139
Variable lease costs		17		18		21

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

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Future annual minimum lease payments for operating and finance leases as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	752	$	67
2025	612		72
2026	480		75
2027	383		77
2028	228		73
Thereafter	638		355
Total lease payments (1)	3,093		719
Less: Interest	(467)		(217)
Present value of lease liabilities	$	2,626	$	502

(1)Does not include approximately $3.8 billion of legally binding minimum payments for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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

	December 31, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.3	9.7	5.9	10.6
Weighted-average discount rate (1)	4.7%	7.7%	4.2%	7.8%

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

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

	Year Ended December 31,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	720	$	713	$	483
Operating cash flows from finance leases	35		14		10
Financing cash flows from finance leases	28		7		—
Right-of-use assets obtained in exchange for operating lease liabilities	646		1,220		1,736
Right-of-use assets obtained in exchange for finance lease liabilities (1)	8		473		—

(1)     Includes $88 million reclassified from operating leases to finance leases during the year ended December 31, 2022 as a result of modification of the underlying vessel charters.

LNG Vessel Subcharters

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

	Year Ended December 31,
	2023		2022		2021
Fixed income	$	446	$	371	$	72
Variable income	57		79		37
Total sublease income	$	503	$	450	$	109

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Future annual minimum sublease payments to be received from LNG vessel subcharters as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	158
2025	5
Total sublease payments	$	163

NOTE 13—REVENUES

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

	Year Ended December 31,
	2023		2022		2021
Revenues from contracts with customers
LNG revenues	$	19,459	$	32,132	$	17,171
Regasification revenues	135		1,068		269
Other revenues	187		107		91
Total revenues from contracts with customers	19,781		33,307		17,531
Net derivative gain (loss) (1)	110		(328)		(1,776)
Other (2)	503		449		109
Total revenues	$	20,394	$	33,428	$	15,864

(1)See Note 7—Derivative Instruments for additional information about our derivatives.

(2)Primarily includes revenues from LNG vessel subcharters. See Note 12—Leases for additional information about our subleases.

LNG Revenues

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

We intend to primarily use LNG sourced from our Sabine Pass LNG Terminal or our Corpus Christi LNG Terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $359 million, $760 million and $499 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the delivery terms described above, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.

When we sell LNG on a DAT basis, we consider all transportation costs, including vessel chartering, loading/unloading and canal fees, as fulfillment costs and not as separate services provided to the customer within the arrangement, regardless of

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whether or not such activities occur prior to or after the customer obtains control of the LNG. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Consolidated Statements of Operations, and where we have concluded that we acted as an agent are netted within cost of sales in our Consolidated Statements of Operations.

Regasification Revenues

The Sabine Pass LNG Terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 1 Bcf/d of the regasification capacity at the Sabine Pass LNG Terminal has been reserved under a long-term TUA with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), under which they are required to pay fixed monthly fees to SPLNG, regardless of their use of the LNG terminal, aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Prior to its cancellation effective December 31, 2022, SPLNG also had a TUA for 1 Bcf/d with Chevron, as further described below. Approximately 2 Bcf/d of regasification capacity of the Sabine Pass LNG Terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs.

In 2012, SPL entered into a partial TUA assignment agreement with TotalEnergies, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit SPL to more flexibly manage its LNG storage capacity. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred to TotalEnergies are recognized in operating and maintenance expense. During the years ended December 31, 2023, 2022 and 2021, SPL recorded $132 million, $131 million and $129 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Termination Agreement with Chevron

In June 2022, Chevron entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million reported, upon receipt of the Termination Fee, as a loss on extinguishment of debt on our Consolidated Statements of Operations allocable to a premium paid to Chevron to terminate a revenue sharing arrangement with them that was accounted for as debt.

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Contract Assets and Liabilities

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	250	$	186

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due and also include consideration paid to our customers that will reduce the amount of revenue recognized as the remaining performance obligations in the contract are satisfied. The change in contract assets between the years ended December 31, 2023 and 2022 was primarily attributable to additional revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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

	Year Ended December 31, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	218
Revenue recognized from prior period deferral	(244)
Deferred revenue, end of period	$	294

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2023 and 2022 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

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

	December 31, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	111.0	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	111.7		$	112.8

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

(2)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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met and consideration is not otherwise constrained from ultimate pricing and receipt.

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We have elected the following exemptions which omit certain potential future sources of revenue from the table above:

(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Year Ended December 31,
	2023		2022
LNG revenues	69	%	72	%
Regasification revenues	7	%	2	%

NOTE 14—RELATED PARTY TRANSACTIONS

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

	Year Ended December 31,
	2023		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	$	—	$	—	$	1
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	10		7		7
Cost of sales
Natural Gas Supply Agreements (3)	—		—		162
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		1
Total cost of sales	—		—		163
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	9		9		9
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	62		72		46

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of CQP’s limited partner interests.

(2)Midship Pipeline is a subsidiary of Midship Holdings, LLC, which we recognize as an equity method investment.

(3)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, when the related party entity was acquired by a non-related party.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

	December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	3	$	1
Accrued liabilities	6		1

NOTE 15—INCOME TAXES

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

	Year Ended December 31,
	2023		2022		2021
U.S.	$	11,176	$	(1,575)	$	(2,317)
International	3,402		4,669		39
Total income (loss) before income taxes and non-controlling interest	$	14,578	$	3,094	$	(2,278)

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

	Year Ended December 31,
	2023		2022		2021
Current:
Federal	$	130	$	6	$	—
State	1		2		3
Foreign	(1)		11		5
Total current	130		19		8
Deferred:
Federal	2,377		320		(633)
State	15		118		(89)
Foreign	(3)		2		1
Total deferred	2,389		440		(721)
Total income tax provision (benefit)	$	2,519	$	459	$	(713)

Our income tax rates do not bear a customary relationship to statutory income tax rates. A reconciliation of the federal statutory income tax rate of 21% to our effective income tax rate is as follows: 

	Year Ended December 31,
	2023		2022		2021
U.S. federal statutory tax rate	21.0	%	21.0	%	21.0	%
Income not taxable to Cheniere	(3.1)		(8.2)		7.2
State tax, net of federal benefit	0.1		0.5		(2.5)
Foreign-derived intangible income deduction	(0.7)		(1.2)		—
Valuation allowance	—		2.6		5.6
Other	—		0.1		—
Effective tax rate as reported	17.3	%	14.8	%	31.3	%

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

	December 31,
	2023		2022
Deferred tax assets
Net operating loss (“NOL”) carryforwards
Federal	$	915	$	1,968
State	163		177
Federal and state tax credits	33		66
Derivative instruments	98		1,345
Operating lease liabilities	550		542
Other	298		311
Less: valuation allowance (1)	(147)		(143)
Total deferred tax assets	1,910		4,266
Deferred tax liabilities
Investment in partnerships	(309)		(211)
Property, plant and equipment	(2,564)		(2,646)
Operating lease assets	(538)		(536)
Other	(18)		(9)
Total deferred tax liabilities	(3,429)		(3,402)
Net deferred tax assets (liabilities)	$	(1,519)	$	864

(1)Valuation allowance primarily related to state NOL carryforward deferred tax assets and increased by $4 million and $80 million during the years ended December 31, 2023 and 2022, respectively, and decreased by $127 million during year ended December 31, 2021.

NOL and tax credit carryforwards

As of December 31, 2023, we had federal and state NOL carryforwards of approximately $4.3 billion and $2.2 billion, respectively. All of our NOLs have an indefinite carryforward period.

As of December 31, 2023, we had federal and state tax credit carryforwards of $32 million and $1 million, respectively, which will expire between 2028 and 2033. As of December 31, 2023, all of the federal tax credit carryforwards were foreign tax credit carryforwards.

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

Unrecognized Tax Benefits

As of December 31, 2023, we had unrecognized tax benefits of $73 million. If recognized, $66 million of unrecognized tax benefits would affect our effective tax rate in future periods. Interest and penalties related to income tax matters are recognized as part of income tax expense. Interest recognized as part of income tax provision was $4 million and zero as of December 31, 2023 and 2022, respectively, and cumulative accrued interest was $4 million and zero as of December 31, 2023 and 2022, respectively. There were no penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2023 and 2022. We do not expect the amount of our existing unrecognized tax benefit to significantly increase or decrease within the next 12 months.

We are subject to tax in the U.S. and various state and foreign jurisdictions and we are subject to periodic audits and reviews by taxing authorities. Federal and United Kingdom tax returns for the years after 2017 and state tax returns for the years after 2019 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

	Year Ended December 31,
	2023		2022
Balance at beginning of the year	$	74	$	65
Additions based on tax positions related to current year	—		10
Reductions for tax positions of prior years	(1)		(1)
Balance at end of the year	$	73	$	74

NOTE 16—SHARE-BASED COMPENSATION

We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the 2011 Incentive Plan, as amended (the “2011 Plan”) and the 2020 Incentive Plan (the “2020 Plan”). The 2011 Plan and the 2020 Plan provide for the issuance of 35.0 million shares and 8.0 million shares, respectively, of our common stock that may be in the form of various share-based performance awards as determined by the Compensation Committee of our Board (the “Compensation Committee”).

We initially recognize share-based compensation based upon the estimated fair value of awards.

For equity-classified share-based compensation awards, compensation cost is recognized based on the grant-date fair value and not subsequently remeasured unless modified. For liability-classified share-based compensation awards that cash settle or include an election to be cash settled, compensation costs are remeasured at fair value through settlement or maturity.

Except for awards that contain market conditions, the grant-date fair value is estimated based on our stock price on the grant date. The grant-date fair value of awards containing market conditions is estimated using a fair value model as further described herein.

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

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

The recognition period for share-based compensation costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period.

We account for forfeitures as they occur.

Total share-based compensation consisted of the following (in millions):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs before income taxes:
Equity awards	$	100	$	112	$	105
Liability awards	155		97		40
Total share-based compensation	255		209		145
Capitalized share-based compensation	(5)		(4)		(5)
Total share-based compensation costs before income taxes	$	250	$	205	$	140
Tax benefit associated with share-based compensation costs	$	54	$	48	$	33

    

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

The total unrecognized compensation cost at December 31, 2023 relating to non-vested share-based compensation arrangements consisted of the following:

	Unrecognized Compensation Cost (in millions)		Recognized over a weighted average period (years)
Restricted Stock Unit and Performance Stock Unit Awards	$	181	1.4

Equity-Classified Awards

Restricted Stock Share Awards

Restricted stock share awards are awards of common stock that are granted to the members of our Board of Directors for their service, subject to restrictions on transfer and to a risk of forfeiture if the recipient is unaffiliated with us prior to the lapse of the restrictions. These awards vest over a one-year service period. There were nominal non-vested restricted stock share awards outstanding as of December 31, 2023.

The fair value of restricted stock share awards vested for the year ended December 31, 2023 was $1 million.

Restricted Stock Units

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

The table below provides a summary of activity related to our equity-classified restricted stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	2.3	$	92.52
Granted	0.8	150.59
Forfeited	(0.1)	118.77
Modified to liability awards (1)	(0.2)	115.26
Vested (2)	(1.2)	84.12
Non-vested at December 31, 2023	1.6	$	123.24

(1)See further details in Liability-Classified Awards below.

(2)The total fair value of shares vested was $183 million for the year ended December 31, 2023.

Performance Stock Units

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

Where applicable, the compensation for performance stock units containing a market condition of ATSR is based on a fair value assigned to the market metric using a Monte Carlo model as of the grant date, which utilizes level 3 inputs such as projected stock volatility and projected risk free rates and remains constant through the vesting period for the equity-settled component.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

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

For performance stock units containing a cash-settlement feature, the compensation cost of the cash settled component is remeasured at each reporting period, as discussed in Liability-Classified Awards below.

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

	Year Ended December 31,
	2023		2022		2021
Fair value assumptions:
Dividend yield (1)	—	%	—	%	—	%
Expected volatility (2)	27.5% - 32.7%		36.4% - 40.2%		27.0% - 41.0%
Risk-free interest rate (2)	4.2% - 4.8%		4.4% - 4.7%		0.7% - 1.4%
Weighted average expected remaining term, in years	1.5		1.4		1.5

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

(2)Represents the range associated with individual vesting years.

The table below provides a summary of activity related to our equity-classified performance stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	0.6	$	92.11
Granted (1)	0.2	163.04
Incremental units achieved (2)	0.3	72.05
Forfeited	(0.1)	107.61
Modified to liability awards (3)	(0.3)	106.25
Vested (4)	(0.2)	55.26
Non-vested at December 31, 2023	0.5	$	124.19

(1)Includes 0.1 million performance stock units granted in 2023 to certain officers containing a cash settlement cap of $3 million.

(2)Represents incremental units recognized as a result of final performance measures or estimated measures.

(3)See further details in Liability-Classified Awards below.

(4)The total fair value of shares vested was $36 million for the year ended December 31, 2023.

Liability-Classified Awards

Restricted stock units and performance stock units granted to certain officers may be settled in cash in lieu of shares, following approval by the Compensation Committee, in order to limit dilution from equity grants consistent with our share repurchase program under our long-term capital allocation plan, provided that we have sufficient liquidity to do so and the officers maintain certain stock ownership requirements. The Compensation Committee also has authorization from the Board to permit certain officers to make an election to cash settle their earned performance stock units that are expected to vest in 2025 and restricted stock units that are expected to vest in 2025 and 2026. Notwithstanding those awards which contain a cash settlement option, performance stock units granted to certain officers contain a cash settlement cap of $3 million.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

A total of 0.5 million units were reclassified from equity to liability during the year ended December 31, 2023, as a result of modifications made for certain employees to settle certain awards in cash in lieu of shares. Under GAAP, the modifications are treated as an exchange of the original award for a new award. During the years ended December 31, 2023, 2022 and 2021, we recognized $86 million, $56 million and $18 million, respectively, in incremental expense as a result of the modifications, attributed to six, six, and five employees impacted, respectively.

During the year ended December 31, 2023, we paid $84 million to settle a total of 0.5 million liability-classified awards, which approximated the fair value of the awards on the settlement date and was inclusive of payout for an incremental 0.3 million of performance stock units based on final performance measures achieved.

As described above, liability-classified share-based compensation awards are remeasured at fair value through settlement or maturity. The fair value of non-vested liability-classified awards was $165 million and $98 million as of December 31, 2023 and 2022, respectively, and consisted of 0.2 million of unvested restricted stock units and 0.6 million of unvested performance stock units as of December 31, 2023 and 0.2 million of unvested restricted stock units and 0.1 million of unvested performance stock units as of December 31, 2022.

NOTE 17—EMPLOYEE BENEFIT PLAN

We have a defined contribution plan (“401(k) Plan”) which allows eligible employees to contribute up to 75% of their compensation up to the Internal Revenue Service maximum. We match each employee’s deferrals (contributions) up to 6% of compensation and may make additional contributions at our discretion. Employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $17 million, $16 million and $15 million for of the years ended December 31, 2023, 2022 and 2021, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

NOTE 18—NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

The following table reconciles basic and diluted weighted average common shares outstanding and common stock dividends declared (in millions, except per share data):

	Year Ended December 31,
	2023		2022		2021
Net income (loss) attributable to common stockholders	$	9,881	$	1,428	$	(2,343)
Weighted average common shares outstanding:
Basic	241.0		251.1		253.4
Dilutive unvested stock	1.6		2.3		—
Diluted	242.6		253.4		253.4
Net income (loss) per share attributable to common stockholders—basic (1)	$	40.99	$	5.69	$	(9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	40.72	$	5.64	$	(9.25)
Dividends paid per common share	$	1.62	$	1.385	$	0.33

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

On January 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Potentially dilutive securities that were not included in the diluted net income (loss) per share computations because their effects would have been anti-dilutive were as follows (in millions):

	Year Ended December 31,
	2023	2022	2021
Unvested stock (1)	—	—	1.8
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	0.3	—
Total potentially dilutive common shares	—	0.3	1.8

(1)Includes the impact of unvested shares containing performance conditions to the extent that the underlying performance conditions are satisfied based on actual results as of the respective period end dates.

(2)The 2045 Cheniere Convertible Senior Notes were redeemed or converted in cash on January 5, 2022. However, the adoption of ASU 2020-06 on January 1, 2022 required a presumption of share settlement for the purpose of calculating the impact to diluted earnings per share during the period the notes were outstanding in 2022. Such impact was anti-dilutive as a result of the reported net loss attributable to common stockholders during the 2022 period.

NOTE 19—SHARE REPURCHASE PROGRAMS

On September 7, 2021, our Board authorized a reset in the previously existing share repurchase program to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional three years beginning on October 1, 2021. 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. The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Year Ended December 31,
	2023		2022		2021
Total shares repurchased	9.54		9.35		0.10
Weighted average price paid per share	$	155.50	$	146.88	$	87.32
Total cost of repurchases (1)	$	1,484	$	1,373	$	9

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

As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program. Subsequent to December 31, 2023 and through February 16, 2024, we repurchased approximately 2.9 million shares for over $450 million.

NOTE 20—COMMITMENTS AND CONTINGENCIES

Commitments

We have various future commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2023 and thus are not recognized as liabilities in our Consolidated Financial Statements.

EPC Contract

CCL has a lump sum turnkey contract with Bechtel Energy Inc. (“Bechtel”) for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. The total contract price of the EPC contract is approximately $5.7 billion, inclusive of amounts incurred under change orders through December 31, 2023. As of December 31, 2023, we had approximately $2.9 billion remaining obligations under this contract.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Natural Gas Supply, Transportation and Storage Service Agreements

SPL and CCL have physical natural gas supply contracts to secure natural gas feedstock for the SPL Project and the CCL Project, respectively. As of December 31, 2023, the remaining fixed terms of these contracts ranged up to 15 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs.

Additionally, SPL and CCL have natural gas transportation and storage service agreements for the SPL Project and the CCL Project, respectively. The initial fixed terms of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs. The initial fixed term of the natural gas storage service agreements ranges up to 10 years.

As of December 31, 2023, the obligations of SPL and CCL under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are currently expected to be met were as follows (in billions):

Years Ending December 31,	Payments Due to Third Parties (1) (2)		Payments Due to Related Parties (1) (3)
2024	$	6.2	$	0.1
2025	6.3		0.1
2026	5.9		0.1
2027	5.3		0.1
2028	4.3		0.1
Thereafter	29.5		0.8
Total	$	57.5	$	1.3

(1)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. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

(2)Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

(3)Includes $1.0 billion under natural gas transportation and storage service agreements with unsatisfied contractual conditions.

Other Agreements

We have certain fixed commitments under SPL’s partial TUA assignment agreement with TotalEnergies and other agreements of $1.4 billion. See Note 13—Revenues for further discussion of the partial TUA assignment.

We have approximately $3.8 billion of legally binding minimum payments primarily for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years. See Note 12—Leases for further discussion of our leases, including leases for vessel charters that have not yet commenced as of December 31, 2023.

Environmental and Regulatory Matters

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

Legal Proceedings

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

NOTE 21—CUSTOMER CONCENTRATION

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers			Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Year Ended December 31,			December 31,
	2023	2022	2021	2023	2022
Customer A	*	*	12%	*	*
Customer B	*	*	12%	*	*
Customer C	*	*	10%	*	*
Customer D	*	*	*	13%	*

* Less than 10%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business.

	Revenues from External Customers
	Year Ended December 31,
	2023		2022		2021
Singapore	$	3,407	$	3,273	$	1,740
United Kingdom	2,908		4,642		1,246
United States	2,868		5,213		1,340
Ireland	1,596		2,726		1,838
South Korea	1,503		2,225		1,680
Spain	1,357		2,226		1,577
India	1,166		2,109		1,375
Switzerland	534		1,725		582
Germany	131		1,747		507
Other countries	4,924		7,542		3,979
Total	$	20,394	$	33,428	$	15,864

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—CONTINUED

NOTE 22—SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2023		2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	1,032	$	891	$	1,365
Cash paid for income taxes, net	117		30		4
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net and other non-current assets	204		181		117
Share-based compensation capitalized to property, plant and equipment	5		4		5
Conveyance of property, plant and equipment in exchange for other non-current assets	—		17		—
Contribution of other non-current assets in exchange for equity method investment	30		—		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		4		1
Unpaid repurchases of treasury stock inclusive of excise taxes	23		—		—

See Note 12—Leases for supplemental cash flow information related to our leases.

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ITEM 9.    CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

None.

ITEM 9A.    CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by us in reports we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and that such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure.

Based on their evaluation as of the end of the fiscal year ended December 31, 2023, our principal executive officer and principal financial officer have concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act are (1) accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and (2) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.

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.

Management’s Report on Internal Control Over Financial Reporting

Our Management’s Report on Internal Control Over Financial Reporting is included in our Consolidated Financial Statements and is incorporated herein by reference.

ITEM 9B.    OTHER INFORMATION

Rule 10b5-1 under the Exchange Act provides an affirmative defense that enables prearranged transactions in securities in a manner that avoids concerns about initiating transactions at a future date while possibly in possession of material nonpublic information. Our Insider Trading Policy permits our directors and executive officers to enter into trading plans designed to comply with Rule 10b5-1. During the three-month period ending December 31, 2023, none of our executive officers or directors adopted or terminated a Rule 10b5-1 trading plan or adopted or terminated a non-Rule 10b5-1 trading arrangement (as defined in Item 408(c) of Regulation S-K).

ITEM 9C.    DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

Not applicable.

97

PART III

Pursuant to paragraph 3 of General Instruction G to Form 10-K, the information required by Items 10 through 13 of Part III of this Report is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2023.

ITEM 14.     PRINCIPAL ACCOUNTANT FEES AND SERVICES

Our independent registered public accounting firm is KPMG LLP, Houston, Texas, Auditor Firm ID 185.

The remaining information required by this Item is incorporated by reference from Cheniere’s definitive proxy statement, which is to be filed pursuant to Regulation 14A within 120 days after the end of Cheniere’s fiscal year ended December 31, 2023.

98

PART IV

ITEM 15.    EXHIBITS AND FINANCIAL STATEMENT SCHEDULES

(a)    Financial Statements, Schedules and Exhibits

(1)    Financial Statements—Cheniere Energy, Inc. and Subsidiaries:

Management’s Report to the Stockholders of Cheniere Energy, Inc.	52
Reports of Independent Registered Public Accounting Firm	53
Consolidated Statements of Operations	56
Consolidated Balance Sheets	57
Consolidated Statements of Stockholders’ Equity (Deficit)	58
Consolidated Statements of Cash Flows	59
Notes to Consolidated Financial Statements	60

(2)     Financial Statement Schedules:

All financial statement schedules have been omitted because they are not required, are not applicable, or the required information has been included in the consolidated financial statements and accompanying notes included in this Form 10-K.

(3)    Exhibits:

Certain of the agreements filed as exhibits to this Form 10-K contain representations, warranties, covenants and conditions by the parties to the agreements that have been made solely for the benefit of the parties to the agreement. These representations, warranties, covenants and conditions:

•should not in all instances be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate;

•may have been qualified by disclosures that were made to the other parties in connection with the negotiation of the agreements, which disclosures are not necessarily reflected in the agreements;

•may apply standards of materiality that differ from those of a reasonable investor; and

•were made only as of specified dates contained in the agreements and are subject to subsequent developments and changed circumstances.

Accordingly, these representations and warranties may not describe the actual state of affairs as of the date they were made or at any other time. These agreements are included to provide you with information regarding their terms and are not intended to provide any other factual or disclosure information about the Company or the other parties to the agreements. Investors should not rely on them as statements of fact.

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
2.1	Amended and Restated Purchase and Sale Agreement, dated as of August 9, 2012, by and among CQP, Cheniere Pipeline Company, Grand Cheniere Pipeline, LLC and the Company	CQP	8-K	10.2	8/9/2012
3.1	Restated Certificate of Incorporation of the Company	Cheniere	10-Q	3.1	8/10/2004
3.2	Certificate of Amendment of Restated Certificate of Incorporation of the Company	Cheniere	8-K	3.1	2/8/2005

99

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
3.3	Certificate of Amendment of Restated Certificate of Incorporation of the Company	Cheniere (SEC File No. 333-160017)	S-8	4.3	6/16/2009
3.4	Certificate of Amendment of Restated Certificate of Incorporation of the Company	Cheniere	8-K	3.1	6/7/2012
3.5	Certificate of Amendment of Restated Certificate of Incorporation of the Company	Cheniere	8-K	3.1	2/5/2013
3.6	Bylaws of the Company, as amended and restated December 9, 2015	Cheniere	8-K	3.1	12/15/2015
3.7	Amendment No. 1 to the Amended and Restated Bylaws of the Company, dated September 15, 2016	Cheniere	8-K	3.1	9/19/2016
4.1	Specimen Common Stock Certificate of the Company	Cheniere (SEC File No. 333-10905)	S-1	4.1	8/27/1996
4.2	Indenture, dated as of February 1, 2013, by and among SPL, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as trustee	CQP	8-K	4.1	2/4/2013
4.3	First Supplemental Indenture, dated as of April 16, 2013, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.1.1	4/16/2013
4.4	Second Supplemental Indenture, dated as of April 16, 2013, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.1.2	4/16/2013
4.5	Third Supplemental Indenture, dated as of November 25, 2013, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.1	11/25/2013
4.6	Fourth Supplemental Indenture, dated as of May 20, 2014, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.1	5/22/2014
4.7	Form of 5.750% Senior Secured Note due 2024 (Included as Exhibit A-1 to Exhibit 4.6 above)	CQP	8-K	4.1	5/22/2014
4.8	Fifth Supplemental Indenture, dated as of May 20, 2014, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.2	5/22/2014
4.9	Sixth Supplemental Indenture, dated as of March 3, 2015, between SPL and The Bank of New York Mellon, as Trustee	CQP	8-K	4.1	3/3/2015
4.10	Form of 5.625% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.9 above)	CQP	8-K	4.1	3/3/2015
4.11	Seventh Supplemental Indenture, dated as of June 14, 2016, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	6/14/2016
4.12	Form of 5.875% Senior Secured Note due 2026 (Included as Exhibit A-1 to Exhibit 4.11 above)	CQP	8-K	4.1	6/14/2016
4.13	Eighth Supplemental Indenture, dated as of September 19, 2016, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	9/23/2016
4.14	Ninth Supplemental Indenture, dated as of September 23, 2016, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.2	9/23/2016
4.15	Form of 5.00% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.14 above)	CQP	8-K	4.2	9/23/2016
4.16	Tenth Supplemental Indenture, dated as of March 6, 2017, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	3/6/2017
4.17	Form of 4.200% Senior Secured Note due 2028 (Included as Exhibit A-1 to Exhibit 4.16 above)	CQP	8-K	4.1	3/6/2017
4.18	Eleventh Supplemental Indenture, dated as of May 8, 2020, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	SPL	8-K	4.1	5/8/2020

100

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
4.19	Form of 4.500% Senior Secured Note due 2030 (Included as Exhibit A-1 to Exhibit 4.18 above)	SPL	8-K	4.1	5/8/2020
4.20	Twelfth Supplemental Indenture, dated as of November 29, 2022, between SPL and The Bank of New York Mellon, as Trustee under the Indenture	SPL	8-K	4.1	11/29/2022
4.21	Form of 5.900% Senior Secured Amortizing Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.20 above)	SPL	8-K	4.1	11/29/2022
4.22	Indenture, dated as of February 24, 2017, between SPL, the guarantors that may become party thereto from time to time and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	2/27/2017
4.23	Form of 5.00% Senior Secured Note due 2037 (Included as Exhibit A-1 to Exhibit 4.22 above)	CQP	8-K	4.1	2/27/2017
4.24	Indenture, dated as of December 15, 2021, between SPL and The Bank of New York Mellon, as Trustee	Cheniere	10-K	4.24	2/24/2022
4.25	Form of 2.95% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.24 above)	Cheniere	10-K	4.24	2/24/2022
4.26	Indenture, dated as of December 15, 2021, between SPL and The Bank of New York Mellon, as Trustee	Cheniere	10-K	4.26	2/24/2022
4.27	Form of 3.17% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.26 above)	Cheniere	10-K	4.26	2/24/2022
4.28	First Supplemental Indenture, dated as of December 15, 2021, between SPL and The Bank of New York Mellon, as Trustee	Cheniere	10-K	4.28	2/24/2022
4.29	Form of 3.19% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.28 above)	Cheniere	10-K	4.28	2/24/2022
4.30	Second Supplemental Indenture, dated as of December 15, 2021, between SPL and The Bank of New York Mellon, as Trustee	Cheniere	10-K	4.30	2/24/2022
4.31	Form of 3.08% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.30 above)	Cheniere	10-K	4.30	2/24/2022
4.32	Third Supplemental Indenture, dated as of December 15, 2021, between SPL and The Bank of New York Mellon, as Trustee	Cheniere	10-K	4.32	2/24/2022
4.33	Form of 3.10% Senior Secured Notes due 2037 (Included as Exhibit A-1 to Exhibit 4.32 above)	Cheniere	10-K	4.32	2/24/2022
4.34	Indenture, dated as of September 22, 2020, between the Company, as issuer, and the Bank of New York Mellon, as trustee	Cheniere	8-K	4.1	9/22/2020
4.35	First Supplemental Indenture, dated as of September 22, 2020, between the Company, as issuer, and the Bank of New York Mellon, as trustee	Cheniere	8-K	4.2	9/22/2020
4.36	Form of 4.625% Senior Secured Notes due 2028 (Included as Exhibit A-1 to Exhibit 4.35 above)	Cheniere	8-K	4.2	9/22/2020
4.37	Indenture, dated as of May 18, 2016, among CCH, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	Cheniere	8-K	4.1	5/18/2016
4.38	First Supplemental Indenture, dated as of December 9, 2016, among CCH, as Issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	Cheniere	8-K	4.1	12/9/2016
4.39	Form of 5.875% Senior Secured Note due 2025 (Included as Exhibit A-1 to Exhibit 4.39 above)	Cheniere	8-K	4.1	12/9/2016
4.40	Second Supplemental Indenture, dated as of May 19, 2017, among CCH, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	5/19/2017
4.41	Form of 5.125% Senior Secured Note due 2027 (Included as Exhibit A-1 to Exhibit 4.41 above)	CCH	8-K	4.1	5/19/2017

101

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
4.42	Third Supplemental Indenture, dated as of September 6, 2019, among CCH, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as Guarantors, and The Bank of New York Mellon, as Trustee	CCH	8-K	4.1	9/12/2019
4.43	Fourth Supplemental Indenture, dated as of November 13, 2019, among CCH, as issuer, CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	11/13/2019
4.44	Form of 3.700% Note due 2029 (Included as Exhibit A-1 to Exhibit 4.44 above)	CCH	8-K	4.1	11/13/2019
4.45	Fifth Supplemental Indenture, dated as of August 24, 2021, among CCH, as issuer, CCL, CCP, and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	8/24/2021
4.46	Form of 2.742% Senior Secured Note due 2039 (Included as Exhibit A-1 to Exhibit 4.46 above)	CCH	8-K	4.1	8/24/2021
4.47	Indenture, dated as of August 20, 2020, among CCH, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	8/21/2020
4.48	Form of 3.52% Senior Secured Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.48 above)	CCH	8-K	4.1	8/21/2020
4.49	Indenture, dated as of September 27, 2019, among CCH, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	9/30/2019
4.50	Form of 4.80% Senior Note due December 31, 2039 (Included as Exhibit A-1 to Exhibit 4.50 above)	CCH	8-K	4.1	9/30/2019
4.51	Indenture, dated as of October 17, 2019, among CCH, as issuer, and CCL, CCP and Corpus Christi Pipeline GP, LLC, as guarantors, and The Bank of New York Mellon, as trustee	CCH	8-K	4.1	10/18/2019
4.52	Form of 3.925% Senior Note due December 31, 2039 (Included as Exhibit A to Exhibit 4.52 above)	CCH	8-K	4.1	10/18/2019
4.53	Indenture, dated as of September 18, 2017, between CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	9/18/2017
4.54	First Supplemental Indenture, dated as of September 18, 2017, between CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.2	9/18/2017
4.55	Second Supplemental Indenture, dated as of September 11, 2018, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	9/12/2018
4.56	Third Supplemental Indenture, dated as of September 12, 2019, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	9/12/2019
4.57	Form of 4.500% Senior Notes due 2029 (Included as Exhibit A-1 to Exhibit 4.57 above)	CQP	8-K	4.1	9/12/2019
4.58	Fourth Supplemental Indenture, dated as of November 5, 2020, between CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	Cheniere	10-Q	4.4	11/6/2020
4.59	Fifth Supplemental Indenture, dated as of March 11, 2021, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	3/11/2021
4.60	Form of 4.000% Senior Notes due 2031 (Included as Exhibit A-1 to Exhibit 4.60 above)	CQP	8-K	4.1	3/11/2021
4.61	Sixth Supplemental Indenture, dated as of September 27, 2021, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	9/27/2021

102

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
4.62	Form of 3.25% Senior Notes due 2032 (Included as Exhibit A-1 to Exhibit 4.62 above)	CQP	8-K	4.1	9/27/2021
4.63	Seventh Supplemental Indenture, dated as of September 27, 2021, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	10/1/2021
4.64	Eighth Supplemental Indenture, dated as of June 21, 2023, among CQP, the guarantors party thereto and The Bank of New York Mellon, as Trustee under the Indenture	CQP	8-K	4.1	6/21/2023
4.65	Form of 5.950% Senior Notes due 2033 (Included as Exhibit A to Exhibit 4.65 above)	CQP	8-K	4.1	6/21/2023
4.66*	Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934
10.1†	Cheniere Energy, Inc. 2020 Incentive Plan	Cheniere (SEC No. 333-238261)	S-8	4.9	5/14/2020
10.2†	Form of Restricted Stock Grant under the Cheniere Energy, Inc. 2020 Incentive Plan (Director)	Cheniere	10-Q	10.1	8/5/2021
10.3†*	Form of Restricted Stock Unit Award Agreement under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2022)
10.4†	Form of Restricted Stock Unit Award Agreement under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2023)	Cheniere	10-K	10.43	2/23/2023
10.5†*	Form of Restricted Stock Unit Award Agreement under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2024)
10.6†	Form of Performance Stock Unit Award Agreement Under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2022)	Cheniere	10-K	10.44	2/24/2022
10.7†	Form of Performance Stock Unit Award Agreement Under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2023)	Cheniere	10-K	10.46	2/23/2023
10.8†*	Form of Performance Stock Unit Award Agreement Under the Cheniere Energy, Inc. 2020 Incentive Plan (NEO) (2024)
10.9†*	Amended and Restated Cheniere Energy, Inc. Key Executive Severance Pay Plan (Effective as of November 17, 2023) and Summary Plan Description
10.10†	Director Deferred Compensation Plan (Effective February 10, 2022)	Cheniere	10-K	10.46	2/24/2022
10.11†	Form of Deferred Stock Unit Award Agreement Under the Director Deferred Compensation Plan	Cheniere	10-K	10.47	2/24/2022
10.12†	Employment Agreement between the Company and Jack A. Fusco, dated May 12, 2016	Cheniere	8-K	10.1	5/12/2016
10.13†	Employment Agreement Amendment between the Company and Jack Fusco, dated August 15, 2019	Cheniere	8-K	10.1	8/15/2019
10.14†	Second Employment Agreement Amendment between the Company and Jack Fusco, dated August 11, 2021	Cheniere	8-K	10.1	8/13/2021
10.15†*	Cheniere Energy, Inc. Amended and Restated Retirement Policy, dated effective January 1, 2021	Cheniere	10-K	10.49	2/25/2020
10.16†	Form of Indemnification Agreement for officers of the Company	Cheniere	8-K	10.2	5/20/2020
10.17†	Form of Indemnification Agreement for directors of the Company	Cheniere	8-K	10.1	5/20/2020
10.18†	Letter Agreement, dated February 15, 2023, between the Company and Aaron Stephenson	Cheniere	8-K	10.1	2/15/2023
10.19	Senior Revolving Credit and Guaranty Agreement, among SPL, as borrower, certain subsidiaries of the Company, The Bank of Nova Scotia, as Senior Facility Agent, Société Générale, as the Common Security Trustee, the issuing banks and lenders from time to time party thereto and other participants	SPL (SEC File No. 333-273238)	S-4	10.46	7/13/2023

103

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.20	Fourth Amended and Restated Common Terms Agreement, among SPL, as borrower, the Secured Debt Holder Group Representatives party thereto, the Secured Hedge Representatives party thereto, the Secured Gas Hedge Representatives party thereto and Société Générale, as the Common Security Trustee and the Intercreditor Agent	SPL (SEC File No. 333-273238)	S-4	10.44	7/13/2023
10.21	Third Amended and Restated Accounts Agreement, among SPL, certain subsidiaries of SPL, Société Générale, as the Common Security Trustee, and Citibank, N.A. as the Accounts Bank	SPL	8-K	10.3	3/23/2020
10.22	Second Amended and Restated Term Loan Facility Agreement, dated June 15, 2022, among CCH, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time and Société Générale as the Term Loan Facility Agent	Cheniere	8-K	10.1	6/22/2022
10.23	Second Amended and Restated Common Terms Agreement, dated June 15, 2022, among CCH, CCP, Corpus Christi Pipeline GP, LLC, CCL, Société Générale, as Term Loan Facility Agent, The Bank of Nova Scotia as Working Capital Facility Agent, and Société Générale as Intercreditor Agent, and any other facility lenders party thereto from time to time	Cheniere	8-K	10.3	6/22/2022
10.24	Second Amended and Restated Common Security and Account Agreement, dated June 15, 2022, among CCH, CCP, Corpus Christi Pipeline GP, LLC, CCL, the Senior Creditor Group Representatives, Société Générale as the Intercreditor Agent, Société Générale as Security Trustee and Mizuho Bank, Ltd as the Account Bank	Cheniere	8-K	10.4	6/22/2022
10.25	Amended and Restated Pledge Agreement, dated May 22, 2018, among CCH HoldCo I and Société Générale as Security Trustee	Cheniere	8-K	10.4	5/24/2018
10.26	Amended and Restated Equity Contribution Agreement, dated May 22, 2018, among CCH and the Company	Cheniere	8-K	10.5	5/24/2018
10.27	Second Amended and Restated Working Capital Facility Agreement, dated June 15, 2022, among CCH, CCP, Corpus Christi Pipeline GP, LLC, CCL, the lenders party thereto from time to time, the issuing banks party thereto from time to time, the swing line lenders party thereto from time to time, The Bank of Nova Scotia as Working Capital Facility Agent and Société Générale as Security Trustee	Cheniere	8-K	10.2	6/22/2022
10.28	Second Amended and Restated Revolving Credit Agreement, dated as of October 28, 2021, among the Company, the Lenders and Issuing Banks party thereto, Sumitomo Mitsui Banking Corporation, as ESG Coordinator, and Société Générale, as Administrative Agent	Cheniere	8-K	10.1	11/1/2021
10.29	First Amendment to Second Amended and Restated Revolving Credit Agreement, dated as of June 15, 2023, among the Company, the Lenders and Issuing Banks party thereto, Sumitomo Mitsui Banking Corporation, as ESG Coordinator, and Société Générale, as Administrative Agent	Cheniere	10-Q	10.2	8/3/2023
10.30	Credit Agreement, dated June 18, 2020, among the Company, the Lenders party thereto, Société Générale, as Administrative Agent, and the other agents and arrangers party thereto from time to time	Cheniere	8-K	10.1	6/19/2020
10.31	Credit and Guaranty Agreement, dated as of June 23, 2023, among CQP, as borrower, certain subsidiaries of CQP, as Subsidiary Guarantors, the lenders from time to time party thereto, Société Générale, Natixis, Sumitomo Mitsui Banking Corporation, The Bank of Nova Scotia, and Wells Fargo Bank, as Issuing Banks, MUFG Bank, LTD as Administrative Agent and Coordinating Lead Arranger, and certain arrangers and other participants	Cheniere	10-Q	10.4	8/3/2023

104

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.32	Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil, Gas and Chemicals, Inc. (Portions of this exhibit have been omitted and filed separately with the Securities and Exchange Commission pursuant to a request for confidential treatment.)	Cheniere	8-K	10.1	11/9/2018
10.33	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00001 Modifications to Insurance Language Change Order, dated June 3, 2019	Cheniere	10-Q	10.6	8/8/2019
10.34	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00002 Fuel Provisional Sum Closure, dated July 8, 2019, (ii) the Change Order CO-00003 Currency Provisional Sum Closure, dated July 8, 2019, (iii) the Change Order CO-00004 Foreign Trade Zone, dated July 2, 2019, (iv) the Change Order CO-00005 NGPL Gate Access Security Coordination Provisional Sum, dated July 17, 2019, (v) the Change Order CO-00006 Alternate to Adams Valves, dated August 14, 2019, (vi) the Change Order CO-00007 E-1503 to HRU Permanent Drain Piping, dated August 14, 2019, (vii) the Change Order CO-00008 Differing Subsurface Soil Conditions - Train 6 ISBL, dated August 27, 2019, (viii) the Change Order CO-00009 LNG Berth 3, dated September 25, 2019 and (ix) the Change Order CO-00010 Cold Box Redesign and Addition of Inspection Boxes on Methane Cold Box, dated September 16, 2019	Cheniere	10-Q	10.10	11/1/2019
10.35	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00011 Insurance Provisional Sum Interim Adjustment, dated October 1, 2019 and (ii) the Change Order CO-00012 Replacement of Timber Piles with Pre-Stressed Concrete Piles, dated October 30, 2019	Cheniere	10-K	10.88	2/25/2020
10.36	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00013 Cost to Comply with SPL FTZ (FTZ entries, bonded transports and receipts for AG Pipe Spools Only), dated February 10, 2020, (ii) the Change Order CO-00014 Permanent Access Road to Third Berth, dated February 10, 2020, (iii) the Change Order CO-00015 Modifications to Schedule Bonus Language, dated February 10, 2020, (iv) the Change Order CO-00016 LNG Berth 3 LNTP No 3, dated January 31, 2020 and (v) the Change Order CO-00017 Construction Doc Fender Guards and LP Fuel Gas Overpressure Interlock, dated March 18, 2020	Cheniere	10-Q	10.6	4/30/2020

105

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.37	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00018 Electrical Studies for GTG Grid Modification, dated April 2, 2020, (ii) the Change Order CO-00019 Third Berth - Change in 5kV Electrical Tie-In, dated April 30, 2020, (iii) the Change Order CO-00020 LNG Berth 3 LNTP No. 4, dated May 4, 2020, (iv) the Change Order CO-00021 Train 6 P1601 A/B/ Flange Changes, dated May 27, 2020 and (v) the Change Order CO-00022 Train 6 H2S Skid Modifications to Level Transmitters & GTG Pressure Range Change on PT-573 A/B, dated June 4, 2020	Cheniere	10-Q	10.9	8/6/2020
10.38	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00023 Third Berth Vapor Fence Provisional Sum Scope Removal and Closeout, dated June 22, 2020, (ii) the Change Order CO-00024 Train 6 Thermowell Upgrades, dated June 22, 2020, (iii) the Change Order CO-00025 Third Berth Bubble Curtain, dated June 22, 2020, (iv) the Change Order CO-00026 Third Berth Fuel Provisional Sum Closure Change Order, dated July 14, 2020, (v) the Change Order CO-00027 Third Berth Currency Provisional Sum Closure Change Order, dated July 20, 2020, (vi) the Change Order CO-00028 Train 6 Hot Oil WHRU PSV Bypass, dated August 11, 2020 and (vii) the Change Order CO-00029 Change in Law IMO 2020 Regulatory Change – Low Sulphur Emissions on Marine Vessels, dated August 25, 2020	Cheniere	10-Q	10.2	11/6/2020
10.39	Change order to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between the SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00030 Third Berth Soil Preparation Provisional Sum Interim Adjustment Change Order, dated September 16, 2020, (ii) the Change Order CO-00031 Provisional Sum Consolidation (PAB, Taxes & Insurance), dated October 2, 2020, (iii) the Change Order CO-00032 COVID-19 Impacts, dated October 2, 2020, (iv) the Change Order CO-00033 Third Berth - Jetty Building (00A-4041) - Clean Agent System, dated November 2, 2020 and (v) the Change Order CO-00034 Vanessa Spare Valves, dated November 18, 2020	Cheniere	10-K	10.88	2/24/2021
10.40	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00035 Impacts from Hurricanes Laura and Delta, dated December 22, 2020, (ii) the Change Order CO-00036 Third Berth - Add N2 Connection on Liquid & Hybrid SVT Loading Arm Apex, dated December 22, 2020, (iii) the Change Order CO-00037 Third Berth Design Vessels Update, dated December 22, 2020, (iv) the Change Order CO-00038 Train 6 PV-16002 & FV-15104 Valve Trim Upgrades, dated January 21, 2021, (v) the Change Order CO-00039 Third Berth Design Update to Supply Bunkering Fuel, dated February 11, 2021, (vi) the Change Order CO-00040 LNG Benchmark 7 Elevation Change, dated February 11, 2021, (vii) the Change Order CO-00041 Costs to Comply with SPL FTZ (Excluding Pipe Spools), dated February 12, 2021 and (viii) the Change Order CO-00042 COVID-19 Impacts 1Q2021, dated March 12, 2021	Cheniere	10-Q	10.2	5/4/2021

106

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.41	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00043 Third Berth SVT Loading Arm Spares, dated April 9, 2021, (ii) the Change Order CO-00044 Third Berth U/G Directional Drilling & Cathodic Protection Provisional Sum Closures, dated April 9, 2021, (iii) the Change Order CO-00045 Winter Storm Impacts, dated April 9, 2021, (iv) the Change Order CO-00046 NGPL Security Provisional Sum Interim Adjustment, dated June 15, 2021, (v) the Change Order CO-00047 80 Acres Bridge, dated June 15, 2021 and (vi) the Change Order CO-00048 AGRU Additions for Lean Solvent Overpressure, dated June 15, 2021	Cheniere	10-Q	10.4	8/5/2021
10.42	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00049 COVID-19 Impacts 2Q2021, dated July 6, 2021, (ii) CO-00050 Third Berth Bunkering Ship Modifications — Pre-Investment for Foundations, dated July 6, 2021, (iii) CO-00051 Thermal Oxidizer Controls Change, dated September 8, 2021, (iv) CO-00052 Third Berth Spare Beacon and Additional Cable Tray, dated September 8, 2021 and (v) CO-00053 Train 6 Gearbox Assembly Replacement for Unit 1411, dated September 24, 2021	Cheniere	10-Q	10.1	11/4/2021
10.43	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00054 80 Acres Bridge Credit, dated November 30, 2021, (ii) CO-00055 Change in Law LPDES Permit - Water Treatment Filter Washing, dated December15, 2021, (iii) CO-00056 Impacts from Hurricane Ida, dated December 15, 2021 and (iv) CO-00057 Impacts from Hurricane Nicholas, dated December 15, 2021	Cheniere	10-K	10.99	2/24/2022
10.44	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00058 COVID-19 Impacts 3Q2021, dated January 6, 2022, (ii) CO-00059 Spill Containment SIL 2 Interlock, dated January 11, 2022, (iii) the Change Order CO-00060 Third Berth Soil Preparation Provisional Sum Closure, dated March 15, 2022, (iv) the Change Order CO-00061 COVID-19 Impacts 4Q2021, dated March 15, 2022 and (v) the Change Order CO-00062 FERC Condition 61, dated March 15, 2022	Cheniere	10-Q	10.2	5/4/2022
10.45	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00063 FERC Condition 78, dated May 6, 2022, (ii) the Change Order CO-00064 FERC Impact to Pipe Installation, dated June 14, 2022, (iii) the Change Order CO-00065 Spill Containment Sil 2 Interlock, dated June 15, 2022 and (iv) the Change Order CO-00066 Marine Dredging and Management Oversight Provisional Sums Closure, dated June 16, 2022	Cheniere	10-Q	10.6	8/4/2022

107

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.46	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00067 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure, dated August 18, 2022, (ii) the Change Order CO-00068 Performance and Attendance Bonus (“PAB”) Provisional Sum Closure (Reconciliation to CO-00067), dated August 18, 2022, and (iii) the Change Order CO-00069 COVID-19 Impacts 1Q2022 and 2Q2022, dated August 29, 2022	Cheniere	10-Q	10.1	11/3/2022
10.47	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 7, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00070 80-Acres Bridge, dated October 28, 2022, (ii) the Change Order CO-00071 Mooring System Low-Tension Common Alarm, dated October 31, 2022, (iii) the Change Order CO-00072 FERC Hydrocarbon Permit Conditions, dated October 31, 2022, (iv) the Change Order CO-00073 BN#2 Beacon Pile Relocation, dated October 31, 2022 and (v) the Change Order CO-00074 FERC Condition 56: ISA 84 Gas Detection, dated October 31, 2022	Cheniere	10-K	10.92	2/23/2023
10.48	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 8, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: the Change Order CO-00075 Section 232 Duties (Final Settlement FTZ), dated December 16, 2022	Cheniere	10-Q	10.1	5/2/2023
10.49	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Sabine Pass LNG Stage 4 Liquefaction Facility, dated November 8, 2018, by and between SPL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00076 Supplemental FERC Condition 80 Requirements, dated May 5, 2023, (ii) the Change Order CO-00077 Louisiana Sales and Use Tax Provisional Sum Closure, dated June 16, 2023, (iii) the Change Order CO-00078 Natural Gas Pipeline (NGPL) Security Coordination Provisional Sum Closure, dated June 22, 2023, (iv) the Change Order CO-00079 Insurance Provisional Sum Closure, dated July 27, 2023 and (v) the Change Order Co-00080 Borrowed Items, dated September 6, 2023	Cheniere	10-Q	10.1	11/2/2023
10.50	Fixed Price Separated Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Energy Inc. (Portions of this exhibit have been omitted and filed separately with the SEC pursuant to a request for confidential treatment)	Cheniere	10-Q	10.1	5/4/2022
10.51	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL Stage III and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00001 Maintaining Elevated Ground Flare Option, dated March 28, 2022, (ii) the Change Order CO-00002 Package 7 Pre-Investment of Trains 8 and 9 (Without Site Work), dated April 29, 2022 and (iii) the Change Order CO-00003 Modifications to Insurance Language, dated June 13, 2022 (Portions of this exhibit have been omitted)	Cheniere	10-Q	10.7	8/4/2022

108

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.52	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00004 Currency Conversion, dated June 27, 2022, (ii) the Change Order CO-00005 Fuel Adjustment, dated July 15, 2022, (iii) the Change Order CO-00006 Removal of Laydown Yard Scope Option, dated August 2, 2022, (iv) the Change Order CO-00007 Removal of Air Bridges Scope Option, dated August 22, 2022, (v) the Change Order CO-00008 Acid Gas Flare K/O Drum, dated August 16, 2022, and (vi) the Change Order CO-00009 Package 7A (Without Site Work), dated August 16, 2022 (Portions of this exhibit have been omitted)	Cheniere	10-Q	10.2	11/3/2022
10.53	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-000010 Insurance Provisional Sum Interim Adjustment, dated September 13, 2022 and (ii) the Change Order CO-000011 Package 6 Descope and Transfer to Owner, dated September 14, 2022 (Portions of this exhibit have been omitted)	Cheniere	10-K	10.96	2/23/2023
10.54	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction Stage III, LLC and Bechtel Oil Gas and Chemicals, Inc.: (i) the Change Order CO-00012 Chart License Fee Provisional Sum Closure, dated September 16, 2022, (ii) the Change Order CO-00013 HRU Nozzles and Block Headers, dated September 21, 2022, (iii) the Change Order CO-00014 Addition of Nitrogen Receiver, dated December 13, 2022, (iv) the Change Order CO-00015 Package 6 Feed Gas Pipeline Interfaces, dated December 14, 2022, (v) the Change Order CO-00016 Old Sherwin Building Security, dated November 23, 2022, (vi) the Change Order CO-00017 Remote Monitoring Diagnostic for Mixed Refrigerant (MR) Compressors, dated December 14, 2022, (vii) the Change Order CO-00018 EFG Package #1, dated January 9, 2023, (viii) the Change Order CO-00019 Q3 2022 Commodity Price Rise and Fall (ATT MM), dated January 17, 2023, (ix) the Change Order CO-00020 ICSS Vendor Selection and EPC Warranty (Yokogawa), dated September 21, 2022 and (x) the Change Order CO-00021 Laydown Development Package, dated February 6, 2023 (Portions of this exhibit have been omitted.)	Cheniere	10-Q	10.2	5/2/2023

109

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.55	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between Corpus Christi Liquefaction, LLC and Bechtel Energy, Inc.: (i) the Change Order CO-00022 Refrigerant Storage Packages 1 and 2, dated February 13, 2023, (ii) the Change Order CO-00023 EFG Package #2, dated February 21, 2023, (iii) the Change Order CO-00024 Defrost Improvements (Cold Box), dated February 23, 2023, (iv) the Change Order CO-00025 Miscellaneous Design Improvements, dated February 23, 2023, (v) the Change Order CO-00026 EFG Package #3, dated February 23, 2023, (vi) the Change Order CO-00027 Addition of 86 Lockout Relay on Transformers, dated February 14, 2023, (vii) the Change Order CO-00028 Additional Duct Banks, dated September 15, 2022, (viii) the Change Order CO-00029 2022 FERC Support Hours Interim Adjustment, dated March 13, 2023, (ix) the Change Order CO-00030 Drainage Blanket (A Street), dated April 6, 2023, (x) the Change Order CO-00031 Refrigerant Storage Interface Package #3, dated April 7, 2023, (xi) the Change Order CO-00032 Q4 2022 Commodity Price Rise and Fall (ATT MM), dated April 24, 2023, (xii) the Change Order CO-00033 Lift Owner-Provided Dewar System (Nitrogen Receiver Facility), dated March 1, 2022, (xiii) the Change Order CO-00034 HAZOP Package #1 - Addition of Flame Arrestors for Oil Mist Eliminator Vent, dated April 25, 2023 and (xiv) the Change Order CO-00035 EFG Package #4 (Water Pipeline Pipe Bridge), dated May 19, 2023 (Portions of this exhibit have been omitted.)	Cheniere	10-Q	10.1	8/3/2023
10.56	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00036 Payment Milestone Updates (Schedule C-1), dated June 19, 2023, (ii) the Change Order CO-00037 Geotechnical Soils Investigation Period & Security Division of Responsibility Change, dated June 20, 2023, (iii) the Change Order CO-00038 Power Monitoring System (ETAP HMI), dated June 29, 2023 and (iv) the Change Order CO-00039 EFG Firewater Connection, dated June 30, 2023 (Portions of this exhibit have been omitted.)	Cheniere	10-Q	10.2	11/2/2023

110

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.57*	Change orders to the Lump Sum Turnkey Agreement for the Engineering, Procurement and Construction of the Corpus Christi Liquefaction Stage 3 Project, dated March 1, 2022, by and between CCL and Bechtel Energy, Inc.: (i) the Change Order CO-00040 Q1 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (ii) the Change Order CO-00041 Q2 2023 Commodity Price Rise and Fall (ATT MM), dated August 29, 2023, (iii) the Change Order CO-00042 HAZOP Package #2 – Additional IPL (Pressure Transmitter Across the Strainer), dated July 5, 2023, (iv) the Change Order CO-00043 Total Condensate Flowmeter on Three (3) Inch Condensate Line, dated August 31, 2023, (v) the Change Order CO-00044 FERC Package #1 ISA 84 (Accommodation for Two Hundred and Fifty (250) Fire and Gas Detectors), dated August 31, 2023, (vi) the Change Order CO-00045 Increase LNG Rundown Line Check Valve Bypass Size to Six (6) Inches, dated August 31, 2023, (vii) the Change Order CO-00046 Add Manual Bypass Valves Around 31XV-13071, dated September 13, 2023, (viii) the Change Order CO-00047 Relocate Existing 16” Process Water Line and Provide Tie-In, dated September 8, 2023, (ix) the Change Order CO-00048 Future HRU Bypass Tie-In and Thermowell Updates, dated September 12, 2023, (x) the Change Order CO-00049 Butterfly Valves for Flare Drums, dated September 5, 2023, (xi) the Change Order CO-00050 Condensate Shroud on Condensate Rundown Line (Blue Engineering Report), dated September 12, 2023, (xii) the Change Order CO-00051 EFG Package #5 (138KV Feeder Cable), dated September 8, 2023, (xiii) the Change Order CO-00052 Defect Correction Period for Cementitious Fireproofing, dated August 7, 2023, (xiv) the Change Order CO-00053 Chart Transition Joint Spares, dated October 5, 2023, (xv) the Change Order CO-00054 CCL Tank(s) “A” and “C” Tie-In Study & Long Lead Item Purchases, dated September 19, 2023, (xvi) the Change Order CO-00055 FERC Package #2 Firewater Layout, dated September 13, 2023, (xvii) the Change Order CO-00056 HAZOP Package #3 – Stainless Steel C And D Pass Piping / Two Temperature Transmitters per Train, dated February 14, 2023, (xviii) the Change Order CO-00057 HAZOP Package #4 (“Phase Two Items”), dated October 10, 2023, (xix) the Change Order CO-00058 E-HAZOP Package #1 (“LV MCC Ride Through”), dated September 8, 2023, (xx) the Change Order CO-00059 Level Transmitter on Stand Pipe Inside Liquefaction Cold Boxes, dated October 13, 2023, (xxi) the Change Order CO-00060 Small Spill Containment (Additional Curbs), dated July 5, 2023, (xxii) the Change Order CO-00061 Remote Input/Output (RIO) Junction Box Grounding, dated October 10, 2023, (xxiii) the Change Order CO-00062 Geomembrane Liner and Geocell for Laydown 6 Channel, dated August 31, 2023, (xxiv) the Change Order CO-00063 Phased Surfacing of Permanent Plant Roads, dated August 7, 2023, (xxv) the Change Order CO-00064 Provisional Sum Interim Adjustment - Schedule KK-1 12-Month COVID Countermeasures, dated July 24, 2023, (xxvi) the Change Order CO-00065 Modification to FTZ Zone Site (Exhibit A of Attachment LL), dated August 3, 2023, (xxvii) the Change Order CO-00066 Attachment B (Contract Deliverables), dated June 2, 2023, (xxviii) the Change Order CO-00067 Sheet Pile Joint Sealing 310Q02 Sump, dated October 5, 2023, (xxix) the Change Order CO-00068 E-HAZOP Package #2 (“Phase One Items”), dated October 19, 2023, (xxx) the Change Order CO-00069 Package 6 Feed Gas Pipeline and Pig Receiver DMM, dated August 3, 2023, (xxxi) the Change Order CO-00070 Dry Flare Knockout Drum Spill Pad Drain Specification Change, dated October 5, 2023, (xxxii) the Change Order CO-00071 Viewing Platform Piles, dated October 18, 2023, (xxxiii) the Change Order CO-00072 Site Plan Update Package #1 – Re-Route Contractor’S Utility Water & Nitrogen Pipelines and Provide Power & Fiber Cables To Nitrogen Tie-In Point, dated November 2, 2023, (Portions of this exhibit have been omitted.)

111

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
10.58	LNG Sale and Purchase Agreement (FOB), dated November 21, 2011, between SPL (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)	CQP	8-K	10.1	11/21/2011
10.59	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated April 3, 2013, between SPL (Seller) and Gas Natural Aprovisionamientos SDG S.A. (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)	CQP	10-Q	10.1	5/3/2013
10.60	Amendment of LNG Sale and Purchase Agreement (FOB), dated January 12, 2017, between SPL (Seller) and Gas Natural Fenosa LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.) (Buyer)	SPL (SEC File No. 333-215882)	S-4	10.3	2/3/2017
10.61	Letter agreement regarding change from LIBOR to SOFR, dated June 8, 2023, to LNG Sale and Purchase Agreement, dated November 21, 2011, between SPL and Naturgy LNG GOM, Limited (assignee of Gas Natural Aprovisionamientos SDG S.A.), as amended	Cheniere	10-Q	10.13	8/3/2023
10.62	Amended and Restated LNG Sale and Purchase Agreement (FOB), dated January 25, 2012, between SPL (Seller) and BG Gulf Coast LNG, LLC (Buyer)	CQP	8-K	10.1	1/26/2012
10.63	Letter agreement regarding change from LIBOR to SOFR, dated May 18, 2023, to LNG Sale and Purchase Agreement, dated January 25, 2012, between SPL and BG Gulf Coast LNG, LLC, as amended	Cheniere	10-Q	10.10	8/3/2023
10.64	LNG Sale and Purchase Agreement (FOB), dated June 2, 2014, between CCL (Seller) and Gas Natural Fenosa LNG SL (subsequently assigned to Gas Natural Fenosa LNG GOM, Limited) (Buyer)	Cheniere	8-K	10.1	6/2/2014
10.65	Amendment No. 1 of LNG Sale and Purchase Agreement (FOB), dated February 27, 2018, between CCL (Seller) and Gas Natural Fenosa LNG GOM, Limited (Buyer)	Cheniere	10-Q	10.6	5/4/2018
10.66	Letter agreement regarding change from LIBOR to SOFR, dated June 8, 2023, to LNG Sale and Purchase Agreement, dated June 2, 2014, between CCL and Naturgy LNG GOM, Limited (assignee of Gas Natural Fenosa LNG SL), as amended	Cheniere	10-Q	10.9	8/3/2023
10.67	Cooperative Endeavor Agreement & Payment in Lieu of Tax Agreement with eleven Cameron Parish taxing authorities, dated October 23, 2007, by and between Cheniere Marketing, Inc. and SPLNG	Cheniere	10-Q	10.7	11/6/2007
10.68	Investors’ and Registration Rights Agreement, dated as of July 31, 2012, by and among the Company, Cheniere Energy Partners GP, LLC, CQP, Cheniere Class B Units Holdings, LLC, Blackstone CQP Holdco LP and the other investors party thereto from time to time	CQP	8-K	10.1	8/6/2012
10.69	Fourth Amended and Restated Agreement of Limited Partnership of CQP, dated February 14, 2017	CQP	8-K	3.1	2/21/2017
10.70	Amended and Restated Limited Liability Company Agreement of Cheniere GP Holding Company, LLC, dated December 13, 2013	Cheniere Holdings	8-K	10.3	12/18/2013
21.1*	Subsidiaries of the Company
23.1*	Consent of KPMG LLP
31.1*	Certification by Chief Executive Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act
31.2*	Certification by Chief Financial Officer required by Rule 13a-14(a) and 15d-14(a) under the Exchange Act

112

Exhibit No.		Incorporated by Reference (1)
	Description	Entity	Form	Exhibit	Filing Date
32.1**	Certification by Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
32.2**	Certification by Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
97*	Cheniere Energy Inc. Clawback Policy
101.INS*	XBRL Instance Document
101.SCH*	XBRL Taxonomy Extension Schema Document
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB*	XBRL Taxonomy Extension Labels Linkbase Document
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document
104*	Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101)

(1)	Exhibits are incorporated by reference to reports of Cheniere (SEC File No. 001-16383), CQP (SEC File No. 001-33366), Cheniere Energy Partners LP Holdings, LLC (“Cheniere Holdings”) (SEC File No. 001-36234), SPL (SEC File No. 333-192373), CCH (SEC File No. 333-215435) and SPLNG (SEC File No. 333-138916), as applicable, unless otherwise indicated.
*	Filed herewith.
**	Furnished herewith.
†	Management contract or compensatory plan or arrangement.

113

ITEM 16.    FORM 10-K SUMMARY

None.

114

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. 

CHENIERE ENERGY, INC.
(Registrant)
By:	/s/ Jack A. Fusco
	Jack A. Fusco
	President and Chief Executive Officer (Principal Executive Officer)
Date:	February 21, 2024

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Jack A. Fusco	President and Chief Executive Officer and Director (Principal Executive Officer)	February 21, 2024
Jack A. Fusco
/s/ Zach Davis	Executive Vice President and Chief Financial Officer (Principal Financial Officer)	February 21, 2024
Zach Davis
/s/ David Slack	Vice President and Chief Accounting Officer (Principal Accounting Officer)	February 21, 2024
David Slack
/s/ G. Andrea Botta	Chairman of the Board	February 21, 2024
G. Andrea Botta
/s/ Patricia K. Collawn	Director	February 21, 2024
Patricia K. Collawn
/s/ Brian E. Edwards	Director	February 21, 2024
Brian E. Edwards
/s/ Denise Gray	Director	February 21, 2024
Denise Gray
/s/ Lorraine Mitchelmore	Director	February 21, 2024
Lorraine Mitchelmore
/s/ Donald F. Robillard, Jr.	Director	February 21, 2024
Donald F. Robillard, Jr.
/s/ Matthew Runkle	Director	February 21, 2024
Matthew Runkle
/s/ Neal A. Shear	Director	February 21, 2024
Neal A. Shear

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EX-4.66

Exhibit 4.66

Description of the Registrant’s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934

Cheniere Energy Inc. (“Cheniere”) has one class of securities registered under Section 12 of the Securities Exchange Act of 1934, as amended: common stock, $0.003 par value (“Common Stock”).

The following contains a description of the Common Stock, as well as certain related additional information. This description is a summary only and does not purport to be complete. You should read the complete text of Cheniere’s certificate of incorporation (as may be amended from time to time, the “Certificate of Incorporation”) and bylaws of Cheniere (as may be amended from time to time, the “Bylaws”).

Authorized Capital Stock

Cheniere’s authorized capital stock consists of 480,000,000 shares of Common Stock and 5,000,000 shares of preferred stock, $0.0001 par value.

Listing

The Common Stock is listed on the New York Stock Exchange under the symbol “LNG.”

Dividends

Subject to the rights of holders of preferred stock, holders of Common Stock may receive dividends when declared by the Board of Directors of Cheniere (the “Board”). Dividends may be paid in cash, stock or another form.

Fully Paid

All outstanding shares of Common Stock are fully paid and non-assessable.

Voting Rights

Holders of Common Stock are entitled to one vote in the election of directors and other matters for each share of Common Stock owned. Holders of Common Stock are not entitled to preemptive or cumulative voting rights.

Other Rights

Holders of Common Stock will be notified by Cheniere of any stockholders meetings in accordance with applicable law. If Cheniere liquidates, dissolves or winds up its business, either voluntarily or not, holders of Common Stock will share equally in the assets remaining after Cheniere pays its creditors and preferred stockholders. There are no redemption or sinking fund provisions applicable to the Common Stock.

Transfer Agent and Registrar

The transfer agent and registrar for the Common Stock is Computershare Trust Company, N.A. located in Providence, Rhode Island.

Certain Provisions of the Cheniere Certificate of Incorporation, Cheniere Bylaws and Law

The Certificate of Incorporation and the Bylaws contain provisions that may render more difficult possible takeover proposals to acquire control of Cheniere and make removal of Cheniere’s management more difficult. Below is a description of certain of these provisions in the Certificate of Incorporation and Bylaws.

The Certificate of Incorporation authorizes a class of undesignated preferred stock consisting of 5,000,000 shares. Additional shares of preferred stock may be issued from time to time in one or more series, and the Board, without further approval of the holders of Common Stock, is authorized to fix the designations, powers, preferences and rights applicable to each series of preferred stock. The purpose of authorizing the Board to determine such designations, powers, preferences and rights is to allow such determinations to be made by the Board instead of the holders of Common Stock and to avoid the expense of, and eliminate delays associated with, a stockholder vote on specific issuances. The issuance of preferred stock, while providing flexibility in connection with possible acquisitions and other corporate purposes, could, among other things, adversely affect the voting power of the holders of Common Stock and, under some circumstances, make it more difficult for a third party to gain control of Cheniere.

The Certificate of Incorporation provides that any action required or permitted to be taken by the holders of Common Stock must be taken at an annual or special meeting of stockholders and not by written consent.

The Bylaws permit holders of record of at least 50.1% of the outstanding shares of Common Stock to call a special meeting of stockholders if such holders comply with the requirements set forth in the Bylaws.

The Bylaws contain specific procedures for stockholder nomination of directors. These provisions require advance notification that must be given in accordance with the provisions of the Bylaws. The procedure for stockholder nomination of directors may have the effect of precluding a nomination for the election of directors at a particular meeting if the required procedure is not followed.

The Bylaws provide that a stockholder, or group of up to 20 stockholders, that has owned for at least the prior three consecutive years shares of Common Stock representing an aggregate of at least 3% of Cheniere’s outstanding Common Stock, may nominate and include in Cheniere’s proxy materials director nominees, provided that the stockholder(s) and nominee(s) satisfy the requirements in the Bylaws.

The Certificate of Incorporation requires the vote of at least 66 2/3% of all of the shares of capital stock of Cheniere which are entitled to vote, voting together as a single class, to take stockholder action to alter, amend, rescind or repeal any of the Bylaws, or to alter, amend, rescind or repeal provisions of the Certificate of Incorporation or to adopt any provision inconsistent therewith relating to the inability of stockholders to act by written consent, the ability of the Board to adopt, alter, amend and repeal the Bylaws and the supermajority voting provision. The “supermajority” voting provisions may discourage or deter a person from attempting to obtain control of Cheniere by making it more difficult to amend some provisions of the Certificate of Incorporation or for holders of Common Stock to amend any provision of the Bylaws, whether to eliminate provisions that have an anti-takeover effect or those that protect the interests of minority stockholders.

Although Section 214 of the General Corporation Law of the State of Delaware (“DGCL”) provides that a corporation’s certificate of incorporation may provide for cumulative voting for directors, the Certificate of Incorporation does not provide for cumulative voting. As a result, in a non-contested election of directors, directors are elected by a vote of the majority of the votes cast with respect to that director’s election; in a contested election of directors, directors are elected by a vote of the plurality of the votes cast.

As a Delaware corporation, Cheniere is subject to Section 203, or the business combination statute, of the DGCL. Under the business combination statute of the DGCL, a corporation is generally restricted from engaging in a business combination (as defined in Section 203 of the DGCL) with an interested stockholder (defined generally as a person owning 15% or more of the corporation’s outstanding voting stock) for a three-year period following the time the stockholder became an interested stockholder. This restriction applies unless:

•prior to the time the stockholder became an interested stockholder, the board of directors of the corporation approved either the business combination or the transaction which resulted in the stockholder becoming an interested stockholder;

•the interested stockholder owned at least 85% of the voting stock of the corporation upon completion of the transaction which resulted in the stockholder becoming an interested stockholder (excluding stock held by the corporation’s directors who are also officers and by the corporation’s employee stock plans, if any, that do not provide employees with the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer); or

•at or subsequent to the time the stockholder became an interested stockholder, the business combination was approved by the board of directors of the corporation and authorized by the affirmative vote, at an annual or special meeting, and not by written consent, of at least 66 2/3% of the outstanding voting shares of the corporation, excluding shares held by that interested stockholder.

The provisions of the business combination statute of the DGCL do not apply to a corporation if, subject to certain requirements specified in Section 203(b) of the DGCL, the certificate of incorporation or bylaws of the corporation contain a provision expressly electing not to be governed by the provisions of the statute or the corporation does not have voting stock listed on a national securities exchange or held of record by more than 2,000 stockholders. Cheniere has not adopted any provision in the Certificate of Incorporation or Bylaws electing not to be governed by the business combination statute of the DGCL. As a result, the statute is applicable to business combinations involving Cheniere.

EX-10.3

Exhibit 10.3

CHENIERE ENERGY, INC.
2020 INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD AGREEMENT

1.    Award. Cheniere Energy, Inc., a Delaware corporation (the “Company”), has awarded the undersigned Participant (for purposes of this Agreement, the “Participant”) restricted stock units (this “Award”) effective as of the date set forth on the signature page hereto (the “Grant Date”) pursuant to the Company’s 2020 Incentive Plan (as amended or restated from time to time, the “Plan”). Unless otherwise defined in this Restricted Stock Unit Award Agreement (this “Agreement”), capitalized terms used herein shall have the meanings assigned to them in the Plan.

2.    Restricted Stock Units. The Company hereby awards the Participant the number of restricted stock units set forth in Schedule A (the “RSUs”). Each RSU constitutes an unfunded and unsecured promise by the Company to deliver (or cause to be delivered) one share of common stock, $0.003 par value per share, of the Company (a “Share”). The RSUs will be subject to vesting in accordance with Paragraph 3 below.

3.    Vesting. Subject to the Participant’s continued employment and Paragraphs 4 and 5, the RSUs shall vest on the date or dates set forth in Schedule A (each, a “Vesting Date”).

4.    Termination of Employment or Services.

(A)    Upon the termination of the Participant’s employment with the Company or an Affiliate (1) by the Company or an Affiliate due to the Disability of the Participant while performing Continuous Service or (2) due to the death of the Participant while performing Continuous Service, unvested RSUs shall vest in full immediately subject, in the case of a termination due to Disability, to the Participant’s execution and delivery to the Company (and non-revocation of) a release of claims that becomes fully effective and irrevocable within fifty-five (55) days following the date of termination. If a release is not timely executed and delivered by the Participant to the Company, or if such release is timely executed and delivered but is subsequently revoked by the Participant, then the Participant will automatically forfeit the unvested RSUs covered by this Award effective as of the date of termination of employment.

(B)    Except as otherwise provided in (A) the Plan, this Agreement or other agreement between the Company and the Participant, (B) any severance plan under which the Participant is eligible for benefits (“Severance Plan”) or (C) the Company’s Retirement Policy if applicable to the Participant, the Participant will automatically forfeit any unvested RSUs covered by this Award on the termination, resignation, or removal of the Participant from employment with or services to the Company and its Affiliates for any reason. In the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment. In the event that the Participant is eligible for benefits under a Severance Plan that is terminated prior to the date on which the Participant’s employment terminates and no successor plan governs the treatment of the unvested RSUs on a termination of employment, then the unvested RSUs will be treated in accordance with the terms, conditions, and covenants set forth in the Severance Plan and exhibits thereto as it existed immediately prior to its termination.

5.    Change in Control. In the event of a Change in Control of the Company, this Award will be treated in accordance with the Plan, Severance Plan or other agreement between

the Company and the Participant, if applicable, and in the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment.

6.    Settlement; Dividend Equivalents; Withholding of Taxes.

(A)    Subject to the Severance Plan or Retirement Policy, if applicable, and Paragraph 6(B), one Share will be delivered in respect of each vested RSU on or as soon as reasonably practicable, but in no event later than the sixtieth (60th) day, following the date on which the RSUs vest as determined in accordance with Paragraph 3, 4 or 5; provided, however, that if vesting is contingent on the effectiveness of a release of claims, and the release period begins in one taxable year and ends in a subsequent taxable year, then the Shares will be delivered in such subsequent taxable year. All ordinary cash dividends that would have been paid upon any Shares delivered in respect of the vested RSUs had such Shares been issued as of the Grant Date (as determined by the Committee) will be paid to the Participant (without interest) on the date on which the RSUs are settled in accordance with this Paragraph 6(A) to the extent that the RSUs vest.

(B)    The Company’s obligation to deliver Shares under this Award is subject to the payment of all federal, state and local income, employment and other taxes required to be withheld or paid by the Company in connection with this Award. The Company shall have the right to take any action as may be necessary or appropriate to satisfy any withholding obligations, provided, however, that except as otherwise agreed in writing by the Participant and the Company, if the Participant is an Executive Officer or an individual subject to Rule 16b-3, such tax withholding obligations will be effectuated by the Company withholding a number of Shares that would otherwise be issued and delivered in respect of the RSUs with a Fair Market Value equal to the amount of such tax withholding obligations (at the minimum withholding tax rate required by the Code).

7.    Participant Covenants.

(A)    Non-Competition. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, alone or jointly, with any person or entity, participate in, engage in, consult with, advise, be employed by, own (wholly or partially), possess an interest in, solicit the business of the vendors, suppliers or customers of the Company for, or in any other manner be involved with, any business or person that is engaged in business activities anywhere in the Territory that are competitive with the Business, provided, however, if the Participant voluntarily resigns without Good Reason (as defined in the Severance Plan), and not due to a Qualifying Retirement (as defined in the Retirement Policy), within three years following the Grant Date, this Paragraph 7(A) will only apply in the event the Company elects to make the payments set forth in Paragraph 7(E) subject to the requirements of that Paragraph 7(E). Notwithstanding the foregoing, the Participant shall not be prohibited from passively owning less than 1% of the securities of any publicly-traded corporation. For purposes of this Paragraph 7(A), “Territory” means anywhere in which the Company engages in Business and “Business” means the business of (i) selling, marketing, trading, or distributing liquefied natural gas and/or (ii) designing, permitting, constructing, developing or operating liquefied natural gas facilities and/or (iii) trading natural gas on behalf of a liquefied natural gas facility or facilities. Notwithstanding the foregoing, the Participant shall not be prohibited from being employed by, or consulting for, an entity that has a division immaterial to the business of such

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entity in the aggregate, which division may compete with, or could assist another in competing with, the Company in the Business in the Territory (a “Competitive Division”), so long as the Participant is not employed in, and does not perform work for or otherwise provide services to, the Competitive Division.

(B)    Non-Solicitation. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, do any of the following or assist any other person, firm, or entity to do any of the following: (a) solicit on behalf of the Participant or another person or entity, the employment or services of, or hire or retain, any person who is employed by or is a substantially full-time consultant or independent contractor to the Company or any of its subsidiaries or affiliates, or was within six (6) months prior to the action; (b) induce or attempt to induce any employee of the Company or its affiliates to terminate that employee’s employment with the Company or such subsidiary or affiliate; (c) induce or attempt to induce any consultant or independent contractor doing business with or retained by the Company or its subsidiaries or affiliates to terminate their consultancy or contractual relationship with the Company or such subsidiary or affiliate or otherwise reduce the services they provide to the Company or such subsidiary or affiliate or (d) interfere with the relationship of the Company or any of its subsidiaries or affiliates with any vendor or supplier.

(C)    Confidentiality. During employment and thereafter, the Participant shall maintain the confidentiality of the following information: proprietary technical and business information relating to any Company plans, analyses or strategies concerning international or domestic acquisitions, possible acquisitions or new ventures; development plans or introduction plans for products or services; unannounced products or services; operation costs; pricing of products or services; research and development; personnel information; manufacturing processes; installation, service, and distribution procedures and processes; customer lists; any know-how relating to the design, manufacture, and marketing of any of the Company’s services and products, including components and parts thereof; non-public information acquired by the Company concerning the requirements and specifications of any of the Company’s agents, vendors, contractors, customers and potential customers; non-public financial information, business and marketing plans, pricing and price lists; non-public matters relating to employee benefit plans; quotations or proposals given to agents or customers or received from suppliers; documents relating to any of the Company’s legal rights and obligations; the work product of any attorney employed by or retained by the Company; and any other information which is sufficiently confidential, proprietary, and secret to derive economic value from not being generally known including with respect to intellectual property inventions and work product. The Participant shall maintain in the strictest confidence and will not, directly or indirectly, intentionally or inadvertently, use, publish, or otherwise disclose to any person or entity whatsoever, any of the information of or belonging to the Company or to any agent, joint venture, contractor, customer, vendor, or supplier of the Company regardless of its form, without the prior written explicit consent of the Company. The Participant acknowledges that the foregoing information is not generally known, is highly confidential and constitutes trade secrets or confidential information of the Company. The Participant shall take reasonable precautions to protect the inadvertent disclosure of information. The foregoing shall not apply to information that the Participant is required to disclose by applicable law, regulation, or legal process (provided that the Participant provides the Company with prior notice of the contemplated disclosure and cooperates with the Company at its expense in seeking a protective order or other appropriate protection of such information). Notwithstanding the foregoing, nothing in this

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Agreement prohibits the Participant from reporting possible violations of federal law or regulation to any government agency or entity or making other disclosures that are protected under whistleblower provisions of law. The Participant does not need prior authorization to make such reports or disclosures and is not required to notify the Company that the Participant has made any such report or disclosure.

(D)    Non-Disparagement. During employment and thereafter, the Participant shall not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise malign the business reputation of, the Company, its affiliates or any of their respective officers, directors, managers, employees or partners.

(E)    Voluntary Resignation. If (a) the Participant voluntarily resigns without Good Reason (and not due to a Qualifying Retirement) within three years following the Grant Date and (b) the Company elects to enforce the covenants in Paragraph 7(A), then the Company agrees, as further consideration for such covenants, to continue to pay the Participant his or her base salary (at the rate in effect at the time of the Participant’s voluntary resignation) in accordance with the Company’s regular payroll dates for one year following the date of such voluntary resignation. The payment of the Participant’s base salary in accordance with this Paragraph 7(E) will begin on the first payroll after the 60th day following the Participant’s voluntary resignation (with the first payment including the aggregate amount that would have been paid in the first sixty (60) days) subject to the Participant’s execution and delivery to the Company (and non-revocation) of a Release Agreement that becomes fully effective and irrevocable within fifty-five (55) days following the date of voluntary resignation. If a Release Agreement is not timely executed and delivered to the Company by the Participant, or if such Release Agreement is timely executed and delivered but is subsequently revoked by the Participant, then the Participant will not be entitled to the base salary continuation set forth in this Paragraph 7(E). The Participant agrees to promptly notify the Company of the date on which the Participant begins employment with a new employer in compliance with this Paragraph 7 (the “Commencement Date”) within 12 months following the Participant’s voluntary resignation. The Company will not have any obligation to pay the Participant’s base salary in accordance with this Paragraph 7(E) after the Commencement Date.

(F)    Participant Acknowledgements.

(i)    The Participant agrees that the restrictions in this Paragraph 7 are reasonable in light of the scope of the Company’s business operations, the Participant’s position within the Company, the interests which the Company seeks to protect, and the consideration provided to the Participant. The Participant agrees that these restrictions go only so far as to protect the Company’s business and business interests, and that those interests are worth protecting for the continued success, viability, and goodwill of the Company.

(ii)    The Participant expressly acknowledges that any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7 may result in substantial, continuing, and irreparable injury to the Company and its subsidiaries and affiliates for which monetary damages alone would not be a sufficient remedy. Therefore, the Participant hereby agrees that, in addition to any other remedy that may be available to the Company (including pursuant to Paragraph 9), in the event of any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7, the Company shall be entitled to injunctive relief, specific performance or other equitable relief by a court of appropriate jurisdiction, without the requirement of posting bond or the necessity of proving irreparable harm or injury as a result of such breach or threatened breach. Without limitation on the Company’s rights under the foregoing sentence or under Paragraph 9, (a) in the event of any actual breach of any of the

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terms and/or conditions set forth in Paragraph 7(A) or 7(B) during the term of such covenants, or (b) in the event of any actual breach of any of the terms and/or conditions set forth in Paragraphs 7(C) or (D) of this Agreement prior to the first anniversary of the date on which the Participant’s employment terminates for any reason: (i) if the Award is unvested, then the Award will immediately be forfeited for no consideration; (ii) the Company will cease to be obligated to furnish the Participant any further payments or deliveries pursuant to this Agreement; and (iii) the Participant shall promptly repay to the Company an amount equal to the gain realized in respect of this Award within the three preceding years (which gain shall be deemed to be an amount equal to the aggregate Fair Market Value, on each of the date(s) on which the Award is settled, of the Shares delivered to the Participant under this Award within such three-year period); provided that the foregoing repayment obligations, and the cessation of further payments and benefits, shall be without prejudice to the Company’s other rights.

(iii)    Notwithstanding any other provision to the contrary, the Participant acknowledges and agrees that the restrictions set forth in this Paragraph 7, as applicable, shall be tolled during any period of violation of any of the covenants therein and during any other period required for litigation during which the Company seeks to enforce such covenants against the Participant.

8.    Cooperation. Following the termination of the Participant’s employment with the Company for any reason, the Participant agrees (i) to reasonably cooperate with the Company and its directors, officers, attorneys and experts, and take all actions the Company may reasonably request, including but not limited to cooperation with respect to any investigation, government inquiry, administrative proceeding or litigation relating to any matter in which the Participant was involved or had knowledge during the Participant’s employment with the Company and (ii) that, if called upon by the Company, the Participant will provide assistance with respect to business, personnel or other matters which arose during the Participant’s employment with the Company or as to which the Participant has relevant information, knowledge or expertise, with such cooperation including, but not limited to, completing job tasks in progress, transitioning job tasks to other Company personnel, responding to questions and being available for such purposes. Any cooperation requests shall take into account the Participant’s personal and business commitments, and the Participant shall be reasonably compensated for the Participant’s time (if appropriate for the matter) and further reimbursed for any documented expenses (including reasonable attorney’s fees) incurred in connection with such cooperation within thirty (30) days of the Participant providing an invoice to the Company.

9.    Forfeiture/Clawback.

(A)    The delivery of Shares under this Award is subject to any policy (whether in existence as of the Grant Date or later adopted) established by the Company or required by applicable law providing for clawback or recovery of amounts that were paid to the Participant. The Company will make any determination for clawback or recovery in its sole discretion and in accordance with any applicable law or regulation.

(B)    In addition to Paragraph 9(A) and notwithstanding anything to the contrary in this Agreement, if the Board or Committee determines that the Participant has, without the consent of the Company, violated a non-competition, non-solicitation or non-disclosure covenant (including the covenants in Paragraph 7) between the Participant and the Company or any Affiliate, then the Board or Committee may in its sole discretion (i) determine that all or any portion of any unvested RSUs shall be forfeited for no consideration and/or (ii) require the Participant to promptly repay to the Company any gain realized in respect of this Award within the three years preceding the date on which the Board or Committee determines

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that any of the events described above has occurred (which gain shall be deemed to be an amount equal to the aggregate Fair Market Value, on each of the date(s) on which the Award is settled, of the Shares delivered to the Participant under this Award within such three-year period). Unless otherwise required by law, the provisions of this Paragraph 9(B) shall apply during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason. The foregoing forfeiture and repayment obligations shall be without prejudice to any other rights that the Company may have.

10.    Effect of the Plan.This Award is subject to all of the provisions of the Plan and this Agreement, together with all of the rules and determinations from time to time issued by the Committee and/or the Board pursuant to the Plan, including the restrictions in the Plan on the transferability of awards. In the event of a conflict between any provision of the Plan and this Agreement, the provisions of this Agreement shall control but only to the extent such conflict is permitted under the Plan. By accepting this Award, the Participant acknowledges that he or she has received a copy of the Plan and agrees that the Participant will enter into such written representations, warranties and agreements and execute such documents as the Company may reasonably request in order to comply with applicable securities and other applicable laws, rules or regulations, or with this document or the terms of the Plan, the Severance Plan or the Cheniere Retirement Plan, as applicable.

11.    Amendment and Termination; Waiver. This Agreement, together with the Plan, constitutes the entire agreement by the Participant and the Company with respect to the subject matter hereof, and supersedes any and all prior agreements or understandings between the Participant and the Company with respect to the subject matter hereof, whether written or oral. This Agreement may not be amended or terminated by the Company in a manner that would be materially adverse to the Participant without the written consent of the Participant, provided that the Company may amend this Agreement unilaterally (a) as provided in the Plan or (b) if the Company determines that an amendment is necessary to comply with applicable law (including the requirements of the Code). Any provision for the benefit of the Company contained in this Agreement may be waived in writing, either generally or in any particular instance, by the Company. A waiver on one occasion shall not be deemed to be a waiver of the same or any other breach on a future occasion.

12.    Unsecured Obligation. The Company’s obligation under this Agreement shall be an unfunded and unsecured promise. The Participant’s right to receive the payments and benefits contemplated hereby from the Company under this Agreement shall be no greater than the right of any unsecured general creditor of the Company, and the Participant shall not have nor acquire any legal or equitable right, interest or claim in or to any property or assets of the Company. Nothing contained in this Agreement, and no action taken pursuant to its provisions, will create or be construed to create a trust of any kind or a fiduciary relationship between the Participant and the Company or any other person.

13.    No Right To Continued Employment. Neither this Award nor anything in this Agreement shall confer upon the Participant any right to continued employment with the Company (or its Affiliates or their respective successors) or shall interfere in any way with the right of the Company (or its Affiliates or their respective successors) to terminate the Participant’s employment at any time.

14.    Tax Matters; No Guarantee of Tax Consequences. This Agreement is intended to be exempt from, or to comply with, the requirements of Section 409A of the Code and this Agreement shall be interpreted accordingly; provided that in no event whatsoever shall the Company or any of its Affiliates be liable for any additional tax, interest or penalties that may be

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imposed on the Participant by Section 409A of the Code or any damages for failing to comply with Section 409A of the Code. Each payment under this Agreement will be treated as a separate payment for purposes of Section 409A of the Code. The Company makes no commitment or guarantee to the Participant that any federal or state tax treatment will apply or be available to any person eligible for benefits under this Agreement.

15.    Governing Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Delaware to the extent federal law does not supersede and preempt Delaware law (in which case such federal law shall apply).

16.    Severability; Interpretive Matters. In the event that any provision of this Agreement shall be held illegal, invalid, or unenforceable for any reason, such provision shall be fully severable, but shall not affect the remaining provisions of this Agreement, and this Agreement shall be construed and enforced as if the illegal, invalid, or unenforceable provision had never been included herein. Whenever required by the context, pronouns and any variation thereof shall be deemed to refer to the masculine, feminine, or neuter, and the singular shall include the plural and vice versa. The terms “includes” or “including” in this Agreement shall be construed as “including without limitation”, so that terms following “includes” or “including” are not exhaustive. The captions and headings used in this Agreement are inserted for convenience and shall not be deemed a part of this Agreement granted hereunder for construction or interpretation.

17.    Counterparts. This Agreement may be signed in any number of counterparts, each of which will be an original, with the same force and effect as if the signature thereto and hereto were upon the same instrument.

[Remainder of Page Blank – Signature Page Follows]

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the Grant Date indicated below.

COMPANY:
CHENIERE ENERGY, INC.
By:
	Name:
	Title:

I hereby accept the Award subject to all of the terms and provisions hereof. I acknowledge and agree that the Award shall vest and become payable, if at all, only during the period of my continued service with the Company or as otherwise provided in this Agreement (not through the act of issuing the Award).

PARTICIPANT:
By:
	Name:

Grant Date:

Schedule A

●    RSUs:

●    Vesting Dates:

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EX-10.5

Exhibit 10.5

CHENIERE ENERGY, INC.
2020 INCENTIVE PLAN

RESTRICTED STOCK UNIT AWARD AGREEMENT

1.    Award. Cheniere Energy, Inc., a Delaware corporation (the “Company”), has awarded the undersigned Participant (for purposes of this Agreement, the “Participant”) restricted stock units (this “Award”) effective as of the date set forth on the signature page hereto (the “Grant Date”) pursuant to the Company’s 2020 Incentive Plan (as amended or restated from time to time, the “Plan”). Unless otherwise defined in this Restricted Stock Unit Award Agreement (this “Agreement”), capitalized terms used herein shall have the meanings assigned to them in the Plan.

2.    Restricted Stock Units. The Company hereby awards the Participant the number of restricted stock units set forth in Schedule A (the “RSUs”). Each RSU constitutes an unfunded and unsecured promise by the Company to deliver (or cause to be delivered) one share of common stock, $0.003 par value per share, of the Company (a “Share”) or the value thereof. The RSUs will be subject to vesting in accordance with Paragraph 3 below.

3.    Vesting. Subject to the Participant’s continued employment and Paragraphs 4 and 5, the RSUs shall vest on the date or dates set forth in Schedule A (each, a “Vesting Date”).

4.    Termination of Employment or Services.

(A)    Upon the termination of the Participant’s employment with the Company or an Affiliate (1) by the Company or an Affiliate due to the Disability of the Participant while performing Continuous Service or (2) due to the death of the Participant while performing Continuous Service, unvested RSUs shall vest in full immediately subject, in the case of a termination due to Disability, to the Participant’s execution and delivery to the Company (and non-revocation of) a release of claims that becomes fully effective and irrevocable within fifty-five (55) days following the date of termination. If a release is not timely executed and delivered by the Participant to the Company, or if such release is timely executed and delivered but is subsequently revoked by the Participant, then the Participant will automatically forfeit the unvested RSUs covered by this Award effective as of the date of termination of employment.

(B)    Except as otherwise provided in (A) the Plan, this Agreement or other agreement between the Company and the Participant, (B) any severance plan under which the Participant is eligible for benefits (“Severance Plan”) or (C) the Company’s Retirement Policy if applicable to the Participant, the Participant will automatically forfeit any unvested RSUs covered by this Award on the termination, resignation, or removal of the Participant from employment with or services to the Company and its Affiliates for any reason. In the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment. In the event that the Participant is eligible for benefits under a Severance Plan that is terminated prior to the date on which the Participant’s employment terminates and no successor plan governs the treatment of the unvested RSUs on a termination of employment, then the unvested RSUs will be treated in accordance with the terms, conditions, and covenants set forth in the Severance Plan and exhibits thereto as it existed immediately prior to its termination.

5.    Change in Control. In the event of a Change in Control of the Company, this Award will be treated in accordance with the Plan, Severance Plan or other agreement between

the Company and the Participant, if applicable, and in the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment.

6.    Settlement; Dividend Equivalents; Withholding of Taxes.

(A)    Subject to the Severance Plan or Retirement Policy, if applicable, and Paragraph 6(B), one Share will be delivered in respect of each vested RSU on or as soon as reasonably practicable, but in no event later than the sixtieth (60th) day, following the date on which the RSUs vest as determined in accordance with Paragraph 3, 4 or 5; provided, however, that if vesting is contingent on the effectiveness of a release of claims, and the release period begins in one taxable year and ends in a subsequent taxable year, then the Shares will be delivered in such subsequent taxable year. Notwithstanding the foregoing, in lieu of all or any portion of the Shares otherwise deliverable in respect of the vested RSUs, the Committee may permit the Participant to elect to receive a cash amount equal to all or a portion of the number of such Shares multiplied by the Fair Market Value of a Share. Such election will be made pursuant to a form containing such terms as the Committee shall determine. The Fair Market Value of a vested RSU shall equal the average closing price of a Share for the 45 trading days preceding the end of the vesting period as reported on the New York Stock Exchange. All ordinary cash dividends that would have been paid upon any Shares deliverable in respect of the vested RSUs (whether such vested RSUs are settled in cash or Shares) had such Shares been issued as of the Grant Date (as determined by the Committee) will be paid to the Participant (without interest) on the date on which the RSUs are settled in accordance with this Paragraph 6(A) to the extent that the RSUs vest.

(B)    The Company’s obligation to deliver Shares or cash under this Award is subject to the payment of all federal, state and local income, employment and other taxes required to be withheld or paid by the Company in connection with this Award. The Company shall have the right to take any action as may be necessary or appropriate to satisfy any withholding obligations, provided, however, that except as otherwise agreed in writing by the Participant and the Company, if the Participant is an Executive Officer or an individual subject to Rule 16b-3, such tax withholding obligations will be effectuated by the Company withholding a number of Shares and/or an amount of cash that would otherwise be issued and delivered in respect of the RSUs with a Fair Market Value equal to the amount of such tax withholding obligations (at the minimum withholding tax rate required by the Code).

7.    Participant Covenants.

(A)    Non-Competition. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill, Confidential Information (as defined in Section 7(c) and in related agreements), and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, alone or jointly, with any person or entity:

(1) own (wholly or partially), possess an interest in, solicit the business of the vendors, suppliers or customers of the Company for, or finance any business or person that is engaged in business activities anywhere in the Territory that are competitive with the Business (as defined below), provided, however, the Participant shall not be prohibited from passively owning less than 1% of the securities of any publicly-traded corporation.

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(2) employed by, manage, operate, provide services to, consult, or advise any business or person that is engaged in activities anywhere in the Territory that are competitive with the Business in which (i) the Participant would perform any duties or responsibilities which are similar to those Participant performed on behalf of the Company in any capacity (whether prior to the execution of this Agreement or after the execution of this Agreement), or (ii) whereby Participant would use or disclose (or may use or disclose) any Confidential Information to perform any duties or responsibilities for any such business or person;

provided, however, if the Participant voluntarily resigns without Good Reason (as defined in the Severance Plan), and not due to a Qualifying Retirement (as defined in the Retirement Policy), within three years following the Grant Date, this Paragraph 7(A) will only apply in the event the Company elects to make the payments set forth in Paragraph 7(E) subject to the requirements of that Paragraph 7(E). For purposes of this Paragraph 7(A), “Territory” means anywhere in which the Company engages in Business and “Business” means the business of (i) selling, marketing, trading, or distributing liquefied natural gas and/or (ii) designing, permitting, constructing, developing or operating liquefied natural gas facilities and/or (iii) trading natural gas on behalf of a liquefied natural gas facility or facilities. Notwithstanding the foregoing, the Participant shall not be prohibited from being employed by, or consulting for, an entity that has a division immaterial to the business of such entity in the aggregate, which division may compete with, or could assist another in competing with, the Company in the Business in the Territory (a “Competitive Division”), so long as the Participant is not employed in, and does not perform work for or otherwise provide services to, the Competitive Division.

(B)    Non-Solicitation. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, do any of the following or assist any other person, firm, or entity to do any of the following: (a) solicit on behalf of the Participant or another person or entity, the employment or services of, or hire or retain, any person who is employed by or is a substantially full-time consultant or independent contractor to the Company or any of its subsidiaries or affiliates, or was within six (6) months prior to the action; (b) induce or attempt to induce any employee of the Company or its affiliates to terminate that employee’s employment with the Company or such subsidiary or affiliate; (c) induce or attempt to induce any consultant or independent contractor doing business with or retained by the Company or its subsidiaries or affiliates to terminate their consultancy or contractual relationship with the Company or such subsidiary or affiliate or otherwise reduce the services they provide to the Company or such subsidiary or affiliate or (d) interfere with the relationship of the Company or any of its subsidiaries or affiliates with any vendor or supplier.

(C)    Confidentiality. During employment and thereafter, the Participant shall maintain the confidentiality of the following information (collectively, “Confidential Information”): proprietary technical and business information relating to any Company plans, analyses or strategies concerning international or domestic acquisitions, possible acquisitions or new ventures; development plans or introduction plans for products or services; unannounced products or services; operation costs; pricing of products or services; research and development; personnel information; manufacturing processes; installation, service, and distribution procedures and processes; customer lists; any know-how relating to the design, manufacture, and marketing of any of the Company’s services and products, including components and partsthereof; non-public information acquired by the Company concerning the requirements and specifications of any of the Company’s agents, vendors, contractors, customers and potential

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customers; non-public financial information, business and marketing plans, pricing and price lists; non-public matters relating to employee benefit plans; quotations or proposals given to agents or customers or received from suppliers; documents relating to any of the Company’s legal rights and obligations; the work product of any attorney employed by or retained by the Company; and any other information which is sufficiently confidential, proprietary, and secret to derive economic value from not being generally known including with respect to intellectual property inventions and work product. The Participant shall maintain in the strictest confidence and will not, directly or indirectly, intentionally or inadvertently, use, publish, or otherwise disclose to any person or entity whatsoever, any of the information of or belonging to the Company or to any agent, joint venture, contractor, customer, vendor, or supplier of the Company regardless of its form, without the prior written explicit consent of the Company. The Participant acknowledges that the foregoing information is not generally known, is highly confidential and constitutes trade secrets or confidential information of the Company. The Participant shall take reasonable precautions to protect the inadvertent disclosure of information.

The foregoing shall not apply to information that the Participant is required to disclose by applicable law, regulation, or legal process (provided that the Participant provides the Company with prior notice of the contemplated disclosure and cooperates with the Company at its expense in seeking a protective order or other appropriate protection of such information). Notwithstanding the foregoing, nothing in this Agreement prohibits the Participant from reporting possible violations of federal, state or local law or regulation to any government agency or entity, filing a charge with or participating in an investigation conducted by any government agency or entity, or making other disclosures that are protected under whistleblower provisions of law.  The Participant does not need prior authorization to make such reports or disclosures and is not required to notify the Company that the Participant has made any such report or disclosure. The Company does not waive confidentiality or any applicable privilege.

(D)    Non-Disparagement. During employment and thereafter, the Participant shall not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise malign the business reputation of, the Company, its affiliates or any of their respective officers, directors, managers, employees or partners.

(E)    Voluntary Resignation. If (a) the Participant voluntarily resigns without Good Reason (and not due to a Qualifying Retirement) within three years following the Grant Date and (b) the Company elects to enforce the covenants in Paragraph 7(A), then the Company agrees, as further consideration for such covenants, to continue to pay the Participant his or her base salary (at the rate in effect at the time of the Participant’s voluntary resignation) in accordance with the Company’s regular payroll dates for one year following the date of such voluntary resignation. The payment of the Participant’s base salary in accordance with this Paragraph 7(E) will begin on the first payroll after the 60th day following the Participant’s voluntary resignation (with the first payment including the aggregate amount that would have been paid in the first sixty (60) days) subject to the Participant’s execution and delivery to the Company (and non-revocation) of a Release Agreement that becomes fully effective and irrevocable within fifty-five (55) days following the date of voluntary resignation. If a Release Agreement is not timely executed and delivered to the Company by the Participant, or if such Release Agreement is timely executed and delivered but is subsequently revoked by the Participant, then the Participant will not be entitled to the base salary continuation set forth in this Paragraph 7(E). The Participant agrees to promptly notify the Company of the date on which the Participant begins employment with a new employer in compliance with this Paragraph 7 (the “Commencement Date”) within 12 months following the Participant’s voluntary resignation. The Company will not have any obligation to pay the Participant’s base salary in accordance with this Paragraph 7(E) after the Commencement Date.

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(F)    Participant Acknowledgements.

(i)    The Participant agrees that the restrictions in this Paragraph 7 are reasonable in light of the scope of the Company’s business operations, the Participant’s position within the Company, the interests which the Company seeks to protect, and the consideration provided to the Participant. The Participant agrees that these restrictions go only so far as to protect the Company’s business and business interests, and that those interests are worth protecting for the continued success, viability, and goodwill of the Company.

(ii)    The Participant expressly acknowledges that any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7 may result in substantial, continuing, and irreparable injury to the Company and its subsidiaries and affiliates for which monetary damages alone would not be a sufficient remedy. Therefore, the Participant hereby agrees that, in addition to any other remedy that may be available to the Company (including pursuant to Paragraph 9), in the event of any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7, the Company shall be entitled to injunctive relief, specific performance or other equitable relief by a court of appropriate jurisdiction, without the requirement of posting bond or the necessity of proving irreparable harm or injury as a result of such breach or threatened breach. Without limitation on the Company’s rights under the foregoing sentence or under Paragraph 9, (a) in the event of any actual breach of any of the terms and/or conditions set forth in Paragraph 7(A) or 7(B) during the term of such covenants, or (b) in the event of any actual breach of any of the terms and/or conditions set forth in Paragraphs 7(C) or (D) of this Agreement prior to the first anniversary of the date on which the Participant’s employment terminates for any reason: (i) if the Award is unvested, then the Award will immediately be forfeited for no consideration; (ii) the Company will cease to be obligated to furnish the Participant any further payments or deliveries pursuant to this Agreement; and (iii) the Participant shall promptly repay to the Company an amount equal to the gain realized in respect of this Award within the three preceding years (which gain shall be deemed to be an amount equal to the aggregate (x) cash amount and (y) with respect to Shares, the Fair Market Value, on each of the date(s) on which the Award is settled, of the Shares delivered to the Participant under this Award within such three-year period); provided that the foregoing repayment obligations, and the cessation of further payments and benefits, shall be without prejudice to the Company’s other rights.

(iii)    Notwithstanding any other provision to the contrary, the Participant acknowledges and agrees that the restrictions set forth in this Paragraph 7, as applicable, shall be tolled during any period of violation of any of the covenants therein and during any other period required for litigation during which the Company seeks to enforce such covenants against the Participant.

8.    Cooperation. Following the termination of the Participant’s employment with the Company for any reason, the Participant agrees (i) to reasonably cooperate with the Company and its directors, officers, attorneys and experts, and take all actions the Company may reasonably request, including but not limited to cooperation with respect to any investigation, government inquiry, administrative proceeding or litigation relating to any matter in which the Participant was involved or had knowledge during the Participant’s employment with the Company and (ii) that, if called upon by the Company, the Participant will provide assistance with respect to business, personnel or other matters which arose during the Participant’s employment with the Company or as to which the Participant has relevant information, knowledge or expertise, with such cooperation including, but not limited to, completing job tasks in progress, transitioning job tasks to other Company personnel, responding to questions and being available for such purposes. Any cooperation requests shall take into account the Participant’s personal and business commitments, and the Participant shall be reasonably compensated for the Participant’s time (if appropriate for the matter) and further reimbursed for any documented expenses (including reasonable attorney’s fees) incurred in connection with such cooperation within thirty (30) days of the Participant providing an invoice to the Company.

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9.    Forfeiture/Clawback.

(A)    The delivery of Shares or cash under this Award is subject to any policy (whether in existence as of the Grant Date or later adopted) established by the Company or required by applicable law providing for clawback or recovery of amounts that were paid to the Participant. The Company will make any determination for clawback or recovery in its sole discretion and in accordance with any applicable law or regulation.

(B)    In addition to Paragraph 9(A) and notwithstanding anything to the contrary in this Agreement, if the Board or Committee determines that the Participant has, without the consent of the Company, violated a non-competition, non-solicitation or non-disclosure covenant (including the covenants in Paragraph 7) between the Participant and the Company or any Affiliate, then the Board or Committee may in its sole discretion (i) determine that all or any portion of any unvested RSUs shall be forfeited for no consideration and/or (ii) require the Participant to promptly repay to the Company any gain realized in respect of this Award within the three years preceding the date on which the Board or Committee determines that any of the events described above has occurred (which gain shall be deemed to be an amount equal to the aggregate (x) cash amount and (y) with respect to Shares, the Fair Market Value, on each of the date(s) on which the Award is settled, of the Shares delivered to the Participant under this Award within such three-year period). Unless otherwise required by law, the provisions of this Paragraph 9(B) shall apply during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason. The foregoing forfeiture and repayment obligations shall be without prejudice to any other rights that the Company may have.

10.    Effect of the Plan.This Award is subject to all of the provisions of the Plan and this Agreement, together with all of the rules and determinations from time to time issued by the Committee and/or the Board pursuant to the Plan, including the restrictions in the Plan on the transferability of awards. In the event of a conflict between any provision of the Plan and this Agreement, the provisions of this Agreement shall control but only to the extent such conflict is permitted under the Plan. By accepting this Award, the Participant acknowledges that he or she has received a copy of the Plan and agrees that the Participant will enter into such written representations, warranties and agreements and execute such documents as the Company may reasonably request in order to comply with applicable securities and other applicable laws, rules or regulations, or with this document or the terms of the Plan, the Severance Plan or the Cheniere Retirement Plan, as applicable.

11.    Amendment and Termination; Waiver. This Agreement, together with the Plan, constitutes the entire agreement by the Participant and the Company with respect to the subject matter hereof, and supersedes any and all prior agreements or understandings between the Participant and the Company with respect to the subject matter hereof, whether written or oral. This Agreement may not be amended or terminated by the Company in a manner that would be materially adverse to the Participant without the written consent of the Participant, provided that the Company may amend this Agreement unilaterally (a) as provided in the Plan or (b) if the Company determines that an amendment is necessary to comply with applicable law (including the requirements of the Code). Any provision for the benefit of the Company contained in this Agreement may be waived in writing, either generally or in any particular instance, by the Company. A waiver on one occasion shall not be deemed to be a waiver of the same or any other breach on a future occasion.

12.    Unsecured Obligation. The Company’s obligation under this Agreement shall be an unfunded and unsecured promise. The Participant’s right to receive the payments and benefits contemplated hereby from the Company under this Agreement shall be no greater than

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the right of any unsecured general creditor of the Company, and the Participant shall not have nor acquire any legal or equitable right, interest or claim in or to any property or assets of the Company. Nothing contained in this Agreement, and no action taken pursuant to its provisions, will create or be construed to create a trust of any kind or a fiduciary relationship between the Participant and the Company or any other person.

13.    No Right To Continued Employment. Neither this Award nor anything in this Agreement shall confer upon the Participant any right to continued employment with the Company (or its Affiliates or their respective successors) or shall interfere in any way with the right of the Company (or its Affiliates or their respective successors) to terminate the Participant’s employment at any time.

14.    Tax Matters; No Guarantee of Tax Consequences. This Agreement is intended to be exempt from, or to comply with, the requirements of Section 409A of the Code and this Agreement shall be interpreted accordingly; provided that in no event whatsoever shall the Company or any of its Affiliates be liable for any additional tax, interest or penalties that may be imposed on the Participant by Section 409A of the Code or any damages for failing to comply with Section 409A of the Code. Each payment under this Agreement will be treated as a separate payment for purposes of Section 409A of the Code. The Company makes no commitment or guarantee to the Participant that any federal or state tax treatment will apply or be available to any person eligible for benefits under this Agreement.

15.    Governing Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Texas to the extent federal law does not supersede and preempt Texas law (in which case such federal law shall apply).

16.    Severability; Interpretive Matters. In the event that any provision of this Agreement shall be held illegal, invalid, or unenforceable for any reason, such provision shall be fully severable, but shall not affect the remaining provisions of this Agreement, and this Agreement shall be construed and enforced as if the illegal, invalid, or unenforceable provision had never been included herein. Whenever required by the context, pronouns and any variation thereof shall be deemed to refer to the masculine, feminine, or neuter, and the singular shall include the plural and vice versa. The terms “includes” or “including” in this Agreement shall be construed as “including without limitation”, so that terms following “includes” or “including” are not exhaustive. The captions and headings used in this Agreement are inserted for convenience and shall not be deemed a part of this Agreement granted hereunder for construction or interpretation. The Parties hereby irrevocably submit to the exclusive jurisdiction of the applicable state or federal courts located in Harris County, Texas.

17.    Counterparts. This Agreement may be signed in any number of counterparts, each of which will be an original, with the same force and effect as if the signature thereto and hereto were upon the same instrument.

[Remainder of Page Blank – Signature Page Follows]

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the Grant Date indicated below.

COMPANY:
CHENIERE ENERGY, INC.
By:
	Name:
	Title:

I hereby accept the Award subject to all of the terms and provisions hereof. I acknowledge and agree that the Award shall vest and become payable, if at all, only during the period of my continued service with the Company or as otherwise provided in this Agreement (not through the act of issuing the Award).

PARTICIPANT:
By:
	Name:

Grant Date:

Schedule A

●    RSUs:

●    Vesting Dates:

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EX-10.8

Exhibit 10.8

CHENIERE ENERGY, INC.
2020 INCENTIVE PLAN

PERFORMANCE STOCK UNIT AWARD AGREEMENT

1.    Award. Cheniere Energy, Inc., a Delaware corporation (the “Company”), has awarded the undersigned Participant (for purposes of this Agreement, the “Participant”) performance stock units (this “Award”) effective as of the date set forth on the signature page hereto (the “Grant Date”) pursuant to the Company’s 2020 Incentive Plan (as amended or restated from time to time, the “Plan”). Unless otherwise defined in this Performance Stock Unit Award Agreement (this “Agreement”), capitalized terms used herein shall have the meanings assigned to them in the Plan.

2.    Performance Stock Units. The Company hereby awards the Participant the target number of performance stock units (“PSUs”) set forth in Schedule A (the “Target PSUs”). Each PSU constitutes an unfunded and unsecured promise by the Company to deliver (or cause to be delivered) one share of common stock, $0.003 par value per share, of the Company (a “Share”) or the value of one Share, as provided in Paragraph 6 below. The actual number of PSUs that will be earned is subject to the Committee’s certification of the level of achievement of the performance conditions set forth in Schedule A (the “Performance Metrics”) at the end of the applicable performance period (such earned PSUs, the “Earned PSUs”). The number of Shares covered by the Earned PSUs may range from 0% to 300% of the Target PSUs; provided that the number of Shares will be rounded down to the nearest whole Share. The Earned PSUs will be subject to vesting in accordance with Paragraph 3 below, and any PSUs that do not become Earned PSUs at the end of the performance period will be automatically forfeited without consideration.

3.    Vesting. Subject to the Participant’s continued employment and Paragraphs 4 and 5, the Earned PSUs, if any, shall vest on the date on which the Committee certifies achievement of the Performance Metrics (the “Certification Date”). The Certification Date will be within 75 days following the end of the performance period set forth in Schedule A.

4.    Termination of Employment or Services.

(A)    Upon the termination of the Participant’s employment with the Company or an Affiliate prior to vesting (1) by the Company or an Affiliate due to the Disability of the Participant while performing Continuous Service or (2) due to the death of the Participant while performing Continuous Service, the Target PSUs shall be deemed to be the Earned PSUs and shall vest in full immediately subject, in the case of a termination due to Disability, to the Participant’s execution and delivery to the Company (and non-revocation of) a release of claims that becomes fully effective and irrevocable within fifty-five (55) days following the date of termination. If a release is not timely executed and delivered by the Participant to the Company, or if such release is timely executed and delivered but is subsequently revoked by the Participant, then the Participant will automatically forfeit the PSUs covered by this Award effective as of the date of termination of employment.

(B)    Except as otherwise provided in (A) the Plan, this Agreement or other agreement between the Company and the Participant, (B) any severance plan under which the Participant is eligible for benefits (“Severance Plan”) or (C) the Company’s Retirement Policy, the Participant will automatically forfeit the PSUs covered by this Award on the termination, resignation, or removal of the Participant from employment with or services to the Company and its Affiliates for any reason prior to the date on which the PSUs vest. In the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment. In the event that the Participant is eligible for benefits under a Severance Plan that is terminated prior to the date on which the Participant’s employment terminates and no successor plan governs the treatment of this Award on a

termination of employment, then this Award will be treated in accordance with the terms, conditions, and covenants set forth in the Severance Plan and exhibits thereto as it existed immediately prior to its termination.

5.    Change in Control. In the event of a Change in Control of the Company, this Award will be treated in accordance with the Plan, Severance Plan or other agreement between the Company and the Participant, if applicable, and in the event of any conflict among such arrangements, this Award will be treated in accordance with such arrangement that provides the Participant the most favorable treatment.

6.    Settlement; Dividend Equivalents; Withholding of Taxes.

(A)    Subject to the Severance Plan or Retirement Policy, if applicable, and Paragraph 6(B), on or as soon as reasonably practicable, but in no event later than the sixtieth (60th) day, following the date on which the Earned PSUs vest as determined in accordance with Paragraph 3, 4 or 5:

(i)     if the vested Earned PSUs have a Fair Market Value of equal to or less than $3,000,000, an amount of cash equal to the Fair Market Value of the vested Earned PSUs will be delivered in respect of such Earned PSUs, and

(ii)     if the vested Earned PSUs have a Fair Market Value of greater than $3,000,000, cash will be delivered in respect of the number of vested Earned PSUs with a Fair Market Value of $3,000,000 (rounded down to the nearest whole number of vested Earned PSUs) and Shares will be delivered in respect of the balance of the remaining vested Earned PSUs;

provided, however, that if vesting is contingent on the effectiveness of a release of claims, and the release period begins in one taxable year and ends in a subsequent taxable year, then the Shares and/or cash will be delivered in such subsequent taxable year; provided, further that, in lieu of all or any portion of the Shares otherwise deliverable in respect of the vested Earned PSUs, the Committee may permit the Participant to elect to receive a cash amount equal to all or a portion of the number of such Shares multiplied by the Fair Market Value of a Share. Such election will be made pursuant to a form containing such terms as the Committee shall determine. The Fair Market Value of an Earned PSU determined pursuant to this Paragraph 6(A) as applicable shall equal the average closing price of a Share for the 45 trading days preceding the end of the vesting period as reported on the New York Stock Exchange. All ordinary cash dividends that would have been paid upon the Shares underlying the vested Earned PSUs (whether settled in cash or Shares) had such Shares been issued as of the Grant Date (as determined by the Committee) will be paid to the Participant (without interest) on the date on which the Earned PSUs are settled in accordance with this Paragraph 6(A) to the extent that the Earned PSUs vest.

(B)    The Company’s obligation to deliver Shares or cash under this Award is subject to the payment of all federal, state and local income, employment and other taxes required to be withheld or paid by the Company in connection with this Award. The Company shall have the right to take any action as may be necessary or appropriate to satisfy any withholding obligations, provided, however, that except as otherwise agreed in writing by the Participant and the Company, if the Participant is an Executive Officer or an individual subject to Rule 16b-3, such tax withholding obligations will be effectuated by the Company withholding a number of Shares and/or an amount of cash that would otherwise be issued and delivered in respect of the Earned PSUs with an aggregate value (based on the Fair Market Value of the Shares) equal to the amount of such tax withholding obligations.

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7.    Participant Covenants.

(A)    Non-Competition. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill, Confidential Information (as defined in Section 7(c) and in related agreements), and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, alone or jointly, with any person or entity:

(1) own (wholly or partially), possess an interest in, solicit the business of the vendors, suppliers or customers of the Company for, or, finance any business or person that is engaged in business activities anywhere in the Territory that are competitive with the Business (as defined below), provided, however, the Participant shall not be prohibited from passively owning less than 1% of the securities of any publicly-traded corporation.

(2) employed by, manage, operate, provide services to, consult, or advise any business or person that is engaged in activities anywhere in the Territory that are competitive with the Business in which (i) the Participant would perform any duties or responsibilities which are similar to those Participant performed on behalf of the Company in any capacity (whether prior to the execution of this Agreement or after the execution of this Agreement), or (ii) whereby Participant would use or disclose (or may use or disclose) any Confidential Information to perform any duties or responsibilities for any such business or person;

provided, however, if the Participant voluntarily resigns without Good Reason (as defined in the Severance Plan), and not due to a Qualifying Retirement (as defined in the Retirement Policy), within three years following the Grant Date, this Paragraph 7(A) will only apply in the event the Company elects to make the payments set forth in Paragraph 7(E) subject to the requirements of that Paragraph 7(E). For purposes of this Paragraph 7(A), “Territory” means anywhere in which the Company engages in Business and “Business” means the business of (i) selling, marketing, trading or distributing liquefied natural gas and/or (ii) designing, permitting, constructing, developing or operating liquefied natural gas facilities and/or (iii) trading natural gas on behalf of a liquefied natural gas facility or facilities. Notwithstanding the foregoing, the Participant shall not be prohibited from being employed by, or consulting for, an entity that has a division immaterial to the business of such entity in the aggregate, which division may compete with, or could assist another in competing with, the Company in the Business in the Territory (a “Competitive Division”), so long as the Participant is not employed in, and does not perform work for or otherwise provide services to, the Competitive Division.

(B)    Non-Solicitation. In exchange for the promises set forth herein, including the consideration set forth in Paragraph 1, and in order to protect the Company’s goodwill and other legitimate business needs, during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason, the Participant will not, directly or indirectly, do any of the following or assist any other person, firm, or entity to do any of the following: (a) solicit on behalf of the Participant or another person or entity, the employment or services of, or hire or retain, any person who is employed by or is a substantially full-time consultant or independent contractor to the Company or any of its subsidiaries or affiliates, or was within six (6) months prior to the action; (b) induce or attempt to induce any employee of the Company or its affiliates to terminate that employee’s employment with the Company or such subsidiary or affiliate; (c) induce or attempt to induce any consultant or independent contractor doing business with or retained by the Company or its subsidiaries or affiliates to terminate their consultancy or contractual relationship with the Company or such subsidiary or affiliate or otherwise reduce the services they provide to the Company or such subsidiary or affiliate or (d) interfere with the relationship of the Company or any of its subsidiaries or affiliates with any vendor or supplier.

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(C)    Confidentiality. During employment and thereafter, the Participant shall maintain the confidentiality of the following information (collectively, “Confidential Information”): proprietary technical and business information relating to any Company plans, analyses or strategies concerning international or domestic acquisitions, possible acquisitions or new ventures; development plans or introduction plans for products or services; unannounced products or services; operation costs; pricing of products or services; research and development; personnel information; manufacturing processes; installation, service, and distribution procedures and processes; customer lists; any know-how relating to the design, manufacture, and marketing of any of the Company’s services and products, including components and parts thereof; non-public information acquired by the Company concerning the requirements and specifications of any of the Company’s agents, vendors, contractors, customers and potential customers; non-public financial information, business and marketing plans, pricing and price lists; non-public matters relating to employee benefit plans; quotations or proposals given to agents or customers or received from suppliers; documents relating to any of the Company’s legal rights and obligations; the work product of any attorney employed by or retained by the Company; and any other information which is sufficiently confidential, proprietary, and secret to derive economic value from not being generally known including with respect to intellectual property inventions and work product. The Participant shall maintain in the strictest confidence and will not, directly or indirectly, intentionally or inadvertently, use, publish, or otherwise disclose to any person or entity whatsoever, any of the information of or belonging to the Company or to any agent, joint venture, contractor, customer, vendor, or supplier of the Company regardless of its form, without the prior written explicit consent of the Company. The Participant acknowledges that the foregoing information is not generally known, is highly confidential and constitutes trade secrets or confidential information of the Company. The Participant shall take reasonable precautions to protect the inadvertent disclosure of information.

The foregoing shall not apply to information that the Participant is required to disclose by applicable law, regulation, or legal process (provided that the Participant provides the Company with prior notice of the contemplated disclosure and cooperates with the Company at its expense in seeking a protective order or other appropriate protection of such information). Notwithstanding the foregoing, nothing in this Agreement prohibits the Participant from reporting possible violations of federal, state or local law or regulation to any government agency or entity, filing a charge with or participating in an investigation conducted by any government agency or entity, or making other disclosures that are protected under whistleblower provisions of law.  The Participant does not need prior authorization to make such reports or disclosures and is not required to notify the Company that the Participant has made any such report or disclosure. The Company does not waive confidentiality or any applicable privilege.

(D)    Non-Disparagement. During employment and thereafter, the Participant shall not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise malign the business reputation of, the Company, its affiliates or any of their respective officers, directors, managers, employees or partners.

(E)    Voluntary Resignation. If (a) the Participant voluntarily resigns without Good Reason (and not due to a Qualifying Retirement) within three years following the Grant Date and (b) the Company elects to enforce the covenants in Paragraph 7(A), then the Company agrees, as further consideration for such covenants, to continue to pay the Participant his or her base salary (at the rate in effect at the time of the Participant’s voluntary resignation) in accordance with the Company’s regular payroll dates for one year following the date of voluntary resignation. The payment of the Participant’s base salary in accordance with this Paragraph 7(E) will begin on the first payroll after the 60th day following the Participant’s voluntary resignation (with the first payment including the aggregate amount that would have been paid in the first sixty (60) days) subject to the Participant’s execution and delivery to the Company (and non-revocation) of a Release Agreement that becomes fully effective and irrevocable within fifty-five (55) days following the date of voluntary resignation. If a Release Agreement is not timely executed and delivered to the Company by the Participant, or if such Release Agreement is timely executed and delivered but is subsequently revoked by the

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Participant, then the Participant will not be entitled to the base salary continuation set forth in this Paragraph 7(E). The Participant agrees to promptly notify the Company of the date on which the Participant begins employment with a new employer in compliance with this Paragraph 7 (the “Commencement Date”) within 12 months following the Participant’s voluntary resignation. The Company will not have any obligation to pay the Participant’s base salary in accordance with this Paragraph 7(E) after the Commencement Date.

(F)    Participant Acknowledgements.

(i)    The Participant agrees that the restrictions in this Paragraph 7 are reasonable in light of the scope of the Company’s business operations, the Participant’s position within the Company, the interests which the Company seeks to protect, and the consideration provided to the Participant. The Participant agrees that these restrictions go only so far as to protect the Company’s business and business interests, and that those interests are worth protecting for the continued success, viability, and goodwill of the Company.

(ii)    The Participant expressly acknowledges that any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7 may result in substantial, continuing, and irreparable injury to the Company and its subsidiaries and affiliates for which monetary damages alone would not be a sufficient remedy. Therefore, the Participant hereby agrees that, in addition to any other remedy that may be available to the Company (including pursuant to Paragraph 9), in the event of any breach or threatened breach of any of the terms and/or conditions set forth in this Paragraph 7, the Company shall be entitled to injunctive relief, specific performance or other equitable relief by a court of appropriate jurisdiction, without the requirement of posting bond or the necessity of proving irreparable harm or injury as a result of such breach or threatened breach. Without limitation on the Company’s rights under the foregoing sentence or under Paragraph 9, (a) in the event of any actual breach of any of the terms and/or conditions set forth in Paragraph 7(A) or 7(B) during the term of such covenants, or (b) in the event of any actual breach of any of the terms and/or conditions set forth in Paragraphs 7(C) or (D) of this Agreement prior to the first anniversary of the date on which the Participant’s employment terminates for any reason: (i) if the Award is unvested, then the Award will immediately be forfeited for no consideration; (ii) the Company will cease to be obligated to furnish the Participant any further payments or deliveries pursuant to this Agreement; and (iii) the Participant shall promptly repay to the Company an amount equal to the gain realized in respect of this Award within the three preceding years (which gain shall be deemed to be an amount equal to the aggregate (x) cash amount and (y) with respect to Shares, the Fair Market Value on the date on which the Award is settled delivered to the Participant under this Award within such three-year period); provided that the foregoing repayment obligations, and the cessation of further payments and benefits, shall be without prejudice to the Company’s other rights.

(iii)    Notwithstanding any other provision to the contrary, the Participant acknowledges and agrees that the restrictions set forth in this Paragraph 7, as applicable, shall be tolled during any period of violation of any of the covenants therein and during any other period required for litigation during which the Company seeks to enforce such covenants against the Participant.

8.    Cooperation. Following the termination of the Participant’s employment with the Company for any reason, the Participant agrees (i) to reasonably cooperate with the Company and its directors, officers, attorneys and experts, and take all actions the Company may reasonably request, including but not limited to cooperation with respect to any investigation, government inquiry, administrative proceeding or litigation relating to any matter in which the Participant was involved or had knowledge during the Participant’s employment with the Company and (ii) that, if called upon by the Company, the Participant will provide assistance with respect to business, personnel or other matters which arose during the Participant’s employment with the Company or as to which the Participant has relevant information,

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knowledge or expertise, with such cooperation including, but not limited to, completing job tasks in progress, transitioning job tasks to other Company personnel, responding to questions and being available for such purposes. Any cooperation requests shall take into account the Participant’s personal and business commitments, and the Participant shall be reasonably compensated for the Participant’s time (if appropriate for the matter) and further reimbursed for any documented expenses (including reasonable attorney’s fees) incurred in connection with such cooperation within thirty (30) days of the Participant providing an invoice to the Company.

9.    Forfeiture/Clawback.

(A)    The delivery of Shares or cash under this Award is subject to any policy (whether in existence as of the Grant Date or later adopted) established by the Company or required by applicable law providing for clawback or recovery of amounts that were paid to the Participant. The Company will make any determination for clawback or recovery in its sole discretion and in accordance with any applicable law or regulation.

(B)    In addition to Paragraph 9(A) and notwithstanding anything to the contrary in this Agreement, if the Board or Committee determines that (i) any material misstatement of financial results has occurred as a result of the Participant’s conduct or (ii) the Participant has, without the consent of the Company, violated a non-competition, non-solicitation or non-disclosure covenant (including the covenants in Paragraph 7) between the Participant and the Company or any Affiliate, then the Board or Committee may in its sole discretion (a) determine that all or any portion of any unvested PSUs shall be forfeited for no consideration and/or (b) require the Participant to promptly repay to the Company any gain realized in respect of this Award within the three years preceding the date on which the Board or Committee determines that any of the events described in prongs (i) and (ii) above has occurred (which gain shall be deemed to be an amount equal to the aggregate (x) cash amount and (y) with respect to Shares, the Fair Market Value, on the date on which the Award is settled delivered to the Participant under this Award within such three-year period). Unless otherwise required by law, the provisions of this Paragraph 9(B) shall apply during the Participant’s employment with the Company and/or its Affiliates and for one year following the Participant’s termination of employment for any reason. The foregoing forfeiture and repayment obligations shall be without prejudice to any other rights that the Company may have.

10.    Effect of the Plan.This Award is subject to all of the provisions of the Plan and this Agreement, together with all of the rules and determinations from time to time issued by the Committee and/or the Board pursuant to the Plan, including the restrictions in the Plan on the transferability of awards. In the event of a conflict between any provision of the Plan and this Agreement, the provisions of this Agreement shall control but only to the extent such conflict is permitted under the Plan. By accepting this Award, the Participant acknowledges that he or she has received a copy of the Plan and agrees that the Participant will enter into such written representations, warranties and agreements and execute such documents as the Company may reasonably request in order to comply with applicable securities and other applicable laws, rules or regulations, or with this document or the terms of the Plan, the Severance Plan or the Cheniere Retirement Plan, as applicable.

11.    Amendment and Termination; Waiver. This Agreement, together with the Plan, constitutes the entire agreement by the Participant and the Company with respect to the subject matter hereof, and supersedes any and all prior agreements or understandings between the Participant and the Company with respect to the subject matter hereof, whether written or oral. This Agreement may not be amended or terminated by the Company in a manner that would be materially adverse to the Participant without the written consent of the Participant, provided that the Company may amend this Agreement unilaterally (a) as provided in the Plan or (b) if the Company determines that an amendment is necessary to comply with applicable law (including the requirements of the Code). Any provision for the benefit of the Company contained in this Agreement may be waived in writing, either generally or in any particular

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instance, by the Company. A waiver on one occasion shall not be deemed to be a waiver of the same or any other breach on a future occasion.

12.    Unsecured Obligation. The Company’s obligation under this Agreement shall be an unfunded and unsecured promise. The Participant’s right to receive the payments and benefits contemplated hereby from the Company under this Agreement shall be no greater than the right of any unsecured general creditor of the Company, and the Participant shall not have nor acquire any legal or equitable right, interest or claim in or to any property or assets of the Company. Nothing contained in this Agreement, and no action taken pursuant to its provisions, will create or be construed to create a trust of any kind or a fiduciary relationship between the Participant and the Company or any other person.

13.    No Right To Continued Employment. Neither this Award nor anything in this Agreement shall confer upon the Participant any right to continued employment with the Company (or its Affiliates or their respective successors) or shall interfere in any way with the right of the Company (or its Affiliates or their respective successors) to terminate the Participant’s employment at any time.

14.    Tax Matters; No Guarantee of Tax Consequences. This Agreement is intended to be exempt from, or to comply with, the requirements of Section 409A of the Code and this Agreement shall be interpreted accordingly; provided that in no event whatsoever shall the Company or any of its Affiliates be liable for any additional tax, interest or penalties that may be imposed on the Participant by Section 409A of the Code or any damages for failing to comply with Section 409A of the Code. Each payment under this Agreement will be treated as a separate payment for purposes of Section 409A of the Code. The Company makes no commitment or guarantee to the Participant that any federal or state tax treatment will apply or be available to any person eligible for benefits under this Agreement.

15.    Governing Law. This Agreement shall be construed in accordance with and governed by the laws of the State of Texas to the extent federal law does not supersede and preempt Texas law (in which case such federal law shall apply).

16.    Severability; Interpretive Matters. In the event that any provision of this Agreement shall be held illegal, invalid, or unenforceable for any reason, such provision shall be fully severable, but shall not affect the remaining provisions of this Agreement, and this Agreement shall be construed and enforced as if the illegal, invalid, or unenforceable provision had never been included herein. Whenever required by the context, pronouns and any variation thereof shall be deemed to refer to the masculine, feminine, or neuter, and the singular shall include the plural and vice versa. The terms “includes” or “including” in this Agreement shall be construed as “including without limitation”, so that terms following “includes” or “including” are not exhaustive. The captions and headings used in this Agreement are inserted for convenience and shall not be deemed a part of this Agreement granted hereunder for construction or interpretation. The Parties hereby irrevocably submit to the exclusive jurisdiction of the applicable state or federal courts located in Harris County, Texas.

17.    Counterparts. This Agreement may be signed in any number of counterparts, each of which will be an original, with the same force and effect as if the signature thereto and hereto were upon the same instrument.

[Remainder of Page Blank – Signature Page Follows]

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the Grant Date indicated below.

COMPANY:
CHENIERE ENERGY, INC.
By:
	Name:
	Title:

I hereby accept the Award subject to all of the terms and provisions hereof. I acknowledge and agree that the Award shall vest and become payable, if at all, only during the period of my continued service with the Company or as otherwise provided in this Agreement (not through the act of issuing the Award).

PARTICIPANT:
By:
	Name:

Grant Date:

[Signature Page – Performance Stock Unit Award under 2020 Incentive Plan]

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EX-10.9

Exhibit 10.9

AMENDED AND RESTATED
CHENIERE ENERGY, INC.
KEY EXECUTIVE
SEVERANCE PAY PLAN
(EFFECTIVE AS OF NOVEMBER 17, 2023)
AND SUMMARY PLAN DESCRIPTION

SECTION 1
PURPOSE

The purpose of the Plan is to provide Severance Benefits to each Executive whose employment is terminated as a result of a Qualifying Termination and Change in Control Benefits to each Executive upon a Change in Control, as applicable. The Plan is not intended to provide Severance Benefits to any individual who is not an Executive and who does not suffer a Qualifying Termination. The Plan, as a “severance pay arrangement” as defined in Section 3(2)(B)(i) of ERISA, is intended to be and shall be administered and maintained as an unfunded welfare benefit plan under Section 3(1) of ERISA. The Plan is intended to be a “top hat” plan under ERISA. The document serves as both the formal Plan document and the summary plan description. The Plan originally became effective on January 1, 2017. This amendment and restatement of the Plan is effective November 17, 2023.

SECTION 2
DEFINITIONS

For purposes of the Plan, the following terms shall have the following meanings:

2.1    Affiliate” shall mean a corporation or other entity that, directly or through one or more intermediaries, controls, is controlled by or is under common control with, the Company.

2.2    “Annual Base Pay” shall mean, as it relates to any Executive, such Executive’s gross annual base salary as reflected in the Company’s records and as in effect immediately prior to the Qualifying Termination.

2.3    “Annual Bonus” shall mean the amount of the Executive’s annual cash bonus for the applicable calendar year.

2.4    “Board” shall mean the Board of Directors of the Company.

2.5    “Cause” shall mean, with respect to an Executive, that such Executive experiences a Termination as a result of any of the following:

(a)    the willful commission by the Executive of a crime or other act of misconduct that causes or is likely to cause substantial economic damage to the Company or an Affiliate or substantial injury to the business reputation of the Company or an Affiliate;

(b)    the commission by the Executive of an act of fraud in the performance of the Executive’s duties on behalf of the Company or an Affiliate;

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(c)    the willful and material violation by the Executive of the Company’s Code of Business Conduct and Ethics Policy; or

(d)    the continuing and repeated failure of the Executive to perform his or her duties to the Company or an Affiliate, including by reason of the Executive’s habitual absenteeism (other than such failure resulting from the Executive’s incapacity due to physical or mental illness), which failure has continued for a period of at least thirty (30) days following delivery of a written demand for substantial performance to the Executive by the Board (or any individual designated such authority by the Board or otherwise) which specifically identifies the manner in which the Board (or any individual designated such authority by the Board or otherwise) believes that the Executive has not performed his or her duties;

provided, however, that, notwithstanding anything to the contrary in this Plan, for purposes of determining whether “Cause” exists under this Plan, no act, or failure to act, on the part of the Executive shall be considered “willful” unless done or omitted to be done by the Executive not in good faith and without reasonable belief that the Executive’s action or omission was in the best interest of the Company or an Affiliate, as the case may be.

The determination of whether Cause exists with respect to an Executive shall be made by the Board (or any individual designated such authority by the Board or otherwise) in its sole discretion.

2.6    “Change in Control” shall mean the occurrence of any one of the following events:

(a)    any “person” (as defined in Section 3(a)(9) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and as modified in Section 13(d) and 14(d) of the Exchange Act) other than (A) the Company or any Affiliate, (B) any employee benefit plan of the Company or of any Affiliate, (C) an entity owned, directly or indirectly, by stockholders of the Company in substantially the same proportions as their ownership of the Company, or (D) an underwriter temporarily holding securities pursuant to an offering of such securities (a “Person”), becomes the “beneficial owner” (as defined in Rule 13d-3(a) of the Exchange Act), directly or indirectly, of securities of the Company representing 50.1% or more of the shares of voting stock of the Company then outstanding; or

(b)    the consummation of any merger, organization, business combination or consolidation of the Company with or into any other company, other than a merger, reorganization, business combination or consolidation which would result in the holders of the voting securities of the Company outstanding immediately prior thereto holding securities which represent immediately after such merger, reorganization, business combination or consolidation more than 50% of the combined voting power of the voting securities of the Company or the surviving company or the parent of such surviving company; or

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(c)    the consummation of a sale or disposition by the Company of all or substantially all of the Company’s assets, other than a sale or disposition if the holders of the voting securities of the Company outstanding immediately prior thereto hold securities immediately thereafter which represent more than 50% of the combined voting power of the voting securities of the acquiror, or parent of the acquiror, of such assets, or the stockholders of the Company approve a plan of complete liquidation or dissolution of the Company; or

(d)    individuals who, as of the Effective Date, constitute the Board (the “Incumbent Board”) cease for any reason to constitute at least a majority of the Board; provided, however, that any individual becoming a director subsequent to the date of this Plan whose nomination by the Board was approved by a vote of at least a majority of the directors then comprising the Incumbent Board shall be considered as though such individual were a member of the Incumbent Board, but excluding, for this purpose, any such individual whose initial assumption of office occurs as a result of an election contest or threatened election contest with respect to the election or removal of directors or other solicitation of proxies or consents by or on behalf of a person other than the Board.

Notwithstanding the foregoing, a Change in Control shall not occur or be deemed to occur if any event set forth in subsections (a) - (d) above, that would otherwise constitute a Change in Control occurs as a direct result of the consummation of a transaction solely between the Company and one or more of its controlled Affiliates.

Notwithstanding the foregoing, however, in any circumstance or transaction in which compensation payable pursuant to this Plan would be subject to the income tax under the Section 409A Rules if the foregoing definition of “Change in Control” were to apply, but would not be so subject if the term “Change in Control” were defined herein to mean a “change in control event” within the meaning of Treasury Regulation § 1.409A-3(i)(5), then “Change in Control” means, but only to the extent necessary to prevent such compensation from becoming subject to the income tax under the Section 409A Rules, a transaction or circumstance that satisfies the requirements of both (1) a Change in Control under the applicable clause (a) through (d) above, and (2) a “change in control event” within the meaning of Treasury Regulation Section § 1.409A-3(i)(5).

2.7“Change in Control Benefit” shall mean the acceleration of vesting of outstanding Incentive Awards that may become available under Section 3.2.

2.8“COBRA” shall mean Section 4980B of the Code and Part 6 of Subtitle B of Title I of ERISA.

2.9“Code” shall mean the Internal Revenue Code of 1986, as amended, and the regulations and administrative guidance promulgated thereunder.

2.10“Company” shall mean Cheniere Energy, Inc.

2.11“Continued Benefits” shall mean the continuation of subsidized health benefits to be provided in a manner as determined by the Plan Administrator in its sole discretion.

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2.12“Effective Date” shall mean the original effective date of this Plan, January 1, 2017.

2.13“Employer” shall mean, as it relates to any Executive on any date, the Company or Related Employer that employs the Executive on such date.

2.14“ERISA” shall mean the Employee Retirement Income Security Act of 1974, as amended, and the regulations and administrative guidance promulgated thereunder.

2.15“Executive” shall mean an individual who is (i) a common law U.S.-based employee of the Company or of a Related Employer and (ii) an executive or vice president of the Company or of a Related Employer (except where specifically further defined herein).

2.16“Executive Multiplier” shall mean:

(a)in the case of a Qualifying Termination not during the Protection Period, (i) two (2), with respect to the Chief Executive Officer of the Company, (ii) one and one-half (1.5), with respect to any Executive (A) that reports directly to the Chief Executive Officer of the Company or (B) is otherwise a senior vice president of or an executive vice president of the Company or such other equivalent thereof (including, by way of example, the General Counsel of the Company) and also an officer of the Company, and (iii) one (1), with respect to an Executive not covered under either clause (i) or (ii) hereof; and

(b)in the case of a Qualifying Termination during the Protection Period, (i) three (3), with respect to the Chief Executive Officer of the Company, (ii) two (2), with respect to any Executive (A) that reports directly to the Chief Executive Officer or (B) is otherwise a senior vice president of or an executive vice president of the Company or such other equivalent thereof (including, by way of example, the General Counsel of the Company) and also an officer of the Company, and (iii) one and one-half (1.5), with respect to an Executive not covered under either clause (i) or (ii) hereof.

2.17“Good Reason” shall mean as to any Executive,

(a)Prior to a Change in Control, the occurrence of any of the following events or conditions:

(i)a material diminution in the Executive’s (applicable to senior vice president and executive vice president of the Company and above only) authority, duties, or responsibilities with the Company or the applicable Related Employer, (excluding, for the avoidance of doubt, a vice president from this subsection (a)(i));

(ii)a reduction by the Company or the applicable Related Employer in the Executive’s Annual Base Pay of more than five percent (5%) (other than a reduction that is part of reductions in Annual Base Pay for Executives generally); or

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(iii)the requirement by the Company or the applicable Related Employer that the principal place of business at which the Executive performs his or her duties be permanently changed to a location more than fifty (50) miles from his or her then current principal place of business.

(b)Upon or following a Change in Control, the occurrence of any of the following events or conditions:

(i)a change in the Executive’s status, title, position or responsibilities, including reporting responsibilities which represents a substantial reduction of his or her status, title, position or responsibilities as in effect immediately prior thereto;

(ii)the removal from or failure to re-elect the Executive to the office or position in which he or she last served, unless such removal or failure to re-elect is by reason of removal or failure to re-elect (I) for Cause, (II) as a result of the Executive’s death or disability, or (III) voluntary resignation by or request for removal by the Executive from such office or position;

(iii)the assignment to the Executive of any duties, responsibilities, or reporting requirements which are materially adverse with his or her position with the Company or the applicable Related Employer, or any material diminishment, on a cumulative basis, of the Executive’s overall duties, responsibilities, or status;

(iv)a material reduction by the Company or the applicable Related Employer in the Executive’s Annual Base Pay; or

(v)the requirement by the Company or the applicable Related Employer that the principal place of business at which the Executive performs his or her duties be changed to a location more than fifty (50) miles from his or her then current principal place of business.

Notwithstanding any of the foregoing, an Executive cannot terminate his or her employment for Good Reason unless he or she has provided written notice to the Company of the existence of the circumstances alleged to constitute Good Reason within thirty (30) days of the initial existence of such circumstances and the Company has had at least thirty (30) days from the date on which such notice is provided to cure such circumstances. In the event the Company does not timely cure such circumstances and if the Executive does not terminate his or her employment for Good Reason within ninety (90) days after the first occurrence of the applicable circumstances, then the Executive will be deemed to have waived his or her right to terminate for Good Reason with respect to such circumstances.

2.18“Incentive Award” shall mean (a) any equity award (other than a new hire award), equity-based award (including any such equity-based award settled in cash) (other than a new hire award), and annual award, in each case granted on or after the Effective Date and (b) any new hire award and retention award, regardless of the grant date, in all cases granted pursuant to a Company plan, arrangement or agreement.

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2.19“Lookback Period” shall mean the three (3)-month portion of the Protection Period that precedes the Change in Control.

2.20“Plan” shall mean the Cheniere Energy, Inc. Key Executive Severance Pay Plan, as the same may be amended or amended and restated from time to time.

2.21“Plan Administrator” shall mean the Company or such person or committee appointed thereby to administer the Plan.

2.22“Plan Year” shall mean the calendar year.

2.23“Prorated Target Bonus Amount” means the Executive’s Target Bonus, if any, for the year in which the Qualifying Termination occurs multiplied by a fraction, the numerator of which is the number of days during such year that have elapsed prior to such Qualifying Termination and the denominator of which is 365.

2.24“Protection Period” shall mean the period beginning three (3) months prior to a Change in Control and ending two (2) years after such Change in Control.

2.25“Qualifying Termination” shall mean the Termination of an Executive either (a) by the Company or, if applicable, the Employer, in either case without Cause at a time when the Executive is otherwise willing and able to continue in employment or (b) by the Executive for Good Reason. In no event shall a Termination of an Executive as a result of (w) such Executive’s death, (x) such Executive’s disability, (y) Termination by the Company or a Related Employer of such Executive for Cause, or (z) Termination by the Executive other than for Good Reason constitute a Qualifying Termination.

2.26“Related Employer” shall mean (a) an Affiliate that is a member of a controlled group of corporations (as defined in section 414(b) of the Code) that includes the Company, (b) an Affiliate (whether or not incorporated) that is in common control (as defined in section 414(c) of the Code) with the Company, or (c) an Affiliate that is a member of the same affiliated service group (as defined in section 414(m) of the Code) as the Company.

2.27“Release Agreement” shall mean the agreement which an Executive must execute in order to receive Change in Control or Severance Benefits under the Plan which shall be in a form similar to that attached as Exhibit A hereto and acceptable to the Company.

2.28“Section 409A Rules” shall mean Section 409A of the Code and the regulations and administrative guidance promulgated thereunder.

2.29“Severance Benefits” shall mean (a) the Severance Pay, (b) the Continued Benefits, (c) the treatment of outstanding Incentive Awards that may become available under Section 5.5, (d) the Prorated Target Bonus Amount, (e) the amount of the Executive’s unpaid Annual Bonus (if any) for the year prior to the year in which the Qualifying Termination occurs to the extent earned based on actual performance achieved and (f) such outplacement services (if any) as may be provided or made available under Section 5.6.

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2.30“Severance Pay” shall mean, with respect to an applicable Executive, an amount equal to the product of (a) the Executive’s Executive Multiplier multiplied by (b) the sum of such Executive’s (i) Annual Base Pay plus (ii) full amount of the Executive’s Target Bonus for the year of the Qualifying Termination.

2.31“Target Bonus” shall mean the amount of the Executive’s “target” annual cash bonus for the applicable year.

2.32“Termination” shall mean a “separation from service” as defined in the Section 409A Rules of an Executive with respect to the Company and its Affiliates and which separation both the Employer and Executive reasonably believe to be permanent.

2.33“Termination Date” shall mean the date the applicable Executive experiences a Termination.

SECTION 3

CHANGE IN CONTROL BENEFIT

3.1Eligibility for Change in Control Benefit

Subject to the terms and conditions of the Plan, an Executive will become entitled to the Change in Control Benefit under the Plan only if he or she remains continuously employed with the Company and the Related Employers from the date of his or her commencement of participation in the Plan through the date of a Change in Control.

3.2Treatment of Outstanding Incentive Awards

(a)    Subject to the terms of the Plan and, except as otherwise provided in this Section 3.2, notwithstanding the terms of any Company plan or award agreement thereunder or other agreement or arrangement to the contrary, with respect to each Executive eligible for the Change in Control Benefit, such Executive shall be entitled to:

(i)    all of the Executive’s outstanding unvested time-based Incentive Awards will automatically vest in full as of the date of the Change in Control,

(ii)    the Executive’s outstanding unvested performance-based Incentive Awards that vest based on total shareholder return (“TSR”) will vest as of the date of the Change in Control based on actual TSR as of the date of the Change in Control, and

(iii)    the Executive’s outstanding unvested performance-based Incentive Awards that vest based on performance metrics other than TSR will vest as of the date of the Change in Control based on the greater of (x) target level for such Incentive Awards or (y) actual performance for such Incentive Awards, determined by (A) shortening the performance period to end on the date of the Change of Control, (B) adjusting the applicable performance metrics as necessary and appropriate based on the shortened performance period, and (C) determining

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the level of achievement of such performance metrics based on such shortened performance period.

(b)    Notwithstanding anything in this Section 3.2 to the contrary, to the extent an applicable Incentive Award agreement, plan or similar agreement governing an Executive’s outstanding Incentive Awards provides for more favorable treatment of such awards, the terms of such Incentive Award agreement, plan or similar agreement shall control with respect thereto.

3.3Requirement for Release Agreement

No Change in Control Benefit will be provided to an Executive unless that Executive, in the sole determination of the Plan Administrator, has properly executed and delivered to the Company a Release Agreement and such Release Agreement has become irrevocable as provided therein within fifty-five (55) days following the date of the Change in Control. To be “properly executed,” such Release Agreement must (among other requirements the Plan Administrator may establish) be executed on or after the date of the Change in Control.

3.4Settlement of Vested Incentive Awards

Subject to the terms and conditions of the Plan, an Executive’s outstanding Incentive Awards vesting pursuant to Section 3.2 shall be settled as soon as administratively practicable following the expiration of the period during which the Executive may revoke the Release Agreement pursuant to the terms of the Release Agreement, but in all events no later than the end of the sixtieth (60th) day following the date of the Change in Control; provided, however, that if such sixty (60)-day period begins in one taxable year and ends in a subsequent taxable year, the outstanding Incentive Awards vesting pursuant to Section 3.2 will in all events be settled in such subsequent taxable year. Notwithstanding the immediately preceding sentence, if any outstanding Incentive Award the vesting of which accelerates pursuant to Section 3.2 is required to comply with the Section 409A Rules or is subject to Section 83 of the Code, the settlement date thereof shall be such date as required by the applicable Incentive Award agreement or plan.

SECTION 4
ENTITLEMENT TO SEVERANCE BENEFITS

4.1Eligibility for Severance Benefits

Subject to the terms and conditions of the Plan, an Executive will become entitled to Severance Benefits under the Plan only if he or she experiences a Qualifying Termination. An Executive shall not be entitled to Severance Benefits if he or she does not experience a Qualifying Termination.

4.2Death of an Executive

If an Executive whose employment terminates in a Qualifying Termination dies after his or her Termination Date but before the Executive receives the Severance Benefits to which he or she is entitled, the Severance Benefits will be paid to the Executive’s surviving spouse as then reflected in the Company’s records or, if the Executive does not have a surviving spouse so

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reflected in the Company’s records, to the Executive’s estate. In the event the Release Agreement with respect to a deceased Executive has not become final by such Executive’s date of death, then the Executive’s surviving spouse or estate, as applicable, must timely execute, deliver and not revoke the Release Agreement.

4.3Requirement for Release Agreement

No Severance Benefits will be paid to any Executive unless that Executive, in the sole determination of the Plan Administrator, has properly executed and delivered to the Company a Release Agreement and such Release Agreement has become irrevocable as provided therein within fifty-five (55) days following the date of the Qualifying Termination. To be “properly executed,” such Release Agreement must (among other requirements the Plan Administrator may establish) be executed on or after the Executive’s Termination Date.

SECTION 5

SEVERANCE BENEFITS

5.1Form and Time of Payment of Severance Pay

Subject to the terms and conditions of the Plan, Severance Pay shall be paid in a lump sum in cash. Severance Pay shall be paid as soon as administratively practicable following the expiration of the period during which the Executive may revoke the Release Agreement pursuant to the terms of the Release Agreement, but in all events no later than the sixtieth (60th) day following the date of the Qualifying Termination (such sixty (60)-day period, the “Severance Pay Period”); provided, however, that if the Severance Pay Period begins in one taxable year and ends in a subsequent taxable year, the Severance Pay will in all events be paid in such subsequent taxable year. The Severance Pay payable to any Executive shall be solely the obligation of the Employer by whom the Executive was employed on his or her Termination Date.

5.2Reduction of Severance Pay to Avoid Duplication

(a)If an Executive is a party to an employment, severance, termination, change of control, salary continuation or other similar agreement with the Company or any Affiliate, or is a participant in any other severance plan, practice or policy of the Company or any Affiliate, the Severance Pay to which the Executive may be entitled under this Plan shall be reduced (but not below zero) by the amount of severance, termination, change of control, salary continuation or other similar pay to which he or she may be entitled under such other agreement, plan, practice or policy (provided that any such reduction shall not take into account the value of any acceleration of vesting of such Executive’s outstanding awards under Company equity plans); provided, that the reduction set forth in this sentence shall not apply as to any such other agreement, plan, practice or policy which contains a reduction provision substantially similar to this sentence, so long as the Plan Administrator establishes to its satisfaction that the reduction provision of such other agreement, plan, practice or policy shall be applied. The Severance Pay to which an Executive is otherwise entitled shall be further reduced (but not below zero) by any payments and benefits to which the Executive may be

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entitled under any federal, state or local plant-closing (or similar or analogous) law (including, but not limited to, entitlement to pay and continued employee benefits (or the cash value of either of the foregoing) pursuant to the Worker Adjustment and Retraining Notification Act, as amended).

(b)To the extent permitted by applicable law, including applicable restrictions on offsets under the Section 409A Rules, the Severance Pay to which any Executive is entitled may, in the sole discretion of the Plan Administrator, be reduced by the amount of any indebtedness of the Executive to the Company or any of its Affiliates, and the amount of any such reduction shall be applied as a repayment or forgiveness of such indebtedness to such extent.

5.3Prorated Target Bonus Amount

(a)Subject to the terms and conditions of the Plan, with respect to each Executive whose Termination entitles him or her to Severance Pay, such Executive shall receive his or her Prorated Target Bonus Amount.

(b)Subject to the terms and conditions of the Plan, an Executive’s Prorated Target Bonus Amount shall be paid in a lump sum in cash as soon as administratively practicable following the expiration of the period during which the Executive may revoke the Release Agreement pursuant to the terms of the Release Agreement, but in all events no later than the end of the Severance Pay Period; provided, however, that if the Severance Pay Period begins in one taxable year and ends in a subsequent taxable year, the Prorated Target Bonus will in all events be paid in such subsequent taxable year. The Prorated Target Bonus payable to any Executive shall be solely the obligation of the Employer by whom the Executive was employed on his or her Termination Date.

5.4Continued Benefits

Subject to the terms and conditions of the Plan, with respect to each Executive whose Termination entitles him or her to Severance Pay, such Executive shall receive, subject to timely election pursuant to COBRA and remaining eligible therefor, if applicable, Continued Benefits equal to (a) with respect to the Chief Executive Officer of the Company and (i) any Executive that directly reports to the Chief Executive Officer or (ii) is otherwise a senior vice president of or an executive vice president of the Company or such other equivalent thereof (including, by way of example, the General Counsel of the Company) and also an officer of the Company or an Affiliate, twenty-four (24) months of Continued Benefits and (b) with respect to all other Executives, twelve (12) months of Continued Benefits. In the event an Executive ceases to be eligible to continue coverage under the Company’s group health plans pursuant to COBRA other than as a result of failure to make a timely election therefor or of obtaining new employment that makes available employer-provided health benefits, the Company shall pay to such Executive, on a monthly basis for the remainder of the period that the Continued Benefits would have remained in effect had such COBRA eligibility not ceased, a monthly amount equal to the amount of the health care premiums the Company was paying or causing to be waived on behalf of Executive immediately prior to such loss of eligibility. In the event an Executive ceases, following his or her Termination, to be eligible for the Continued Benefits pursuant to the first sentence of this

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Section 5.4, such Executive shall promptly inform the Company in writing of such ineligibility. Notwithstanding any of the foregoing, the Company may modify the Continued Benefits provided by this Section 5.4 to the extent reasonably necessary to avoid the imposition of any excise taxes or other penalties on the Company or any of its Affiliates for failure to comply with the requirements of the Patient Protection and Affordable Care Act of 2010, as amended, and/or the Health Care and Education Reconciliation Act of 2010, as amended.

5.5Treatment of Outstanding Incentive Awards

(a)Subject to the terms and conditions of the Plan, with respect to each Executive whose Termination entitles him or her to Severance Pay, such Executive shall be entitled to:

(i)in the event of a Qualifying Termination of an Executive (including the President and Chief Executive Officer but excluding any executive vice president of the Company, whose awards are instead subject to Section 5.5(b)) not during the Protection Period,

(A)with respect to the Executive’s outstanding unvested time-based Incentive Awards, (I) subject to Section 5.5(a)(iii), such Incentive Awards that were granted within the six (6) month period immediately preceding the Qualifying Termination will be automatically forfeited for no consideration, and (II) subject to subclause (I) hereof, all of the Executive’s outstanding unvested time-based Incentive Awards will automatically vest, and

(B)with respect to the Executive’s outstanding unvested performance-based Incentive Awards, (I) subject to Section 5.5(a)(iii), such Incentive Awards that were granted within the six (6) month period immediately preceding the Qualifying Termination will be automatically forfeited for no consideration, and (II) subject to subclause (I) hereof, (1) each of the Executive’s outstanding unvested performance-based Incentive Awards shall remain outstanding with respect to the portion of such Incentive Award multiplied by a fraction (not to exceed 1), the numerator of which is the whole number of months elapsed during the applicable performance period the Executive was employed (or, if longer, during the service vesting period the Executive was employed), and the denominator of which is the whole number of months in the performance period (or, if longer, in the service vesting period) with respect thereto, and (2) the portion of such performance-based Incentive Awards that remains outstanding following application of subclause (1) shall vest, if at all, upon completion of the applicable performance period based on actual performance levels achieved. For purposes of this Section 5.5, the service vesting period shall be the period from the grant date through the date on which (but for the termination-related vesting provisions in this Section 5.5 or otherwise) Executive is required to remain employed in order to vest in such Incentive Award; and

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(ii)in the event of a Qualifying Termination of an Executive during the Protection Period,

(A)all of the Executive’s outstanding unvested time-based Incentive Awards will automatically vest in full,

(B)the Executive’s outstanding unvested performance-based Incentive Awards that vest based on TSR will vest based on actual TSR as of the date of the Change in Control, and

(C)the Executive’s outstanding unvested performance-based Incentive Awards that vest based on performance metrics other than TSR will vest (1) in the case of Incentive Awards granted prior to the Change in Control, in accordance with Section 3.2(a)(iii) or (2) in the case of Incentive Awards granted after the Change in Control, based on the greater of (x) target level for such Incentive Awards as of the date of the Qualifying Termination or (y) actual performance for such Incentive Awards, determined by (A) shortening the performance period to end on the date of the Qualifying Termination, (B) adjusting the applicable performance metrics as necessary and appropriate based on the shortened performance period, and (C) determining the level of achievement of such performance metrics based on such shortened performance period.

(iii)Notwithstanding anything in this Section 5.5, the applicable provisions of the Executive’s Incentive Award agreements or the relevant plan governing such Incentive Awards to the contrary, if a Qualifying Termination occurs prior to a Change in Control, (A) no Incentive Awards that are unvested as of the Qualifying Termination (after taking into account vesting acceleration pursuant to Section 5.5(a)(i) or Section 5.5(b)) shall lapse or be forfeited solely on account of such Qualifying Termination; provided, however, if the Change in Control has not occurred within the 3-month period immediately following the Qualifying Termination thus resulting in such Qualifying Termination occurring outside the Protection Period, all such unvested Incentive Awards shall automatically lapse and be forfeited for no consideration at the end of such 3-month period and (B) with respect to performance-based Incentive Awards, if the applicable performance period ends after the Qualifying Termination but prior to a Change in Control and such Change in Control occurs within the 3-month period immediately following the Qualifying Termination, the Executive shall be entitled, with respect to such Incentive Award, to the greater of the amount resulting from the application of Section 5.5(a)(i)(B) or 5.5(b), as applicable and Section 5.5(a)(ii)(B) or (C), as applicable.

(b)Subject to the terms and conditions of the Plan, with respect to each Executive (1) who is an executive vice president of the Company and (2) whose Termination entitles him or her to Severance Pay, in the event of a Qualifying Termination not during the Protection Period:

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(i)all of the Executive’s outstanding unvested time-based Incentive Awards will automatically vest in full, and

(ii)with respect to the Executive’s outstanding unvested performance-based Incentive Awards, (1) each of the Executive’s outstanding unvested performance-based Incentive Awards shall remain outstanding with respect to the portion of such Incentive Award multiplied by a fraction (not to exceed 1), the numerator of which is the whole number of months elapsed during the applicable performance period the Executive was employed (or, if longer, during the service vesting period the Executive was employed), and the denominator of which is the whole number of months in the performance period (or, if longer, in the service vesting period) with respect thereto, and (2) the portion of such performance-based Incentive Awards that remains outstanding following application of subclause (1) shall vest, if at all, upon completion of the applicable performance period based on actual performance levels achieved. For purposes of this Section 5.5, the service vesting period shall be the period from the grant date through the date on which (but for the termination-related vesting provisions in this Section 5.5 or otherwise) Executive is required to remain employed in order to vest in such Incentive Award.

For the avoidance of doubt, the Incentive Awards held by each Executive (1) who is an executive vice president of the Company and (2) whose Termination entitles him or her to Severance Pay will be governed by Section 5.5(a)(ii) in the event of a Qualifying Termination of an Executive during the Protection Period

(c)Subject to the terms and conditions of the Plan, an Executive’s outstanding Incentive Awards vesting pursuant to Sections 5.5(a) and (b) shall be settled as soon as administratively practicable following the expiration of the period during which the Executive may revoke the Release Agreement pursuant to the terms of the Release Agreement, but in all events no later than the end of the Severance Pay Period; provided, however, that if the Severance Pay Period begins in one taxable year and ends in a subsequent taxable year, the outstanding Incentive Awards vesting pursuant to Sections 5.5(a) and (b) will in all events be settled in such subsequent taxable year. Notwithstanding the immediately preceding sentence, if any outstanding Incentive Awards the vesting of which accelerates pursuant to Sections 5.5(a) and (b) is required to comply with the Section 409A Rules or is subject to Section 83 of the Code, the settlement date thereof shall be such date as required by the applicable Incentive Award agreement or plan.

(d)Notwithstanding Sections 5.5(a) and (b), to the extent an applicable Incentive Award agreement, plan or similar agreement governing an Executive’s outstanding Incentive Awards provides for more favorable treatment of such awards, the terms of such Incentive Award agreement, plan or similar agreement shall control with respect thereto.

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5.6Outplacement Services

Subject to the terms and conditions of the Plan, with respect to each Executive whose Qualifying Termination entitles him or her to Severance Benefits, the Plan Administrator may, in its sole and absolute discretion, provide such Executive with outplacement services (or pay the costs associated with obtaining such outplacement services). The Plan Administrator shall determine, in its sole and absolute discretion, the period during which the Executive will be eligible to receive such outplacement services (if any) and the type, degree and length of such services, and in no event shall the Plan Administrator’s decision to provide outplacement services entitle or require any other Executive to such services.

5.7Qualifying Termination followed by Change in Control During the Lookback Period

Subject to the terms and conditions of the Plan, with respect to each Executive whose Termination entitles him or her to Severance Pay, if an Executive experiences a Qualifying Termination prior to a Change in Control, but a Change in Control subsequently occurs that results in the aforementioned Qualifying Termination having occurred during the Lookback Period, then any Severance Benefits not otherwise payable to the Executive as a result of a Qualifying Termination absent a Change in Control shall be payable as soon as administratively practicable following the date of the Change in Control, but in all events no later than the end of than the sixtieth (60th) day following the date of the Change in Control; provided, however, that if such sixty (60)-day period begins in one taxable year and ends in a subsequent taxable year, the applicable Severance Benefits payable pursuant to this Section 5.7 will in all events be paid in such subsequent taxable year.

5.8Repayment of Severance Pay in the Event of Rehire

In the event an Executive is rehired by the Company or an Affiliate thereof within twelve (12) months following such Executive’s Qualifying Termination, the Executive shall promptly repay to the Company an amount equal to the after-tax amount of the Severance Pay multiplied by a fraction, the numerator of which is the number of days since the date of the Qualifying Termination that remain in such twelve (12)-month period and the denominator of which is 365.

SECTION 6ADMINISTRATION, AMENDMENT AND TERMINATION

6.1Administration

(a)The Plan Administrator shall be administrator and “NamedFiduciary” (within the meaning of Section 402(a) of ERISA) of the Plan and shall have full authority to control and manage the operation and administration of the Plan, and to take all such action in respect of the Plan as it deems necessary or appropriate. By way of clarification and not limitation of the foregoing, the Plan Administrator will have the authority, in its sole and absolute discretion, to: (i) adopt, amend, and rescind administrative and interpretive rules and regulations related to the Plan, (ii) delegate its duties under the Plan to such persons, agents and committees as it may appoint from time to time, (iii) interpret the Plan’s provisions and construe its terms, (iv) determine

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eligibility for benefits under the Plan, including determining which Executive Multiplier shall apply to each Executive, (v) determine the entitlement to and the amount of benefits payable to any person pursuant to the Plan, (vi) determine any reduction to severance pursuant to Section 5.2 of this Plan, (vii) engage accountants, legal counsel and such other personnel as it deems necessary or advisable to assist it in the performance of its duties under the Plan and (viii) make all other determinations, perform all other acts and exercise all other powers and authority necessary or advisable for administering the Plan, including the delegation of those ministerial acts and responsibilities as the Plan Administrator deems appropriate. The Plan Administrator shall have complete discretion and authority with respect to the Plan and its application. The Plan Administrator may correct any defect, supply any omission, or reconcile any inconsistency in the Plan in any manner and to the extent it deems necessary or desirable to carry the Plan into effect, and the Plan Administrator will be the sole and final judge of that necessity or desirability. The determinations of the Plan Administrator on the matters referred to in this Section 6.1(a) will be final, conclusive and binding upon all persons claiming any interest in or under the Plan. Any determination made by the Plan Administrator shall be given deference in the event it is subject to judicial review and shall be overturned by a court of law only if it is arbitrary and capricious.

(b)The Plan Administrator may amend the Plan retroactively to cure any ambiguity in the language of the Plan. This Section 6.1(b) may not be invoked by any person to require the Plan to be interpreted in a manner which is inconsistent with its interpretation by the Plan Administrator. All actions and all determinations made by the Plan Administrator shall be final and binding upon all persons claiming any interest in or under the Plan.

6.2Amendment and Termination

(a)Subject to Section 6.2(b), the Company reserves the right to amend, terminate, suspend or otherwise modify all or any part of the Plan at any time, and from time to time, without the consent of or notice to any person.

(b)Neither the termination of the Plan nor any amendment or modification to the Plan by the Company or the Plan Administrator (if such authority is so delegated by the Company) may reduce the Severance Benefits which may be payable or provided under the Plan to any Executive whose Termination Date is on or prior to the effective date of such termination, amendment, modification or supplement.

(c)Notwithstanding the foregoing, no termination or amendment that adversely affects the rights or benefits hereunder of any Executive shall be applicable to such Executive if made within the twelve (12)-month period immediately preceding a Change in Control or the twenty-four (24)-month period beginning on the date of such Change in Control.

SECTION 7

GENERAL PROVISIONS

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7.1Unfunded Obligation

Severance Benefits under the Plan shall be an unfunded obligation of the Employer of such Executive and shall be payable only from such Employer’s general assets.

7.2Withholding

The Company or the Employer, as applicable, shall have the authority to withhold or cause to be withheld applicable taxes from payments made under this Plan with respect to payments made and benefits provided hereunder, to the extent determined applicable by the Company or Employer.

7.3No Guarantee of Tax Consequences

Neither the Company nor any Affiliate represents or guarantees that any particular federal, state, local, income, estate, payroll, personal property or other tax consequences will (or will not) occur with respect to Executives as a result of participation in this Plan and/or the receipt of Severance Benefits hereunder. Neither the Company nor any Affiliate assumes any liability or responsibility for the tax consequences hereunder to any Executive (or to any person, entity, trust or estate claiming through or on behalf of any Executive). Each Executive is solely responsible for obtaining appropriate advice regarding all questions of federal, state, local, income, estate, payroll, personal property and other tax consequences arising from participation in this Plan and the receipt of compensation or benefits hereunder.

7.4Section 409A Rules

(a)This Plan and the Severance Benefits provided hereunder are intended to comply with the Section 409A Rules or an exemption thereunder and shall be construed and administered in accordance therewith. For purposes of the Section 409A Rules, each installment payment provided under this Plan shall be treated as a separate payment.

(b)Notwithstanding any other provision of this Plan, if any payment or benefit provided to an Executive in connection with his or her Termination is determined to constitute “nonqualified deferred compensation” within the meaning of the Section 409A Rules and the Executive is determined to be a “specified employee” as defined in the Section 409A Rules, then such payment or benefit shall not be paid until the first payroll date to occur following the six (6)-month anniversary of the Termination Date (the “Specified Employee Payment Date”). The aggregate of any payments that would otherwise have been paid before the Specified Employee Payment Date shall be paid, without interest, to the Executive in a lump sum on the Specified Employee Payment Date and thereafter, any remaining payments shall be paid without delay in accordance with their original schedule.

(c)Any gross-up payment payable pursuant to this Plan shall be paid no later than the end of the applicable Executive’s taxable year next following the taxable year in which the Executive remits the related taxes.

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(d)To the extent required by the Section 409A Rules, each reimbursement or in-kind benefit provided under this Plan shall be provided in accordance with the following:

(i)the amount of expenses eligible for reimbursement, or in-kind benefits provided, during each calendar year cannot affect the expenses eligible for reimbursement, or in-kind benefits to be provided, in any other calendar year;

(ii)any reimbursement of an eligible expense shall be paid to the Executive on or before the last day of the calendar year following the calendar year in which the expense was incurred; and

(iii)any right to reimbursements or in-kind benefits under this Plan shall not be subject to liquidation or exchange for another benefit.

7.5Section 280G

(a)Notwithstanding any other provision of this Plan or any other plan, arrangement or agreement to the contrary, if any of the payments or benefits provided or to be provided by the Company or its Affiliates to an Executive or for an Executive’s benefit pursuant to the terms of this Plan or otherwise (“Covered Payments”) constitute parachute payments (“Parachute Payments”) within the meaning of Section 280G of the Code and would, but for this Section 7.5 be subject to the excise tax imposed under Section 4999 of the Code (or any successor provision thereto) or any similar tax imposed by state or local law or any interest or penalties with respect to such taxes (collectively, the “Excise Tax”), then prior to making the Covered Payments, a calculation shall be made comparing (i) the Net Benefit (as defined below) to the Executive of the Covered Payments after payment of the Excise Tax to (ii) the Net Benefit to the Executive if the Covered Payments are limited to the extent necessary to avoid being subject to the Excise Tax. Only if the amount calculated under (i) above is less than the amount under (ii) above will the Covered Payments be reduced to the minimum extent necessary to ensure that no portion of the Covered Payments is subject to the Excise Tax (that amount, the “Reduced Amount”). “Net Benefit” shall mean the present value of the Covered Payments net of all federal, state, local, foreign income, employment and excise taxes.

(b)Any such reduction shall be made in accordance with the Section 409A Rules and the following: (i) the Covered Payments that do not constitute nonqualified deferred compensation subject to the Section 409A Rules shall be reduced first; and (ii) all other Covered Payments shall then be reduced as follows: (A) cash payments shall be reduced before non-cash payments; and (B) payments to be made on a later payment date shall be reduced before payments to be made on an earlier payment date.

(c)Any determination required under this Section 7.5, including whether any payments or benefits are parachute payments, shall be made by the Company in its sole discretion. The Executive shall provide the Company with such information and documents as the Company may reasonably request in order to make a determination

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under this Section 7.5. The Company’s determination shall be final and binding on the Executive.

7.6Applicable Law

The Plan and all rights hereunder shall be governed and construed in accordance with applicable federal law and, to the extent not preempted by federal law, with the laws of the State of Texas, wherein venue shall lie for any dispute arising hereunder.

7.7Severability

If a court of competent jurisdiction holds any provision of the Plan invalid or unenforceable, the Plan shall be construed or enforced as if such provision had not been included herein, and the remaining provisions of the Plan shall continue to be fully effective.

7.8Employment at Will

Each Executive shall be an employee-at-will of the Executive’s Employer. No provision of the Plan shall be construed to constitute a contract of employment or impose on the Company or any Affiliate any obligation to (a) retain any Executive, (b) make any payments upon Termination (except as otherwise provided herein), (c) change the status of any Executive’s employment or (d) change any employment policies of any Employer.

7.9Clawback

Any amounts payable under this Plan are subject to any policy (whether in existence as of the Effective Date or later adopted) established by the Company providing for clawback or recovery of amounts that were paid to Executives. The Company will make any determination for clawback or recovery in its sole discretion and in accordance with any applicable law or regulation.

7.10Section Headings

Section headings in this Plan are included for convenience of reference only and shall not be considered part of this Plan for any other purpose.

7.11Non-exclusivity of the Plan

The adoption of the Plan by the Company will not be construed as creating any limitations on the power of the Company or of any Affiliate to adopt such other incentive arrangements as it may deem desirable. No employee, beneficiary or other person will have any claim against the Company or any Affiliate as a result of any such action. Any action with respect to the Plan taken by the Plan Administrator, the Company, any Affiliate or any designee of any of the foregoing shall be conclusive upon all employees of the Company and of any Affiliate and beneficiaries entitled to benefits under the Plan.

7.12Claims Procedures

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(a)Initial Claims. In order to file a claim to receive benefits under the Plan, the Executive or his authorized representative must submit a written claim for benefits to the Plan within 60 days after the Executive’s Termination. An Executive must complete the following claims procedure process before filing suit in court. Claims should be addressed and sent to the following (unless otherwise designated by the Plan Administrator):

Cheniere Energy, Inc.
700 Milam, Suite 1900
Houston, TX 77002
Phone Number: 713-375-5000

If the Executive’s claim is denied, in whole or in part, the Executive will be furnished with written notice of the denial within 90 days after the Plan Administrator’s receipt of the Executive’s written claim, unless special circumstances require an extension of time for processing the claim, in which case a period not to exceed 180 days will apply. If such an extension of time is required, written notice of the extension will be furnished to the Executive before the termination of the initial 90 day period and will describe the special circumstances requiring the extension, and the date on which a decision is expected to be rendered. Written notice of the denial of the Executive’s claim will contain the following information:

(i)the specific reason or reasons for the denial of the Executive’s claim;

(ii)references to the specific Plan provisions on which the denial of the Executive’s claim was based;

(iii)a description of any additional information or material required by the Plan Administrator to reconsider the Executive’s claim (to the extent applicable) and an explanation of why such material or information is necessary; and

(iv)a description of the Plan’s review procedure and time limits applicable to such procedures, including a statement of the Executive’s right to bring a civil action under Section 502(a) of ERISA following a benefit claim denial on review.

(b)Appeal of Denied Claims. If the Executive’s claim is denied and he wishes to submit a request for a review of the denied claim, the Executive or his authorized representative must follow the procedures described below:

(i)Upon receipt of the denied claim, the Executive (or his authorized representative) may file a request for review of the claim in writing with the Plan Administrator. This request for review must be filed no later than 60 days after the Executive has received written notification of the denial.

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(ii)The Executive has the right to submit in writing to the Plan Administrator any comments, documents, records or other information relating to his claim for benefits.

(iii)The Executive has the right to be provided with, upon request and free of charge, reasonable access to and copies of all pertinent documents, records and other information that is relevant to his claim for benefits.

(iv)The review of the denied claim will take into account all comments, documents, records and other information that the Executive submitted relating to his claim, without regard to whether such information was submitted or considered in the initial denial of his claim.

7.13Plan Administrator’s Response to Appeal

The Plan Administrator will provide the Executive with written notice of its decision within 60 days after the Plan Administrator’s receipt of the Executive’s written claim for review, unless special circumstances require an extension of time for processing the claim, in which case a period not to exceed 120 days will apply. If such an extension of time is required, written notice of the extension will be furnished to the Executive before the termination of the initial 60 day period and will describe the special circumstances requiring the extension, and the date on which a decision is expected to be rendered. The Plan Administrator’s decision on the Executive’s claim for review will be communicated to the Executive in writing and will clearly provide:

(a)the specific reason or reasons for the denial of the Executive’s claim;

(b)reference to the specific Plan provisions on which the denial of the Executive’s claim is based;

(c)a statement that the Executive is entitled to receive, upon request and free of charge, reasonable access to, and copies of, the Plan and all documents, records and other information relevant to his claim for benefits; and

(d)a statement describing the Executive’s right to bring an action under Section 502(a) of ERISA.

7.14Your Rights under ERISA

As a participant in the Plan, you are entitled to certain rights and protections under ERISA. ERISA provides that all Plan participants shall be entitled to:

Receive Information About Your Plan and Benefits

Examine, without charge, at the Plan Administrator’s office and at other specified locations, such as worksites and union halls, all documents governing the Plan, including insurance contracts and collective bargaining agreements, and a copy of the latest annual report

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(Form 5500 Series) filed by the Plan with the U.S. Department of Labor and available at the Public Disclosure Room of the Employee Benefits Security Administration.

Obtain, upon written request to the Plan Administrator, copies of documents governing the operation of the Plan, including insurance contracts and collective bargaining agreements, and copies of the latest annual report (Form 5500 Series) and updated Summary Plan Description. The Plan Administrator may make a reasonable charge for the copies.

Prudent Actions by Plan Fiduciaries

In addition to creating rights for Plan participants, ERISA imposes duties upon the people who are responsible for the operation of the Plan. The people who operate the Plan, called “fiduciaries” of the Plan, have a duty to do so prudently and in the interest of you and other Plan participants and beneficiaries. No one, including your Employer, your union, or any other person, may fire you or otherwise discriminate against you in any way to prevent you from obtaining a welfare benefit or exercising your rights under ERISA.

Enforce Your Rights

If your claim for a welfare benefit is denied or ignored, in whole or in part, you have a right to know why this was done, to obtain copies of documents relating to the decision without charge, and to appeal any denial, all within certain time schedules.

Under ERISA, there are steps you can take to enforce the above rights. For instance, if you request a copy of Plan documents or the latest annual report from the Plan and do not receive them within 30 days, you may file suit in a Federal court. In such a case, the court may require the Plan Administrator to provide the materials and pay you up to $110 a day until you receive the materials, unless the materials were not sent because of reasons beyond the control of the Plan Administrator. If you have a claim for benefits which is denied or ignored, in whole or in part, you may file suit in a state or Federal court. In addition, if you disagree with the Plan’s decision or lack thereof concerning the qualified status of a domestic relations order or a medical child support order, you may file suit in Federal court. If it should happen that Plan fiduciaries misuse the Plan’s money, or if you are discriminated against for asserting your rights, you may seek assistance from the U.S. Department of Labor, or you may file suit in a Federal court. The court will decide who should pay court costs and legal fees. If you are successful the court may order the person you have sued to pay these costs and fees. If you lose, the court may order you to pay these costs and fees, for example, if it finds your claim is frivolous. However, no legal action may be commenced or maintained against the Plan prior to your exhaustion of the Plan’s claims procedures described in this Summary Plan Description.

Assistance with Your Questions

If you have any questions about the Plan, you should contact the Plan Administrator. If you have any questions about this statement or about your rights under ERISA, or if you need assistance in obtaining documents from the Plan Administrator, you should contact the nearest office of the Employee Benefits Security Administration, U.S. Department of Labor, listed in your telephone directory or the Division of Technical Assistance and Inquiries, Employee Benefits Security Administration, U.S. Department of Labor, 200 Constitution Avenue N.W.,

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Washington, D.C. 20210. You may also obtain certain publications about your rights and responsibilities under ERISA by calling the publications hotline of the Employee Benefits Security Administration at 1-866-444-3272.

7.15Other Important Plan Information

Name and Address of Plan Sponsor/Plan Administrator

Cheniere Energy, Inc.
700 Milam, Suite 1900
Houston, TX 77002
Phone Number: 713-375-5000

Employer Identification Number (EIN) of Plan Sponsor and Plan Number

EIN:    95-4352386
Plan Number:    505

Type of Welfare Plan

Severance benefit plan

Type of Administration of Plan

Sponsor administration

Person Designated as Agent for Service of Legal Process

Corporate Secretary
Cheniere Energy, Inc.
700 Milam, Suite 1900
Houston, TX 77002

Ending Date for Plan’s Fiscal Year

December 31

Future of The Plan

Except as otherwise set forth herein, the Company has reserved the right to amend, modify or terminate all or any part of the Plan at any time, and from time to time, without the consent of or notice to any Executive. Except as otherwise set forth herein, the Company may also adopt one or more written supplements to this Plan that enlarge or diminish the rights of one or more Executives under the Plan without consent of or notice to any Executive.

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EXHIBIT A

CHENIERE ENERGY, INC. KEY EXECUTIVE SEVERANCE PAY PLAN
RELEASE AGREEMENT

1.This Release Agreement (the “Release Agreement”) is being entered into by ________________(the “Employee”) and Cheniere Energy, Inc. (the “Company”) pursuant to the Cheniere Energy, Inc. Key Executive Severance Pay Plan, as amended from time to time (the “Plan”) in order to further the mutually desired terms and conditions set forth herein. The term “Company” shall include Cheniere Energy, Inc., its present and former parents, trusts, plans, direct or indirect subsidiaries, affiliates and related companies or entities, regardless of its or their form of business organization. Capitalized terms used but not defined herein shall have the definitions set forth in the Plan.

2.For and in consideration for the Employee’s timely execution of this Release Agreement, and provided that the Employee does not revoke the General Release and/or ADEA Release contained in Sections 3 and 5 herein, the Company agrees to the following:

(a)Benefits. The Company shall provide to the Employee either the Change in Control Benefits or the Severance Benefits, as applicable, as set forth in the Plan and described in Exhibit 1 attached to this Release Agreement.

(b)The Change in Control Benefits, if applicable, represent the exclusive amounts to be paid to the Employee by the Company in connection with or arising out of the Change in Control. No further amounts shall be paid to the Employee for any items, including, but not limited to, attorneys’ fees.

(c)The Severance Benefits, if applicable, all of which are paid minus applicable tax withholding, represent the exclusive amounts to be paid to the Employee by the Company in connection with or arising out of the Employee’s employment with the Company and the Employee’s Termination of employment with the Company which occurred on _________________. No further amounts shall be paid to the Employee for any items, including, but not limited to, attorneys’ fees.

3.General Release. The Employee, on behalf of the Employee, the Employee’s heirs, beneficiaries, personal representatives and assigns, hereby releases, acquits and forever discharges the Company, its present and former owners, officers, employees, shareholders, directors, partners, attorneys, agents and assignees, and all other persons, firms, partnerships, or corporations in control of, under the direction of, or in any way presently or formerly associated with the Company (each, a “Released Party” and collectively the “Released Parties”), of, from and against all claims, charges, complaints, liabilities, obligations, promises, agreements, contracts, damages, actions, causes of action, suits, accrued benefits or other liabilities of any kind or character, in law or in equity, whether known or unknown, foreseen or unforeseen, vested or contingent, matured or unmatured, suspected or unsuspected, that may now or hereafter at any time be made or brought against any Released Party, arising from or in any way connected

with or related to the Employee’s employment with the Company and/or the Employee’s Termination of employment with the Company, including, but not limited to, allegations of wrongful termination, discrimination, retaliation, breach of contract, anticipatory breach, fraud, conspiracy, promissory estoppel, retaliatory discharge, constructive discharge, discharge in violation of any law, statute, regulation or ordinance providing whistleblower protection, discharge in violation of public policy, intentional infliction of emotional distress, negligent infliction of emotional distress, defamation, harassment, sexual harassment, invasion of privacy, any action in tort or contract, any violation of any federal, state, or local law, including, but not limited to, any violation of Title VII of the Civil Rights Act of 1964, as amended, 42 U.S.C. § 2000e et seq., the Civil Rights Act of 1866, 42 U.S.C. § 1981, the Equal Pay Act, 29 U.S.C. § 206, the Employee Retirement Income Security Act of 1974, 29 U.S.C. § 1001 et seq., the Americans with Disabilities Act, 29 U.S.C. § 621, et seq., the Family and Medical Leave Act, 29 U.S.C. § 2601 et seq., the Fair Credit Reporting Act, 15 U.S.C. § 1681, et seq., the Worker Adjustment and Retraining Notification Act, 29 U.S.C. §§ 2101-2109, the Texas Commission on Human Rights Act, Tex. Lab. Code § 21.001, et. seq., the Texas Workers’ Compensation Act, Tex. Lab. Code §§ 451.001 - 451.003, the Texas Payday Act, Tex. Lab. Code § 61.011, et seq., or any other employment or civil rights act, and any and all claims for severance pay, vacation pay, paid time off or benefits under any compensation, cash award, bonus, stock grant, equity grants or awards (or dividends, dividend equivalents or other rights associated therewith), or employee benefit plan, program, policy, contract, agreement, but excluding any claim for unemployment compensation, any claim for workers’ compensation benefits; and any benefits which the Employee is entitled to receive under any Company plan that is a qualified plan under IRC §401(a) or is a group health plan subject to COBRA. If execution of this Release Agreement is in connection with Termination of the Employee’s employment with the Company, COBRA continuation coverage is available to participants and their beneficiaries who participated in the Company’s group health plan as of the date of such Termination, to the extent the participant properly elects and pays for such COBRA continuation coverage. Excluded from the General Release in this Section 3 are claims arising under the Age Discrimination in Employment Act (“ADEA”), which are released pursuant to paragraph 5, and those claims which cannot be waived by law.

4.Except as provided herein, the Employee agrees not to commence any private legal proceeding or lawsuit against any Released Party arising out of or based upon the Employee’s employment with the Company or the Termination of the Employee’s employment with the Company. The Employee represents that the Employee has not filed any private charges, complaints, or other proceedings against the Company or any of the Released Parties that are presently pending with any federal, state, or local court or arbitrator. Notwithstanding this release of liability, nothing in this Release Agreement prevents the Employee from exercising any rights that cannot be lawfully waived or restricted, including filing a charge or complaint with the Equal Employment Opportunity Commission (“EEOC”), National Labor Relations Board (“NLRB”) (such as related to Section 7 rights under the NLRA), Occupational Safety and Health Administration, Securities and Exchange Commission (“SEC”), U.S. Department of Justice, Congress, any Inspector General, or other federal, state or local agency or participating in any

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investigation or proceeding (including providing documents or other information) conducted by such agency; however, the Employee understands and agrees that the Employee is waiving any and all rights to recover any monetary or personal relief or recovery from the Released Parties as a result of such proceeding or subsequent legal actions. In addition, nothing in this Release Agreement prohibits Employee from reporting possible violations of law or regulation to, or otherwise communicating with any government agency or entity, making other disclosures that are protected under whistleblower provisions of law, or receiving an award or monetary recovery pursuant to a government award program (including the SEC’s whistleblower program). The Employee does not need prior authorization to make such reports or disclosures and is not required to notify the Company that the Employee has made any such report or disclosure.

5.ADEA Release and Older Worker Benefit Protection Act (“OWBPA”) Disclosures. The Employee hereby completely and forever releases and irrevocably discharges the Company and the other Released Parties, as that term is defined in Section 3 above, from any and all liabilities, claims, actions, demands, and/or causes of action, arising under the ADEA on or before the date of this Release Agreement (“ADEA Release”), and hereby acknowledges and agrees that the Employee has been provided a decisional unit disclosure attached as Exhibit 2 and that:

a.The Release Agreement, including the ADEA Release, was negotiated at arms-length;

b.The Release Agreement, including the ADEA Release, is worded in a manner that the Employee fully understands;

c.The Employee specifically waives any rights or claims under the ADEA;

d.The Employee knowingly and voluntarily agrees to all of the terms set forth in the Release Agreement, including the ADEA Release;

e.The Employee acknowledges and understands that any claims under the ADEA that may arise after the date the Employee signs the Release Agreement are not waived;

f.The rights and claims waived in the Release Agreement, including the ADEA Release, are in exchange for consideration over and above anything to which the Employee was already undisputedly entitled;

g.The Employee has been and hereby is advised in writing to consult with an attorney prior to executing the Release Agreement, including the ADEA Release;

h.The Employee understands that the Employee has been given a period of up to 45 days to consider the ADEA Release prior to executing it, although the Employee may accept it at any time within those 45 days;

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i.The Employee understands and agrees that any changes to Company’s offer, whether material or immaterial, do not restart the running of the 45-day review period; and

j.The Employee understands that the Employee has been given a period of seven (7) days from the date of the execution of the ADEA Release to revoke the ADEA Release, and understands and acknowledges that the ADEA Release will not become effective or enforceable until the revocation period has expired.

If the Employee elects to revoke the release of age discrimination claims, the revocation must be in writing and delivered and presented to Wayne Williams, Vice President, Total Rewards and HR Services, Cheniere Energy, Inc. by 5:00 p.m., Central Time, no later than the seventh (7th) day after the date on which the Employee executes the Release Agreement.

6.The consideration cited above and the promises contained herein are made for the purpose of purchasing the peace of the Released Parties and are not to be construed as an admission of liability or as evidence of unlawful conduct by any Released Party, all liability being expressly denied. The Employee voluntarily accepts the consideration cited herein, as sufficient payment for the full, final, and complete release stated herein, and agrees that no other promises or representations have been made to the Employee by the Company or any other person purporting to act on behalf of the Company, except as expressly stated herein.

7.The Employee understands that this is a full, complete, and final release of the Released Parties. As evidenced by the signature below, the Employee expressly promises and represents to the Company that the Employee has completely read the Release Agreement and understands its terms, contents, conditions, and effects. The Employee represents that the Employee has made no assignment or transfer of the claims covered by Sections 3 or 5 above.

8.The Employee is advised to consult with an attorney prior to executing the Release Agreement. The Employee understands that the Employee has the right to consult an attorney of the Employee’s choice and has consulted with an attorney or has knowingly and voluntarily decided not to do so.

9.The Employee states that the Employee is not presently affected by any disability which would prevent the Employee from knowingly and voluntarily granting the Release Agreement, and further states that the promises made herein are not made under duress, coercion, or undue influence and were not procured through fraud.

10.The Employee acknowledges that the business and services of the Company are highly specialized and that the following information is not generally known, is highly confidential, and constitutes trade secrets: proprietary technical and business information relating to any Company plans, analyses, or strategies concerning international or domestic acquisitions, possible acquisitions, or new ventures; development plans or

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introduction plans for products or services; unannounced products or services; operation costs; pricing of products or services; research and development; personnel information (other than the Employee’s own); manufacturing processes; installation, service, and distribution procedures and processes; customer lists; any know-how relating to the design, manufacture, and marketing of any of the Company’s services and products, including components and parts thereof; non-public information acquired by the Company concerning the requirements and specifications of any of the Company’s agents, vendors, contractors, customers, and potential customers; non-public financial information, business and marketing plans, pricing and price lists; non-public matters relating to employee benefit plans; quotations or proposals given to agents or customers or received from suppliers; documents relating to any of the Company’s legal rights and obligations; the work product of any attorney employed by or retained by the Company; and any other information which is sufficiently secret to derive economic value from not being generally known (the “Confidential Information”). However, Confidential Information does not include information (A) that was or becomes generally available to the Employee on a non-confidential basis, if the source of this information was not reasonably known to the Employee to be bound by a duty of confidentiality, (B) that was or becomes generally available to the public, other than as a result of a disclosure by the Employee, directly or indirectly, that is not authorized by the Company or its affiliate, as applicable, or (C) that the Employee can establish was independently developed by the Employee without reference to any Confidential Information. Except as otherwise provided in paragraph 4, the Employee acknowledges that the Employee will maintain the confidential nature of all Confidential Information. The Employee further agrees to maintain in the strictest confidence and to not, directly or indirectly, intentionally or inadvertently, use, publish, or otherwise disclose to any person or entity whatsoever, any of the Company’s Confidential Information or any confidential information belonging to any agent, joint venture, contractor, customer, vendor, or supplier of the Company regardless of its form, without the prior written explicit consent of the Company’s Chief Executive Officer. The Employee shall take reasonable precautions to protect the inadvertent disclosure of information.

11.The Employee acknowledges and agrees that any work product prepared, conceived, or developed by the Employee during the term of the Employee’s employment with the Company, including but not limited to all written documents and electronic data pertaining thereto, is and shall remain the exclusive property of the Company, and will be considered Confidential Information subject to the terms of this Release Agreement. The Employee agrees that when appropriate, and upon written request of the Company, the Employee will acknowledge that the work product constitutes “works for hire” and will cooperate in the filing for patents or copyrights with regard to any or all such work product and will sign documentation necessary to evidence ownership of such work product in the Company.

12.To protect the Confidential Information of the Company, the Employee agrees, for twelve (12) months following the Termination of the Employee’s employment with the Company, that the Employee shall not, directly or indirectly, alone or jointly, with any person or entity, participate in, engage in, consult with, advise, be employed by, own

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(wholly or partially), possess an interest in, solicit the business of the vendors, suppliers or customers of the Company for, or in any other manner be involved with, any business or person that is engaged in business activities anywhere in the Territory that are competitive with the Business. Notwithstanding the foregoing, the Employee shall not be prohibited from passively owning less than 1% of the securities of any publicly-traded corporation. For purposes of this Section 12, “Territory” means anywhere in which the Company engages in Business and “Business” means the business of (i) selling, marketing, trading or distributing liquefied natural gas and/or (ii) designing, permitting, constructing, developing or operating liquefied natural gas facilities and/or (iii) trading natural gas on behalf of a liquefied natural gas facility or facilities. The Employee agrees that the covenants contained in this Section 12 are reasonable and desirable to protect the Confidential Information of the Company. Notwithstanding the foregoing, the Employee shall not be prohibited from being employed by, or consulting for, an entity that has a division immaterial to the business of such entity in the aggregate, which division may compete with, or could assist another in competing with, the Company in the Business in the Territory (a “Competitive Division”), so long as the Employee is not employed in, and does not perform work for or otherwise provide services to, the Competitive Division.

13.To protect the Confidential Information of the Company, the Employee agrees that for a period of twelve (12) monthsfollowing the Termination of Employee’s employment with Company, not to solicit, hire or participate in or assist in any way in the solicitation or hire of any employee of the Company (or any person who was an employee of the Company during the six (6)-month period preceding such action). For purposes of this covenant, “solicit” or “solicitation” means directly or indirectly influencing or attempting to influence employees of the Company to become employed with any other person, partnership, firm, corporation or other entity; provided, that solicitation through general advertising that is not directed at any employee of the Company or the provision of references shall not constitute a breach of the obligations in this Section 13. The Employee agrees that the covenants contained in this Section 13 are reasonable and desirable to protect the Confidential Information of the Company.

14.Following the Termination of the Employee’s employment with the Company, the Employee agrees (i) to reasonably cooperate with the Company and its directors, officers, attorneys and experts, and take all actions the Company may reasonably request, including but not limited to cooperation with respect to any investigation, government inquiry, administrative proceeding or litigation relating to any matter in which the Employee was involved or had knowledge during the Employee’s employment with the Company and (ii) that, if called upon by the Company, the Employee will provide assistance with respect to business, personnel or other matters which arose during the Employee’s employment with the Company or as to which the Employee has relevant information, knowledge or expertise, with such cooperation including, but not limited to, completing job tasks in progress, transitioning job tasks to other Company personnel, responding to questions and being available for such purposes. Any cooperation requests shall take into account the Employee’s personal and business commitments, and the Employee shall be reimbursed for reasonable documented travel, lodging and meal

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expenses incurred in connection with such cooperation within thirty (30) days of providing an invoice to the Company.

15.Except as otherwise provided in paragraph 4, the Employee shall not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise maligning the business reputation of, any Released Party. In the event that the Company’s Human Resources (“HR”) department receives any requests for employment verification or references pertaining to the Employee’s employment with the Company, the Company’s HR department shall provide a neutral reference that includes only confirmation of the Employee’s employment, dates of employment, and the job positions held. If requested, the Company’s HR department will neither confirm nor deny any basis for the Employee’s separation of employment.

16.If execution of this Release Agreement is in connection with Termination of the Employee’s employment with the Company, the Employee represents that the Employee has returned to the Company, except to the extent such return is expressly excused by the Company in writing, all expense reports, notes, memoranda, records, documents, employment manuals, pass keys, computers, computer diskettes, office equipment, sales records and data, and all other information or property, no matter how produced, reproduced or maintained, kept by the Employee in the Employee’s possession, used in or pertaining to the business of the Company, including but not limited to lists of customers, prices, marketing plans, Company operating manuals, and other Confidential Information obtained by the Employee in the course of the Employee’s employment.

17.Nothing in the Release Agreement shall be deemed to affect or relieve the Employee from any obligation contained in any agreement with the Company or any of the Released Parties related to the terms of Employee’s employment or separation therefrom, including, but not limited to, any confidentiality, non-solicitation, non-disclosure or other protective covenant, entered into between the Employee and the Company or any of the Released Parties, which covenants the Employee expressly reaffirms and re-acknowledges herein.

18.Should any future dispute arise with respect to the Release Agreement, both parties agree that it should be resolved solely in accordance with the terms and provisions of this Release Agreement and the laws of the State of Texas. Any disputes between the parties concerning the Employee’s employment with the Company and/or the Release Agreement shall be settled exclusively in Harris County, Texas.

19.If execution of this Release Agreement is in connection with Termination of the Employee’s employment with the Company, the Employee hereby (i) waives all rights to recall reinstatement, employment, reemployment, and past or future wages from the Company and (ii) additionally represents, warrants and agrees that the Employee has received full and timely payment of all wages, salary, overtime pay, commissions, bonuses, other compensation, remuneration and benefits that may have been due and payable by the Released Parties and that the Employee has been appropriately paid for all time worked and in accordance with all incentive awards.

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20.The Employee expressly represents and warrants to the Company that the Employee has received a copy of and has completely read and understood the Plan. The Employee further expressly represents and warrants to the Company that the Employee has completely read the Release Agreement prior to executing it, has had an opportunity to review it with the Employee’s counsel and to consider the Release Agreement and to understand its terms, contents, conditions and effects and has entered into the Release Agreement knowingly and voluntarily.

21.The Employee agrees that the terms and conditions of the Release Agreement, including without limitation the amount of money and other consideration, shall be treated as confidential, and shall not be revealed to any other person or entity whatsoever, except as follows:

a.to the extent as may be compelled by legal process or by government agency;

b.as set forth in paragraph 4 above; or

c.to the extent necessary to the Employee’s legal advisors, accountants or financial advisors, and provided that the Employee instructs the foregoing not to disclose the same to anyone.

22.The Employee agrees that the confidentiality provisions, including but not limited to those in Section 10 of the Release Agreement are a material part of it and are contractual in nature.

23.The Employee acknowledges that the Employee may hereafter discover claims or facts in addition to or different than those which the Employee now knows or believes to exist with respect to the subject matter of the release set forth above and which, if known or suspected at the time of entering into the Release Agreement, may have materially affected the Release Agreement and the decision to enter into it. Nevertheless, the Employee hereby waives any right, claim or cause of action that might arise as a result of such different or additional claims or facts.

24.The Employee agrees that the Employee will forfeit all amounts payable by the Company pursuant to the Release Agreement if the Employee challenges the validity of the Release Agreement, unless prohibited by law. The Employee also agrees that if the Employee violates the Release Agreement by suing the Company or the other Released Parties on the claims released hereunder, the Employee will pay all costs and expenses of defending against the suit incurred by the Released Parties, including reasonable attorneys’ fees, and return all payments received by the Employee pursuant to the Release Agreement.

25.Whenever possible, each provision of the Release Agreement shall be interpreted in such manner as to be effective and valid under applicable law; however, if any provision of the Release Agreement, other than Sections 3 and 5, shall be finally determined to be invalid or unenforceable under applicable law by a court of competent jurisdiction, that part shall

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be ineffective to the extent of such invalidity or unenforceability only, without in any way affecting the remaining parts of said provision or the remaining provisions of this Release Agreement. Should Sections 3 and/or 5 be determined to be illegal, invalid, unconscionable, or unenforceable, the Company shall be entitled to the forfeiture by the Employee of the Change in Control Benefits or the return of the Severance Benefits, as applicable, paid or provided with respect to the Employee or, at the Company’s sole option, to require the Employee to execute a new agreement that is enforceable.

Signature: _______________________________

Print Name: ______________________________

Date: ___________________________________

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EX-10.15

Exhibit 10.15

Cheniere Retirement Policy

1.0Objective

This Retirement Policy (this “Policy”) is designed to reward eligible employees of Cheniere Energy, Inc. and its subsidiaries (collectively, the “Company”) for their service and tenure.

2.0Scope

This Policy is limited to employees located in the United States. For the avoidance of doubt, this Policy is not applicable in any jurisdictions outside of the United States.

2.1Location

United States

2.2Exceptions

There are no exceptions

3.0Policy

3.1Definition of Qualifying Retirement

A “Qualifying Retirement” is a voluntary resignation by an employee who satisfies the Rule of 72 based on the sum of (i) the employee’s age and (ii) full years of service with the Company and/or its affiliates, provided that the employee also meets the following criteria:

•Employee must be at least age 60 and have at least 4 years of continuous service with the Company and/or its affiliates (such age and years of service, the “Retirement Criteria”).

•Employee must provide Human Resources with a written notice of his or her planned retirement date at least three (3) months in advance thereof; however, the Company may eliminate, or decrease the length of, the notice period in its sole discretion.

•Circumstances constituting “Cause” (as defined in any Company severance plan or employment agreement to the extent applicable to the Employee) do not exist at any time on or after the date of the Employee’s written notice of retirement.

•The Chief Executive Officer of the Company is not eligible for a Qualifying Retirement under this Policy, and accordingly, no retirement by the Chief Executive Officer will be deemed to be a Qualifying Retirement.

•Non-US employees, other than those on expatriate assignment from the US are not eligible for Qualifying Retirements under this Policy.

The determination of whether an employee satisfies the criteria for a Qualifying Retirement shall be determined by the Company in its sole discretion.

3.2Retirement Treatment

With respect to Covered Incentive Awards (as defined below) granted under the Company’s Annual Long-Term Performance Incentive Program on or after the Effective Date, and subject to the exclusions below, following a Qualifying Retirement, the employee will be entitled to:

•Accelerated vesting of the Employee’s outstanding unvested time-based equity or equity-based incentive awards (“Time-based Awards”), provided that the awards were granted at least six (6) months prior to the Qualifying Retirement; and

•Continued vesting of a pro rata portion of each outstanding unvested performance-based equity or equity-based incentive awards (“Performance Awards”), provided that the awards were granted at least six (6) months prior to the Qualifying Retirement, with proration determined by a fraction (not to exceed 1), the numerator of which is the whole number of months elapsed during the applicable performance period the Eligible Employee was employed (or if longer, during the service vesting period the Eligible Employee was employed), and the denominator of which is the whole number of months in the performance period (or, if longer, in the service vesting period) with respect thereto, which shall vest, if at all, based on actual results at the end of such performance period(s). For purposes of this calculation, the service vesting period shall be the period from the grant date through the date on which (but for the Qualifying Retirement) the employee would have otherwise been required to remain employed in order to vest in such Incentive Award.

The Company will waive the continuous employment vesting provisions set forth in any Covered Incentive Awards (as described below) granted prior to the Effective Date (excluding any Covered Incentive Awards granted under the Annual Long Term Performance Incentive Program) (collectively, the “Prior Incentive Awards”) that are held by employees who satisfy the criteria for Qualifying Retirements, as determined by the Company in its sole discretion. Following a Qualifying Retirement, all Prior Incentive Awards will continue to vest in accordance with the terms under the grant agreement(s), notwithstanding any continuous service conditions; however, except as otherwise determined by the Company, Prior Incentive Awards will remain subject to the applicable performance-based vesting conditions, if any.

With respect to certain Covered Incentive Awards, meeting the Retirement Criteria, even in the absence of a Qualifying Retirement, may result in taxation of the Covered Incentive Award at the time the Retirement Criteria are satisfied.

Notwithstanding anything in the Policy to the contrary, the Company may not waive any performance-based vesting conditions in Covered Incentive Awards that are intended to qualify as “qualified performance-based compensation” under Code Section 162(m), as determined by the Company in its sole discretion.

3.3Covered Incentive Awards

The retirement provisions and this Policy will apply to all long-term equity and cash-based awards outstanding on the Effective Date of this Policy and, except as otherwise provided in this Policy or determined by the Company, to long-term equity and cash-based awards granted after the Effective Date of this Policy (collectively, “Covered Incentive Awards”).

The retirement provisions are intended to be applied only to regular long-term incentive awards and not one-time, special, and/or retention-based awards, subject to the discretion of the Company. Accordingly, except as otherwise determined by the Company on a case-by-case basis, this Policy shall not apply to, and “Covered Incentive Awards” shall not include: (i) new hire awards; (ii) special retention awards; (iii) other awards not part of any annual long-term incentive compensation program or to awards under any annual cash bonus program; (iv) outstanding time-based awards granted within six (6) months prior to the Qualifying Retirement; or (v) outstanding performance-based awards granted within six (6) months prior to the Qualifying Retirement.

For the avoidance of doubt, and subject to the exclusions from Covered Incentive Awards above, the retirement provisions, and this Policy, will apply to the following awards outstanding on the Effective Date of this Policy:

•All outstanding Restricted Stock Awards under Trains 3-4; and/or

•All outstanding Phantom Unit Awards under the 2014-2018 Long-Term Cash Incentive Program.

In addition, the retirement provisions, and this Policy, will apply to any long-term cash and/or phantom unit awards granted after the effective date of this Policy or any other annual or long-term incentive compensation plan or program adopted after the effective date of this Policy, except as otherwise determined by the Company on a case-by-case basis or otherwise provided in the applicable plan, program or award agreements.

3.4Conditions to Retirement Treatment

The accelerated vesting or the Company’s waiver of the continuous employment vesting conditions, as applicable, of certain Covered Incentive Awards is subject to the employee’s execution and non-revocation of a release of claims in the form provided by the Company at (or within a specified time after) the time of retirement. In the event that the period in which the employee may consider the release of claims begins in one taxable year and ends in a subsequent taxable year, then any shares or cash payable as a result of vesting under this Policy will be delivered in such subsequent taxable year. Additionally, vesting is subject to compliance with the restrictive covenant provisions described below and any applicable performance vesting conditions that may apply to the Covered Incentive Awards. If the agreement governing the applicable Covered Incentive Award addresses a release of claims, the provisions of such agreement regarding the release shall govern. If the agreement governing the applicable Covered Incentive Award does not address a release of claims, then the Company shall determine the form of and timing requirements with respect to such release. In the event that a Covered Incentive Award is required to be settled prior to the release of claims becoming irrevocable, the employee shall be required to promptly repay or return to the Company all cash and property received with respect to such Covered Incentive Award in the event such release does not become irrevocable during the permitted period. The restrictive covenant provisions will apply for the duration of the vesting schedule for any unvested Covered Incentive Award(s), and the employee’s failure to comply with the restrictive covenant provisions will result in the immediate forfeiture of any then-outstanding Covered Incentive Awards.

3.5Restrictive Covenants

If, during employment or subsequent to a Qualifying Retirement, the employee violates any of the restrictions below, he or she will immediately forfeit all Covered Incentive Awards covered by this Policy that are outstanding at the time of such violation.

•During employment or subsequent to a Qualifying Retirement, the employee will not, directly or indirectly, do any of the following or assist any other person, firm or entity to do any of the following: (a) solicit on behalf of another person or entity, the employment or services of, or hire or retain, any person who is employed by or is a substantially full-time consultant or independent contractor to the Company or any of its subsidiaries or affiliates, or was within six (6) months prior to the action; or (b) otherwise knowingly interfere in any material respect with the business of the Company or any of its subsidiaries or affiliates or the relationship with any vendor or supplier that existed prior to the date of termination of the employee’s employment with the Company.

•During employment or subsequent to a Qualifying Retirement, the employee shall not make or publish any disparaging statements (whether written, electronic or oral) regarding, or otherwise malign the business reputation of, the Company, its present and former owners, officers, employees, shareholders, directors, partners, attorneys, agents and assignees, and all other persons, firms, partnerships, or corporations in control of, under the direction of, or in any way presently or formerly associated with the Company (each, a “Released Party” and collectively the “Released Parties”).

•During employment or subsequent to a Qualifying Retirement, the employee shall maintain the confidentiality of the following information: proprietary technical and business information relating to any Company plans, analyses or strategies concerning international or domestic acquisitions, possible acquisitions or new ventures; development plans or introduction plans for products or services; unannounced products or services; operation costs; pricing of products or services; research and development; personnel information; manufacturing processes; installation, service, and distribution procedures and processes; customer lists; any know-how relating to the design, manufacture, and marketing of any of the Company's services and products, including components and parts thereof; non-public information acquired by the Company concerning the requirements and specifications of any of the Company's agents, vendors, contractors, customers and potential customers; non-public financial information, business and marketing plans, pricing and price lists; non-public matters relating to employee benefit plans; quotations or proposals given to agents or customers or received from suppliers; documents relating to any of the Company's legal rights and obligations; the work product of any attorney employed by or retained by the Company; and any other information which is sufficiently confidential, proprietary, secret to derive economic value from not being generally known including with respect to intellectual property inventions, and work product. The foregoing shall not apply to information that the employee is required to disclose by applicable law, regulation or legal process (provided that the employee provides the Company with prior notice of the contemplated disclosure and cooperates with the Company at its expense in seeking a protective order or other appropriate protection of such information). Notwithstanding the foregoing, nothing in this Agreement prohibits employee from reporting possible violations of federal law or regulation to any government agency or entity or making other disclosures that are protected under whistleblower provisions of law. An employee does not need prior authorization to make such reports or disclosures and is not required to notify the Company that he has made any such report or disclosure.

•For employees who attain Qualifying Retirement from a position of a director level or above, during employment and for one (1) year subsequent to a Qualifying Retirement, to protect the confidential information of the Company, following the Qualifying Retirement, the employee shall not, directly or indirectly, alone or jointly, with any person or entity, participate in, engage in, consult with, advise, be employed by, own (wholly or partially), possess an interest in, solicit the business of the vendors, suppliers or customers of the Company for, or in any other manner be involved with, any business or person that is engaged in business activities anywhere in the Territory that are competitive with the Business. Notwithstanding the foregoing, the employee shall not be prohibited from passively owning less than 1% of the securities of any publicly-traded corporation. For purposes of this paragraph, “Territory” means anywhere in which the Company engages in Business and “Business” means the business of (i) selling, marketing, trading or distributing liquefied natural gas and/or (ii) designing, permitting, constructing, developing or operating liquefied natural gas facilities and/or (iii) trading natural gas on behalf of a liquefied natural gas facility or facilities. The employee agrees that the covenants contained in this paragraph are reasonable and desirable to protect the Confidential Information of the Company. Notwithstanding the foregoing, the employee shall not be prohibited from being employed by, or consulting for, an entity that has a division immaterial to the business of such entity in the aggregate, which division may compete with, or could assist another in competing with, the Company in the Business in the Territory (a “Competitive Division”), so long as the employee is not employed in, and does not perform work for or otherwise provide services to, the Competitive Division.

The Company (in its sole discretion) may elect to subject employees to additional or other restrictive covenants in consideration for the special treatment of their long-term equity and cash awards under this Policy or otherwise. These covenants shall be without limitation to such additional or other restrictions.

3.6Tax Matters; No Guarantee of Tax Consequences

In the event the Company determines that this Policy results in a taxable event for a retiree or eligible employee with respect to the foregoing Covered Incentive Awards, except as otherwise agreed in writing by the employee and the Company, any federal, state and local income, employment and other taxes required to be withheld by the Company in connection with the vesting of such restricted stock awards, or sooner upon the lapse of a substantial risk of forfeiture thereon for purposes of Code Section 83 of the Internal Revenue Code of 1986, as amended (the “Code”) shall be effectuated, as specified by the Company, by either the Company withholding delivery of a number of shares of common stock of the Company

having a fair market value equal to the minimum amount of such tax withholding obligations determined at the time of taxation at the minimum withholding tax rate required by the Code or by the employee writing a check, acceptable to the Company, to the Company equal to such amount.

The Covered Incentive Awards subject to this Policy are subject to all federal, state and local income, employment, and other taxes, and any required withholding in connection with such taxes. This Policy is intended to be exempt from, or to comply with, the requirements of Section 409A of the Code, and this Policy shall be interpreted accordingly; provided that in no event whatsoever shall the Company or any of its affiliates be liable for any additional tax, interest or penalties that may be imposed on an employee by Code Section 409A or any damages for failing to comply with Code Section 409A or damages for noncompliance. The Company makes no commitment or guarantee to the employee that any federal, state or other tax treatment will (or will not) apply or be available to any person eligible for benefits under this Agreement. Notwithstanding anything in this Policy to the contrary, in the event that an employee is deemed to be a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i), no payments hereunder that are “deferred compensation” subject to Code Section 409A shall be made to the employee prior to the date that is six (6) months after the date of the employee’s “separation from service” (as defined in Section 409A) or, if earlier, the employee’s date of death. Following any applicable six (6) month delay, all such delayed payments will be paid in a single lump sum on the earliest date permitted under Code Section 409A that is also a business day.

3.7No Right to Continued Employment

Nothing in this Policy shall confer upon any employee any right to continue in the employ of the Company or any of its affiliates or interfere in any way with the right of the Company or any of its affiliates to terminate the employment of any employee for any reason or no reason at any time.

3.8Interpretation

The Company may interpret and construe the terms and application of this Policy. All actions taken by the Company in accordance with the immediately preceding sentence shall be final and binding on all persons.

3.9Policy Will Not Prevent Clawback

This Policy shall not be construed to prevent the forfeiture or divestiture of any Covered Incentive Award if otherwise contemplated under the terms of any restrictive covenant agreement or clawback policy applicable to an employee or former employee.

3.10Amendment; Termination; Conflict

This Policy can be amended, modified, or terminated at any time at the discretion of the Company or the Board, provided it shall not affect any employees who retire or have previously delivered written notice of retirement prior to such amendment, modification, or termination. In the event of any conflict between the terms of this Policy and the terms of the applicable equity incentive plan, the terms of the applicable equity incentive plan shall control.

4.0Policy Governance

The most senior Human Resources officer of the Company is the owner of this Policy and shall be accountable for ensuring compliance with Records and Information Management & Standards policies. The Company holds all property rights while owners have management accountability.

5.0References

This Policy and all records generated from this Policy shall be managed and retained during their lifecycle according to the Information Management Policy and the Records Retention Schedule.

EX-10.57

Exhibit 10.57

[***] indicates certain identified information has been excluded because it is both (a) not material and (b) would be competitively harmful if publicly disclosed.

CHANGE ORDER

Q1 2023 COMMODITY PRICE RISE AND FALL (ATT MM)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00040 DATE OF CHANGE ORDER: 29-Aug-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.    In accordance with Section 1.2 of Attachment MM of the Agreement (“Commodity Price Rise and Fall”), this Change Order addresses Q1 2023 period commodity price rise and fall for:

1.1    304 Stainless Steel Pipe and Fittings (Item 1 of Appendix 1 of Attachment MM), $ 168,731 paid to Contractor;

1.2    Carbon Steel Pipe, Fittings, Flanges (Item 2 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q1 2023);

1.3    USA Fabricated Structural Steel (Item 3 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q1 2023);

1.4    UAE Fabricated Structural Steel (Item 4 of Appendix 1 of Attachment MM), $453,016 paid to Owner; and

1.5    Wire and Cable (Copper) (Item 5 of Appendix 1 of Attachment MM), $401,365 paid to Owner.

2.    Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

3.    The Q1 2023 current Index Value and calculation methodology is provided in Exhibit A of this Change Order.

Adjustment to Contract Price Applicable to Subproject 6(a)
1. The original Contract Price was ……………………..….....................................................................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00039)...............................	$	167,451,690
3. The Contract Price prior to this Change Order was ........................…..................................................	$	5,651,451,690
4. The Aggregate Equipment Price will be reduced by this Change Order in the amount of ...................	[***]
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of....	$	0
6. The Contract Price Applicable to Subproject 6(a) including this Change Order will be ......................	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………………………………………………….....................	$	0
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,650,766,040

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

Q2 2023 COMMODITY PRICE RISE AND FALL (ATT MM)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00041 DATE OF CHANGE ORDER: 29-Aug-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows: (attach additional documentation if necessary)

1.In accordance with Section 1.2 of Attachment MM of the Agreement (“Commodity Price Rise and Fall”), this Change Order addresses Q2 2023 period commodity price rise and fall for:

1.1 304 Stainless Steel Pipe and Fittings (Item 1 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q2 2023);

1.2 Carbon Steel Pipe, Fittings, Flanges (Item 2 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q2 2023);

1.3 USA Fabricated Structural Steel (Item 3 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q2 2023);

1.4 UAE Fabricated Structural Steel (Item 4 of Appendix 1 of Attachment MM), $680,147 paid to Owner; and

1.5 Wire and Cable (Copper) (Item 5 of Appendix 1 of Attachment MM), $0.00 (not applicable in Q2 2023).

2. Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

3. The Q2 2023 current Index Value and calculation methodology is provided in Exhibit A of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00040)……….……......	$	166,766,040
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,650,766,040
4. The Aggregate Equipment Price will be reduced by this Change Order in the amount of................	[***]
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount....	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………….......................	$	5,650,085,893

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

HAZOP PACKAGE #2 – ADDITIONAL IPL (PRESSURE TRANSMITTER ACROSS THE STRAINER)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy, Inc. CHANGE ORDER NUMBER: CO-00042 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Jul-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor will provide a pressure transmitter across the strainer instead of a pressure indicator as is required in document 26290-100-U4R-DK-21076. For context, HAZOP Action Item 21076 recommended additional Independent Protection Layer (“IPL”) to prevent damage to 31C-1611 when 31SP-16102 31C-1611 is plugged.

2. The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3. Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………….…..	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00041)…..……………….	$	166,085,893
3. The Contract Price prior to this Change Order was ………………………………………………......	$	5,650,085,893
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of .............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of....	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,650,815,301

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

TOTAL CONDENSATE FLOWMETER ON THREE (3) INCH CONDENSATE LINE

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy, Inc. CHANGE ORDER NUMBER: CO-00043 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 31-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor will add a flowmeter on the three (3) inch condensate line to measure total condensate, with isolation valves, being routed to CCL Stage 1 and 2 condensate storage tanks.

2.     The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.     Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………..….................................................................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 - CO-00042)…......................	$	166,815,301
3. The Contract Price prior to this Change Order was ……..................................................................	$	5,650,815,301
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of......................................................................................................................................	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of.................................................................................................................................	$	0
8. The new Contract Price including this Change Order will be .........................................................	$	5,651,146,819

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

FERC Package #1

ISA 84 (ACCOMMODATION FOR TWO HUNDRED AND FIFTY (250) FIRE AND GAS DETECTORS)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy, Inc. CHANGE ORDER NUMBER: CO-00044 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 31-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor will provide power supplies and wiring terminals for the future addition of up to two hundred and fifty (250) fire and gas (“F&G”) detectors in each of the F&G Remote Input / Output (“RIO”) boxes.

2.For context, this Change Order does not address: Design, procurement, installation, wiring, configuration, location plans, index, supply of the potential additional two hundred and fifty (250) F&G devices, associated cabling, I/O configuration. Locations and number of detectors in the future will be limited by the existing RIO boxes.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………..…...................................................................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00043)….…………….....	$	167,146,819
3. The Contract Price prior to this Change Order was ............................................................................	$	5,651,146,819
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,651,433,282

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

INCREASE LNG RUNDOWN LINE CHECK VALVE BYPASS SIZE TO SIX (6) INCHES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00045 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 31-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor will increase the rundown line check valve bypass from four (4) inches to six (6) inches with flanged valve.

2.For context, Owner has requested the six (6) inch rundown line bypass in order to mitigate vapor cloud propagation although four (4) inches is the standard line size.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00044)……..……………	$	167,433,282
3. The Contract Price prior to this Change Order was ……………………………………………….....	$	5,651,433,282
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,651,622,119

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTELENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

ADD MANUAL BYPASS VALVES AROUND 31XV-13071

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00046 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 13-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner based on DECN 2380 (26290-100-M6N-DK-02380), Contractor will add four (4) manual bypass valves around each IMI seated valve 31XV-13071 (one per Train). Therefore of a total of twenty-eight (28) manual bypass valves are provided in this Change Order.

2.For context, at Owner’s request these manual bypass valves are added in order to equalize pressure prior to plant start-up, minimize wear and tear on valve seat, allow additional flexibility during start-up and to minimize flaring.

3.Attachment 1 to this Change Order identifies the location of where the bypass valves will be installed around 31XV-13071.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00045).…….……….....	$	167,622,119
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,651,622,119
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount...............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………………………………………….......	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,652,030,230

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith ___________________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

RELOCATE EXISTING 16” PROCESS WATER LINE AND PROVIDE TIE-IN

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00047 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 08-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will upgrade Owner’s 16” service (utility) water line, as follows:

1) New permanent underground utility water connection for Stage 3, located north of the existing connection which is at STA. 455+80;

2) Relocate existing connection by reconfiguring the underground portion of current connection at STA. 455+80 to stub-up approximately 20' south and adding aboveground metallic pipe and concrete pad with supports. This stub-up was requested for permanent construction water supply; and

3) A representative illustration is provided in Attachment 1 of this Change Order; and

4) Contractor will provide bollards to protect the aboveground piping (beside La Quinta Road).

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00046)……..….............	$	168,030,230
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,652,030,230
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,652,427,821

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith ___________________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

FUTURE HRU BYPASS TIE-IN AND THERMOWELL UPDATES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc.     CHANGE ORDER NUMBER: CO-00048 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 12-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will amend the scope per clauses 2 and 3 of this Change Order:

2.Add a total of forty-two (42) tie-ins for a future Heavies Removal Unit (HRU) Bypass, specifically, three tie-ins on each Heavies Removal Cold Box (or six (6) tie-ins per Train).

a) For context, these tie-ins have been requested by Owner to provide increased operational flexibility, and are not included in the current scope.

3.Replace and upgrade one hundred and nineteen (119) Thermowells (that is, seventeen (17) Thermowells per Train).

a) For context, this is per the outcome of the Owner-requested study (Integrity Check – Summary Report 26469-383-G65-GEX-00001) evaluating Stage 3 Equipment supporting the higher feed gas flow rate and Nitrogen content (mol%) contemplated by potential changes which include the Nitrogen Rejection Unit and End-Flash Unit.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00047)……..……….....	$	168,427,821
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,652,427,821
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of ..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………..	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,653,330,731

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith ___________________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

BUTTERFLY VALVES FOR FLARE DRUMS

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00049 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will add flare drum isolation valves for the three (3) Wet Flare Knockout Drum and three (3) Dry Flare Knockout Drum, all located in the OSBL.

2.The illustration provided in Attachment 1 of this Change Order is representative of the location of the isolation valves on the main outlet of each flare drum, as shown on the first set of Knockout Drums (V1901 and V1902).

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00048)….….………….	$	169,330,731
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,653,330,731
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of ..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,654,029,169

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

CONDENSATE SHROUD ON CONDENSATE RUNDOWN LINE (BLUE ENGINEERING REPORT)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00050 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 12-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will add the RAMCO® TFE SPRA-GARD® Safety Shield condensate shroud on the Condensate Rundown Line. Sections of the condensate line already covered by the LNG rundown shroud, are not included.

2.Attachment 1 to this Change Order identifies the location where the condensate shroud will be installed on the Condensate Rundown Line, which is intended to prevent a vapor cloud and is in accordance with Owner’s Blue Engineering recommendation.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00049)……….………..	$	170,029,169
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,654,029,169
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………………………………………..........	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………..............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,654,314,516

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith ___________________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

EFG PACKAGE #5 (138KV FEEDER CABLE)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00051 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 08-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will install 138kV feeder cables to the future End-Flash Unit (“EFG”) area, that is, up to the first splice location following which the cables will be buried in a trench box.

2.For context, and in accordance with the amendment to the scope per Change Order CO-00028 (“Additional Duct Banks”), the current EFG 138kV scope is only to provide an underground duct bank from the Main GIS Substation to an area west of the West OSBL Piperack.

3.Attachment 1 is provided to illustrate the approximate location of each splice.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00050)…….…………..	$	170,314,516
3. The Contract Price prior to this Change Order was ..............………………………………………	$	5,654,314,516
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount ..............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in ........................	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………......	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………..............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,657,303,536

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith ___________________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

DEFECT CORRECTION PERIOD FOR CEMENTITIOUS FIREPROOFING

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00052 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 07-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Article 6.1 of the Agreement (Owner’s Right to Change Orders), the Parties agree this Change Order:

A) Adopts the revision to the compressive strength acceptance criteria for Carboline Pyrocrete® 241 as stated on page 11 of 11 of Project Specification Proprietary Fireproofing (26290-100-3PS-NF00-F0002 Rev 001 dated 08-Jun-2023), as provided in Attachment 1 of this Change Order; and

B) Amends the capitalized term “Defect Correction Period” in Article 1 (“Definitions”) of the Agreement to add the following sub-clause (ix):

“(ix) With respect to Carboline Pyrocrete® 241 cementitious fireproofing, the period commencing the Substantial Completion of the respective Train and ending thirty (30) months thereafter, without extension, on the condition that the Defect is attributed to low compressive strength”.

Adjustment to Contract Price
1. The original Contract Price was ………………………............……………………………………	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00051)…………….…..	$	173,303,536
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,657,303,536
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of.........	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of.	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………...........................	$	5,657,303,536

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

CHART TRANSITION JOINT SPARES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00053 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams:

1.1 Contractor will procure one (1) set of Transition Joint spares (Liquefaction cold boxes type);

1.2 Contractor will procure one (1) set of Transition Joint spares (Heavy Hydrocarbon cold boxes type);

1.3 The itemization of spares purchased under Clauses 1.1 and 1.2 of this Change Order is provided in Attachment 1 of this Change Order. Currently such spares are not in Contractor’s scope to purchase; and

1.4 For the avoidance of doubt, items procured in this Change Order will not be addressed under Section 4 of Attachment GG of the Agreement (“Capital Spare Parts Provisional Sum”).

2.     The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.     Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………........……………	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00052)…..…………….	$	173,303,536
3. The Contract Price prior to this Change Order was …………………………..............……………	$	5,657,303,536
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,657,470,384

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

CCL TANK(S) “A” AND “C” TIE-IN STUDY & LONG LEAD ITEM PURCHASES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00054 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 19-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor shall perform the scope described in clauses 2 and 3 of this Change Order:

2.CCL Tank(s) “A” and “C” Tie-In Study

1) The scope and deliverables for the CCL Tank(s) “A” and “C” Tie-In Study (“Tie-In Study”) are provided in Attachment 1 of this Change Order;

2) The detailed cost breakdown for the Tie-In Study is provided in Exhibit A of this Change Order.

3.Long Lead Item Purchases - CCL Tank(s) “A” and “C” Tie-Ins

1) Contractor will procure and deliver (only) certain long lead items, as described in Exhibit B of this Change Order. For the avoidance of doubt, the Parties agree that the definition of Stage 3 Facility includes Equipment procured to perform CCL Liquefaction Facility Tie-in Work. Capitalized terms used in Clause 3.1 of this Change Order have meaning ascribed to them in the Stage 3 EPC Agreement.

2) Should Owner terminate such long lead item purchases, Owner’s liability to Contractor is as per the amounts stated in Exhibit 2 of this Change Order. For the avoidance of doubt, Article 16.2 of the Agreement (“Termination for Convenience by Owner”) will govern the termination for convenience of any other portion of this Change Order.

3) Change Order does not include pipe or steel quantities, Contractor will recommend additional pre-buys (pipe, steel, etc.) as needed to align with execution and installation timing with the CCL Stage 3 LNG rundown Line schedule.

4.Parties agree that the fee for HAZOP (including Contractor’s hours), if required, and, regulatory permitting support including FERC, is presently excluded but shall be included by future Change Order on a provisional sum basis (which is currently expected in the $50,000 range but will ultimately be dependent on actual scope).

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00053)…...….…………	$	173,470,384
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,657,470,384
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]

6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………......	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………..………………………………………................	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,659,610,400

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

FERC PACKAGE #2 FIREWATER LAYOUT

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00055 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 13-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, the scope is amended as follows:

1.1    Add a total of twenty-eight (28) elevated self-oscillating firewater monitors (four (4) per Train), located between the Cryogenic Rack and the respective liquefaction unit. These will be designated as 31FWEOM-33101, 31FWEOM-33102, 31FWEOM-33103 and 31FWEOM-33104. Currently, such elevated self-oscillating firewater monitors are not in the design.

1.2    Relocate the seven (7) firewater monitors (31FWM-33008) in each Train’s gas treatment equipment area.

1.3    Provide Hydrants With Monitors in lieu of Hydrants in each of the Flare Knockout Drum areas. Therefore a total of three (3) Hydrants are upgraded in this Change Order; and

1.4    Relocate the three (3) firewater monitors (30FWM-33201, 30FWM-33401 and 30FWM-33601) in each of the Flare Knockout Drum areas. Therefore a total of nine (9) firewater monitors are relocated in this Change Order.

2.For context, this Change Order responds to certain queries Owner received from FERC’s representatives on 21-Dec-2022.

3.Attachment 1 of this Change Order provides the updated Firewater System P&ID (per Train) as per the scope amended in this Change Order.

4.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

5.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00054)….….………….	$	175,610,400
3. The Contract Price prior to this Change Order was ………..............………………………………	$	5,659,610,400
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of...........................................................................................................................................	$	0

7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………….....……….....	$	5,686,272,310

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

HAZOP Package #3 – Stainless Steel C and D Pass Piping / Two Temperature Transmitters per Train

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00056 DATE OF CHANGE ORDER: 14-Feb-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor shall perform the scope defined in Section 2 of this Change Order.

2.With respect to HAZOP Action Item(s) 10040, 10042, 10053, 10063, 21004, 21006, 21007, 21017, 21132, 21003, 21028, 10037, 10039, 10051, 21005, 21008, 21016, 21019 and 21052, Contractor shall:

2.1    Per HAZOP Action Item 21052; and as a conservative measure to provide margin in the simulation results, piping up to and including 31XV-16003 – located approximately 200 feet from 31E-1711 Pass D outlet shall be upgraded from: B1A to P0F;

2.2    Upgrade 31E-1711 Pass C outlet piping material class to R0F from C1A, from 31E-1711 C outlet to 31E-1614 A inlet;

2.3    All valves provided per Items 2.1 and 2.2 will be rated for cryogenic services previously not rated for cryogenic services and

2.4    Add two (2) additional temperature transmitters per string – four (4) per Train:

3.    The cost breakdown is provided in Exhibit A of this Change Order.

4.    Schedules C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestones listed in Exhibit 1 of this Change Order.

Adjustment to Contract Pr
1. The original Contract Price was ………………………………………………………………........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00055)………….……..	$	202,272,310
3. The Contract Price prior to this Change Order was ……………………………………..............…	$	5,686,272,310
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..………………………………………………………………….……................	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,699,694,358

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

HAZOP PACKAGE #4 (“PHASE TWO ITEMS”)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00057 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 10-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor’s scope is amended to implement the following HAZOP resolution(s):

Item	HAZOP Reference	HAZOP Scenario see note 1	HAZOP Resolution
1	26290-100-U4R-DK-21133	Liquid may get trapped between 31XV-16006 and 31HV-16008 causing expansion exceeding the design pressure of piping, due to 31HV-16008 on inlet 31V-1611 MR suction drum being closed.	Contractor will add Thermal Pressure Safety Valve between 31XV-16006 and 31HV-16008 to prevent overpressure due to liquid expansion.
2	26290-100-U4R-DK-30010	Pressure may increase in the fuel gas system, due to 31PV-22007 fails closed when needed to be open.	Contractor will add independent layer of protection (“IPL”) to isolate pressure sources above 150 psig from 31V-2201 Fuel Gas Knockout Drum (“KOD”).
3	26290-100-U4R-DK-30004	31V-2201 Fuel Gas KOD may not be able to drain, and there is a potential for gradual level increase due to fail close of 31LV-22002 on the bottom of 31V-2201 Fuel Gas KOD.	Contractor will add Level Transmitter (“LT”) on 31V-2201 Fuel Gas KOD to close 31XV-13068 and 31XV-18032.
4	26290-100-U4R-DK-10022	High pressure gas may flow from 31V-1201 absorber to 21V-1209 amine sump drum, due to 31VA-120271 on skim line from 31V-1201 absorber line being left open during skimming operation (26290-100-M6N-DK-02120).	Contractor will add LT and isolation valve to isolate the flow.
5	26290-100-U4R-DK-30095	May be unable to purge a burner runner following closure of the staging valve, due to nitrogen purge valve (XV-19712) failing to open when required.	Contractor will relocate the specification break for the nitrogen purge line.
6	26290-100-U4R-DK-10003	Potential unintended flow of feed gas from tube side to shell side of 31E-1102 Feed Gas Heater, due to tube failure in 31E-1102 Feed Gas Heater.	Contractor will add a layers of protection to prevent overpressure of 31E-1102 Feed Gas Heater, such as increased pipe class and other modifications as recommended by the transient analysis.

Note 1 The table only describes each HAZOP scenario at a summary level.

2.    The detailed cost breakdown for each item is detailed in Exhibit A of this Change Order, together with a summary table.

3.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………..................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00056)…...……………...	$	215,694,358
3. The Contract Price prior to this Change Order was ……………………………………….................	$	5,699,694,358
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of.............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of.....	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,718,706,940

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

E-HAZOP PACKAGE #1 (“LV MCC RIDE THROUGH”)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00058 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 08-Sep-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will implement the following design change to keep the contactors closed for critical low voltage (“LV”) motor starters (all other components will remain as originally designed). This was identified in E-Hazop Action item 26290-100-U4R-DK-E0001 Utility Voltage Dip:

a)    LV motor starters for loads identified in the table of Attachment 1 of this Change Order will have internal wiring and components revised from standard manufacturing design to allow LV motor contactors to remain closed for the drop to thirty-five (35%) percent voltage for twenty-five (25) cycles (416 ms).

2.For context and per Cheniere response in BECHTEL-RFC-000032, the current voltage range from the utility is plus or minus five (5%) percent voltage variation from nominal (under normal conditions) and plus five (5%) percent minus ten (10%) percent voltage variation from nominal (under abnormal conditions).

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Pr
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00057)…..…………….	$	234,706,940
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,718,706,940
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………………………………………………….………………………………….	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,722,106,769

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

LEVEL TRANSMITTER ON STAND PIPE INSIDE LIQUEFACTION COLD BOXES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00059 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 13-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner, Contractor will add a level transmitter on each stand pipe inside the liquefaction cold boxes (total of six (6) level transmitters per Train). Therefore, a total of forty-two (42) level transmitters are provided in this Change Order.

2.For context, these level transmitters have been requested in order to assist with troubleshooting during operations.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00058).…….…………….	$	238,106,769
3. The Contract Price prior to this Change Order was ……………………………………….................	$	5,722,106,769
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of..............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of.....	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………......	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………..................	$	0
8. The new Contract Price including this Change Order will be ……………………………………......	$	5,725,475,061

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

SMALL SPILL CONTAINMENT (ADDITIONAL CURBS)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00060 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Jul-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams:

1.1    In the Hot Oil Pumps (D01) and Diesel Generator (G01) areas, Contractor will add a shallow trench area to capture small spills, and a small pit to allow for observation and dropping a vacuum hose;

1.2    In the Hot Oil Pumps (D01), Diesel Generator (G01), and Lean Solvent Booster and Charge pumps (K01) areas, Contractor will provide dedicated valves to control release of clean rainwater connected via underground line leading to the stormwater collection system; and

1.3    In the Lean Solvent Booster and Charge Pump (K01) area, Contractor will only provide nearby high point paving cricket line within perimeter curbing to allow capture of a smaller spill; larger spills (overtopping of high point) to drain into the spill trench.

1.4    For context, the scope presently allows for curbing such that any spill drains into the adjacent concrete spill trench.

2.    An illustrative scope sketch is provided in Attachment 1 of this Change Order.

3.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00059)……..………….	$	241,475,061
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,725,475,061
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of..	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ……………..…………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,728,156,072

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

REMOTE INPUT/OUTPUT (RIO) JUNCTION BOX GROUNDING

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00061 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 10-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor’s scope Remote Input/Output (“RIO”) Junction Box Grounding is amended as follows:

1.1    RIO junction box power earthing (PE) grounding bars will be grounded to a dedicated instrument grounding bar that is grounded to the main electrical grounding grid; and

1.2    RIO junction box instrument earthing (IE) grounding bars are grounded to an isolated instrument grounding bar that is grounded to the main electrical grounding grid through an isolation grounding triad at each ISBL Substation using 2 AWG conductor size. Includes routing to substation IE isolated bus bar.

2.For context, RIO junction box grounding bars (PE and IE) are both grounded to a dedicated instrument grounding bar. The instrument grounding bar is grounded to the main electrical grounding grid.

3.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………….......................................................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00060)…..….………....	$	244,156,072
3. The Contract Price prior to this Change Order was ……………………………….........................................	$	5,728,156,072
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of ..........................	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of.	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………..............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,728,852,534

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

GEOMEMBRANE LINER AND GEOCELL FOR LAYDOWN 6 CHANNEL

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00062 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 31-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams:

1.1    Contractor will amend the slope protection design for Laydown 6 Channel and add one (1) geomembrane liner (XR5), one (1) geoweb (GW30V4), and one (1) additional layer of geotextile to the current design. Contractor will also provide credit for the one (1) geocell (Envirogrid EGA 30), and one (1) D50 rip rap in specified locations that were part of previous design.

1.2    For context, the current slope protection design allows for, one (1) layer of geotextile fabric, one (1) perforated geocell (Envirogrid EGA 30), and one (1) layer of grave infill and D50 Rip Rap in specified locations.

2.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00061)…….…………...	$	244,852,534
3. The Contract Price prior to this Change Order was ………………………………………...............	$	5,728,852,534
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ………………………………….......	$	5,729,688,941

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

PHASED SURFACING OF PERMANENT PLANT ROADS

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00063 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 07-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”), the Parties agree that Substantial Completion, as defined in Article 1 of the Agreement, is amended as follows:

1.1    Contractor will complete surfacing (asphalting) of ISBL and OSBL permanent plant roads in three (3) phases, each no later than forty-five (45) Days following the Substantial Completion(s) of Trains 3, Train 6 and Train 7 respectively.

1.2    Surfacing (asphalting) of ISBL and OSBL permanent plant roads is therefore excluded as a requirement for the achievement of Substantial Completion; and

1.3    Attachment 1 of this Change Order describes the three (3) phases.

2.Specific to the scope of this Change Order, for the avoidance of doubt, upon approval of this Change Order the Parties acknowledge this matter will not be raised as the subject of a future Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………………….........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00062)……..…………..	$	245,688,941
3. The Contract Price prior to this Change Order was ………………………………………...............	$	5,729,688,941
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of..........	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………..	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,729,688,941

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

PROVISIONAL SUM INTERIM ADJUSTMENT - SCHEDULE KK-1 12-MONTH COVID COUNTERMEASURES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00064 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 24-Jul-2023

The Agreement between the Parties listed above is changed as follows:

1.The Parties agree to the interim adjustment to the COVID-19 Provisional Sum as set forth in Section 7 of Attachment GG of the Agreement.

2.Prior to this Change Order the COVID-19 Provisional Sum was Twenty Million U.S. Dollars (U.S.$20,000,000), which includes (6%) fee. The COVID-19 Provisional Sum is hereby decreased by Eleven Million, Three Hundred and Sixty-One, Five Hundred and Thirty-Eight U. S. Dollars (U.S. $ 11,361,538). Therefore the COVID-19 Provisional Sum as amended by this Change Order is Eight Million, Six Hundred and Thirty-Eight Thousand, Four Hundred and Sixty-Two U.S. Dollars (U.S. $ 8,638,462.00).

3.For additional context:

•The unamended COVID-19 Provisional Sum is Twenty Million U.S. Dollars (U.S.$20,000,000) and is comprised of such COVID-19 Countermeasures that may be implemented (i) in the first twelve (12) months following the 01-Mar-2022 LNTP No. 1 (as set forth in Schedule KK-1) and (ii) during the Work (as set forth in Schedule KK-2);

•As at 24-Jul-2023, Contractor has not implemented Schedule KK-1 COVID-19 Countermeasures and therefore the Parties mutually agree to reduce the COVID-19 Provisional Sum by the entire Schedule KK-1 portion, plus six percent (6%); and

•The impact to the Work as a result of a COVID-19 Event (which under the Agreement also includes other epidemics, pandemics, or plagues affecting the Work) does not qualify as a Force Majeure. Parties acknowledge that this Change Order does not affect Contractor’s rights in Section 6.13 of the Agreement.

4. The cost breakdown for this Change Order is detailed in Exhibit 1 of this Change Order.

5. Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………………............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00063)…………………	$	245,688,941
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,729,688,941
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of .......	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of	$	0
6. The Aggregate Provisional Sum Equipment Price will be (decreased) by this Change Order in the amount of …………………………………………………………………………………………...	[***]
7. The Aggregate Provisional Sum Labor and Skills Price will be (decreased) by this Change Order in the amount of …………………………………………………………………………….............	[***]

8. The new Contract Price including this Change Order will be ……………….................................. $ 5,718,327,403 

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

MODIFICATION TO FTZ ZONE SITE (EXHIBIT A OF ATTACHMENT LL)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00065 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 03-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.The purpose of this Change Order is to incorporate the modified FTZ Zone Site (Foreign Trade Zone No. 122-X), as stated in Exhibit A of Attachment LL (“FTZ Agreement”) of the Agreement.

2.Therefore, the FTZ Zone Site provided in Attachment 1 of this Change Order shall supersede the previous FTZ Zone Site (which is provided in Attachment 2 of this Change Order).

3.For context, Owner informed Contractor per Owner correspondence CCLIQ3-BE-C23-079 that the United States Customs and Border Protection Agency activated the subject expanded FTZ Zone Site effective 03-Aug-2023.

Adjustment to Contract Priced
1. The original Contract Price was …………………………………………………………................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00064)….….………….	$	234,327,403
3. The Contract Price prior to this Change Order was...........................................................................	$	5,718,327,403
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of ........	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of.	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………......	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be …………………………………….	$	5,718,327,403

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

Attachment B (Contract Deliverables)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00066 DATE OF CHANGE ORDER: 02-Jun-2023 DATE OF AGREEMENT: 01-Mar-2022

The Agreement between the Parties listed above is changed as follows:

In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, the Parties agree this Change Order shall:

1.Amend Attachment B (Contract Deliverables) of the Agreement. Accordingly, Attachment 1 of this Change Order incorporates into the Agreement the revised Attachment B (Contract Deliverables); and

2.Supersede in its entirety the previous Attachment B (Contract Deliverables) as issued with the Agreement.

Adjustment to Contract Price
1. The original Contract Price was ………………………………………………………………........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00065)….….………….	$	234,327,403
3. The Contract Price prior to this Change Order was ………………………………………...............	$	5,718,327,403
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of.........	$	0
5. The Aggregate Labor and Skills Price will be (unchanged) by this Change Order in the amount of.	$	0
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,718,327,403

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: N/A

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

SHEET PILE JOINT SEALING 310Q02 SUMP

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00067 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor will add sealant to sheet pile joints as an additional measure to minimize groundwater seepage into the 310Q02 sump. For context the additional sealant is intended to reduce groundwater seepage, which must be regularly sampled and tested by Owner.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00066)….….…………….	$	234,327,403
3. The Contract Price prior to this Change Order was ………………………………………	$	5,718,327,403
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………...	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………...............	$	0
8. The new Contract Price including this Change Order will be ……………………………………...	$	5,718,484,524

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

E-HAZOP PACKAGE #2 (“PHASE ONE ITEMS”)

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00068 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 19-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.    In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, Contractor’s scope is amended to implement the following E-HAZOP resolution(s):

Item	E-HAZOP Reference	E-HAZOP Scenario see note 1	E-HAZOP Resolution
1	26290-100-U4R-DK-E0003	High Voltage (“HV”) and Medium Voltage (“MV”) switchgear circuit breakers do not have surge capacitors.	The HV/MV Switchgear vendor performed a Transient Recovery Voltage (“TRV”) study. The study validated whether surge arrestors will continue to be utilized or if surge arrestors will be replaced with surge capacitors. The study has determined that the TRV duties of the HV & MV switchgear circuit breakers are within the capabilities of the rated circuit breakers. Therefore, surge capacitors are not required.

2	26290-100-U4R-DK-E0004	Substation Common Alarm from building Annunciator Panel.	The following are the substation alarms to be displayed on the Distributed Control System (“DCS”) operator’s workstation. Alarms shown on the miscellaneous P&ID 26290-100-M6-3010-00020. Each Liquefaction Substation: 1. Common Alarm 2. Fire Alarm 3. Fire System Common Alarm 4. NOVEC System Alarm 5. UPS Alarm 6. Switchgear Control Power Failure 7. Switchgear Common Alarm 8. Transformer Alarm 9. HVAC Alarm 10. LV Ground Fault 11. MR Compressor VFD Alarm Each Utility Substation: 1. Common Alarm 2. Fire Alarm 3. Fire System Common Alarm 4. NOVEC System Alarm 5. UPS Alarm 6. Switchgear Control Power Failure 7. Switchgear Common Alarm 8. Transformer Alarm 9. HVAC Alarm 10. LV Ground Fault 11. Standby System Alarm Main Substation 30A-4000): 1. Common Alarm 2. Fire Alarm 3. Fire System Common Alarm 4. NOVEC System Alarm 5. UPS Alarm 6. Switchgear PT Failure 7. Switchgear Control Power Failure 8. Switchgear Main or Tie Common Alarm 9. Switchgear Feeder Common Alarm 10. HVAC Alarm
3	26290-100-U4R-DK-E0010	Partial Differential (Overcurrent) Protection on 13.8kV Bus	Full Differential (High Impedance) Protection on 13.8kV Bus.

4	26290-100-U4R-DK-E0017	Essential Low Voltage Motor Control Center (“LV MCC”) designed with Automatic transfer switch (“ATS”) as done in CCL Stage 1/2.	Add a separate incomer breaker to the essential LV MCC to prevent standby diesel generator (“SBDG”) from closing on bus fault.
5	26290-100-U4R-DK-E0018	Essential LV MCC designed with ATS as done in CCL Stage 1/2.	Add a separate incomer breaker to the essential LV MCC in place of an ATS which is required to be taken out of service for routine maintenance.
6	26290-100-U4R-DK-E0019	Essential LV MCC designed with ATS as done in CCL Stage 1/2.	Add a separate incomer breaker to the essential LV MCC in place of an ATS which is required to be taken out of service for routine maintenance. A breaker status for the Liquefaction Substation LV MCC essential incomer added and alarm to the DCS if open.
7	26290-100-U4R-DK-E0020	Substation Common Alarm from building Annunciator Panel	Provide a separate alarm to indicate Emergency Diesel Generator (“EDG”) failure to start, and the alarm to the DCS.
8	26290-100-U4R-DK-E0022	Essential LV MCC designed with ATS as done in CCL Stage 1/2.	Add a separate incomer breaker to the essential LV MCC to support the Generator Control Panel (“GCP”) starting on loss of bus voltage.
9	26290-100-U4R-DK-E0023	Diesel Generator (“DG”) load testing to be exercised on essential LV MCC.	DG load testing to be exercised on essential LV MCC. In addition, provisions for future load bank and test breaker included.
10	26290-100-U4R-DK-E0024	A single feed from the uninterruptible power system (“UPS”) to the UPS Distribution panels.	A separate feed from the UPS to each UPS Distribution panel added.
11	26290-100-U4R-DK-E0027	As done on CCL 1/2 connection of a temporary battery bank during the UPS battery load testing requires a hot work permit.	Add a separate battery disconnect switch and a separate temporary battery connection disconnect switch to support annual UPS testing.
12	26290-100-U4R-DK-E0028	As done on CCL 1/2 connection of a temporary battery bank during the 125V Direct Current (“DC”) Charger battery load testing requires a hot work permit.	A separate battery disconnect switch and a separate temporary battery connection disconnect switch added to support annual 125V DC Charger testing.
13	26290-100-U4R-DK-E1002	Diesel generator power cables routed in piperack tray.	Diesel generator power cables routed in underground ductbank.

Note 1 The table only describes each HAZOP scenario at a summary level.

2.    The detailed cost breakdown for each item is detailed in Exhibit A of this Change Order, together with a summary table.

3.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………......	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00067)…..….………....	$	234,484,524
3. The Contract Price prior to this Change Order was …………………………………......................................	$	5,718,484,524
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of..................	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of ………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be …………………………………....	$	5,723,770,387

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

PACKAGE 6 FEED GAS PIPELINE AND PIG RECEIVER DMM

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00069 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 03-Aug-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”), Owner has requested the modification of the foundation support method for the Feed Gas Pipeline, Pig Receiver area and associated interface pipeline (“Package 6 Area”):

1.1    Contractor’s scope, as previously amended to provide piling (per Change Order CO-00015), is further amended to now provide the design and installation of deep mix method soil improvement (“DMM”) for the Package 6 Area. A general illustration of Package 6 Area DMM is provided in Attachment 1 of this Change Order.

2.     For context:

2.1    Earlier Change Order CO-00011 descoped from Contractor the entirety of Package 6 (“Pig Receiver and Launcher”) of Attachment NN (“Scoping Adjustments”);

2.2    Subsequent Change Order CO-00015 added certain Package 6 Area interface scopes, including, the provision of such piles which have not yet been installed. Therefore, this Change Order includes a budgetary reconciliation for such piles; and

2.3    For the avoidance of doubt only the piling included in Change Order CO-00015 is amended in this Change Order.

3.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………………….........	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00068)……..……...........	$	239,770,387
3. The Contract Price prior to this Change Order was ………………………………………................	$	5,723,770,387
4. The Aggregate Equipment Price will be (unchanged) by this Change Order in the amount of..........	$	0
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of...	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………..............……………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………..............	$	0
8. The new Contract Price including this Change Order will be ………………………………....…....	$	5,727,386,023

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

DRY FLARE KNOCKOUT DRUM SPILL PAD DRAIN SPECIFICATION CHANGE

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00070 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 05-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams, the scope is amended as follows:

1.1    The HDPE material drainpipe from the Dry Flare Knockout Drum spill pad will be replaced with stainless steel pipe and stainless steel valves;

1.2    Downstream of the stainless steel valves, the HDPE pipe will also be revised to carbon steel; and

1.3    Additionally, cathodic protection and valve boxes will be installed to support the new underground metallic pipe.

2.For context, utilization of stainless steel materials is intended to mitigate against HDPE embrittlement and the loss of containment of cryogenic fluid, and is in response to PHMSA’s request to Owner.

3.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………..................	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00069)….….……………	$	243,386,023
3. The Contract Price prior to this Change Order was ……………………………………….................	$	5,727,386,023
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of.............	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of....	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………....	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be …………………………………….....	$	5,727,958,808

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

VIEWING PLATFORM PILES

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc CHANGE ORDER NUMBER: CO-00071 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 18-Oct-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) the scope of the Agreement is amended at Owner’s request to provide certain scope for Owner’s Viewing Platform project, as follows:

a)    Provide a Geotechnical Design Basis Report (26290-200-3DR-K04F-00002) inclusive of reviewing existing surface and sub-surface ground conditions, consideration of seismic design parameters and a recommendation on an alternative design for the pile type; and

b)    Supply and installation of piles.

2.The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

3.Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone(s) listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was …………………………………………………………...............	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00070).…….………….	$	243,958,808
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,727,958,808
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………..............	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………..........................	$	0
8. The new Contract Price including this Change Order will be ………………………………..........	$	5,728,319,702

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

CHANGE ORDER

SITE PLAN UPDATE PACKAGE #1 – RE-ROUTE CONTRACTOR’S UTILITY WATER & NITROGEN PIPELINES AND PROVIDE POWER & FIBER CABLES TO NITROGEN TIE-IN POINT

PROJECT NAME: Corpus Christi Liquefaction Stage 3 Project OWNER: Corpus Christi Liquefaction, LLC CONTRACTOR: Bechtel Energy Inc. CHANGE ORDER NUMBER: CO-00072 DATE OF AGREEMENT: 01-Mar-2022 DATE OF CHANGE ORDER: 02-Nov-2023

The Agreement between the Parties listed above is changed as follows:

1.In accordance with Section 6.1 of the Agreement (“Owner’s Right to Change Order”) and as requested by Owner’s teams to support Owner’s underground natural gas feedstock pipeline project, Contractor will:

1.1    Contractor will relocate from the existing nitrogen tie-in point to a new interface point at the Air Liquide pipeline. As part of this relocation effort, Owner has also requested that certain power and fiber connections are provided to the new location (note: power is only provided up to the Distribution Panel); and

1.2    Accommodations for Owner’s construction laydown for the underground natural gas feedstock pipeline project will require Contractor to re-route Contractor’s current Utility Water (UW) and Nitrogen (N2) pipeline.

2.    An illustrative scope sketch showing the current and revised location(s) is provided in Attachment 1 of this Change Order.

3.    The detailed cost breakdown for this Change Order is detailed in Exhibit A of this Change Order.

4.    Schedule C-1 Aggregate Labor and Skills Price Monthly Payment Schedule and C-3 Aggregate Equipment Price Payment Milestones of Attachment C of the Agreement will be amended by including the milestone listed in Exhibit 1 of this Change Order.

Adjustment to Contract Price
1. The original Contract Price was ……………………………………………………………….......	$	5,484,000,000
2. Net change by previously authorized Change Orders (# CO-00001 – CO-00071)……..………….	$	244,319,702
3. The Contract Price prior to this Change Order was ………………………………………..............	$	5,728,319,702
4. The Aggregate Equipment Price will be (increased) by this Change Order in the amount of...........	[***]
5. The Aggregate Labor and Skills Price will be (increased) by this Change Order in the amount of .	[***]
6. The Aggregate Provisional Sum Equipment Price will be (unchanged) by this Change Order in the amount of …………………………………………………………………………………………..	$	0
7. The Aggregate Provisional Sum Labor and Skills Price will be (unchanged) by this Change Order in the amount of ..…………………………………………………………………………................	$	0
8. The new Contract Price including this Change Order will be ……………………………………..	$	5,735,673,384

The following dates are modified (list all dates modified; insert N/A if no dates modified): N/A

Impact to other Changed Criteria (insert N/A if no changes or impact; attach additional documentation if necessary)

Adjustment to Payment Schedule: Yes; see Exhibit 1 of this Change Order.

Adjustment to Minimum Acceptance Criteria: N/A

Adjustment to Performance Guarantees: N/A

Adjustment to Basis of Design: N/A

Adjustment to Attachment CC (Equipment List): To be updated on a quarterly basis

Other adjustments to liability or obligation of Contractor or Owner under the Agreement: N/A

Select either A or B:

[A] This Change Order shall constitute a full and final settlement and accord and satisfaction of all effects of the change reflected in this Change Order upon the Changed Criteria and shall be deemed to compensate Contractor fully for such change. Initials: /s/ SS Contractor /s/ DC Owner

[B] This Change Order shall not constitute a full and final settlement and accord and satisfaction of all effects of the changereflected in this Change Order upon the Changed Criteria and shall not be deemed to compensate Contractor fully for suchchange. Initials: _______Contractor _________Owner

Upon execution of this Change Order by Owner and Contractor, the above-referenced change shall become a valid and binding part of the original Agreement without exception or qualification, unless noted in this Change Order. Except as modified by this and any previously issued Change Orders, all other terms and conditions of the Agreement shall remain in full force and effect. This Change Order is executed by each of the Parties’ duly authorized representatives.

CORPUS CHRISTI LIQUEFACTION, LLC

By:_____/s/_David Craft______________________________

Name:___David Craft________________________________

Title:_____SVP E&C_________________________________

BECHTEL ENERGY INC.

By:___/s/ Steve Smith_________________________________

Name: Steve Smith _______________________________

Title: Senior Project Manager and Principal Vice President

EX-21.1

Exhibit 21.1

Subsidiaries of the Registrant as of December 31, 2023

Entity Name	Jurisdiction of Incorporation
CCL Midscale 8-9, LLC	Delaware
Cheniere ADCC Investments, LLC	Delaware
Cheniere CCH HoldCo I, LLC	Delaware
Cheniere CCH HoldCo II, LLC	Delaware
Cheniere Corpus Christi Holdings, LLC	Delaware
Cheniere Corpus Christi Pipeline, L.P.	Delaware
Cheniere Creole Trail Pipeline, L.P.	Delaware
Cheniere Energy Investments, LLC	Delaware
Cheniere Energy Operating Co., Inc.	Delaware
Cheniere Energy Partners GP, LLC	Delaware
Cheniere Energy Partners LP Holdings, LLC	Delaware
Cheniere Energy Partners, L.P.	Delaware
Cheniere Energy Shared Services, Inc.	Delaware
Cheniere Financial Services, LLC	Delaware
Cheniere Foundation (fka Cheniere Cares, Inc.)	Texas
Cheniere GP Holding Company, LLC	Delaware
Cheniere Ingleside Marine Terminal, LLC	Delaware
Cheniere Land Holdings, LLC	Delaware
Cheniere Liquids, LLC	Delaware
Cheniere LNG O&M Services, LLC	Delaware
Cheniere LNG Terminals, LLC	Delaware
Cheniere Low Carbon Ventures, LLC	Delaware
Cheniere Major Project Development, LLC	Delaware
Cheniere Marketing Holdco, LLC	Delaware
Cheniere Marketing International, LLP	United Kingdom
Cheniere Marketing, LLC	Delaware
Cheniere Marketing, Ltd.	United Kingdom
Cheniere Marketing PTE Ltd.	Singapore
Cheniere Midship Holdings, LLC	Delaware
Cheniere Midstream Holdings, Inc.	Delaware
Cheniere Operating, LLC	Delaware
Cheniere Pipeline GP Interests, LLC	Delaware
Cheniere Project Construction, LLC	Delaware
Cheniere SPH Pipeline, LLC	Delaware
Cheniere Supply & Marketing, Inc.	Delaware
Corpus Christi Liquefaction, LLC	Delaware
Corpus Christi Liquefaction Stage II, LLC	Delaware

Entity Name	Jurisdiction of Incorporation
Corpus Christi Liquefaction Stage IV, LLC	Delaware
Corpus Christi Pipeline GP, LLC	Delaware
Corpus Christi Tug Services, LLC	Delaware
Gregory Power Holdings, LLC	Delaware
Gregory Power Investments, LLC	Delaware
Gregory Power Partners, LLC	Delaware
Midship Holdings, LLC	Delaware
Midship Pipeline Company, LLC	Delaware
Sabine Crossing, LLC	Delaware
Sabine Pass Carbon Solutions, LLC	Delaware
Sabine Pass Liquefaction, LLC	Delaware
Sabine Pass Liquefaction Stage V, LLC	Delaware
Sabine Pass LNG-GP, LLC	Delaware
Sabine Pass LNG-LP, LLC	Delaware
Sabine Pass LNG, L.P.	Delaware
Sabine Pass Project Development, LLC	Delaware
Sabine Pass Tug Services, LLC	Delaware
Texas Gulf Coast Header, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statements (No. 333-171736) on Form S-3 and (Nos. 333-175297, 333-186451, 333-207651, and 333-238261) on Form S-8 of our reports dated February 21, 2024, with respect to the consolidated financial statements of Cheniere Energy, Inc. and the effectiveness of internal control over financial reporting.

/s/ KPMG LLP

KPMG LLP

Houston, TX

February 21, 2024

EX-31.1

Exhibit 31.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Jack A. Fusco, certify that:

1.    I have reviewed this annual report on Form 10-K of Cheniere Energy, Inc.;

2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.    The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)    Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2024 

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-31.2

Exhibit 31.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO RULE 13a-14(a) AND 15d-14(a) UNDER THE EXCHANGE ACT

I, Zach Davis, certify that:

1.    I have reviewed this annual report on Form 10-K of Cheniere Energy, Inc.;

2.     Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.     Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.     The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)     Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)     Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)     Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;

d)     Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.     The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)     All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)     Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: February 21, 2024

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

EX-32.1

Exhibit 32.1

CERTIFICATION BY CHIEF EXECUTIVE OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Cheniere Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Jack A. Fusco, Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 21, 2024 

/s/ Jack A. Fusco

Jack A. Fusco
Chief Executive Officer of

Cheniere Energy, Inc.

EX-32.2

Exhibit 32.2

CERTIFICATION BY CHIEF FINANCIAL OFFICER

PURSUANT TO 18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the annual report of Cheniere Energy, Inc. (the “Company”) on Form 10-K for the year ended December 31, 2023, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Zach Davis, Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to § 906 of the Sarbanes-Oxley Act of 2002, to my knowledge, that:

(1)    The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2)    The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date: February 21, 2024 

/s/ Zach Davis

Zach Davis
Chief Financial Officer of

Cheniere Energy, Inc.

EX-97

Exhibit 97

CHENIERE ENERGY, INC. CLAWBACK POLICY

I. BACKGROUND

    Cheniere Energy, Inc. (the “Company”) has adopted this policy (this “Policy”) to provide for the recovery or “clawback” of certain incentive compensation in the event of a Restatement. This Policy is intended to comply with, and will be interpreted to be consistent with, the requirements of Section 303A.14 of the New York Stock Exchange (“NYSE”) Listed Company Manual(the “Listing Standard”). Certain terms used in this Policy are defined in Section VIII below.

II. STATEMENT OF POLICY

    The Company shall recover reasonably promptly the amount of erroneously awarded Incentive-Based Compensation in the event that the Company is required to prepare an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period (a “Restatement”). For the avoidance of doubt, a Restatement does not include situations in which financial statement changes did not result from material non-compliance with financial reporting requirements, such as, but not limited to retrospective: (i) application of a change in accounting principles, (ii) revision to reportable segment information due to a change in the structure of the Company’s internal organization, (iii) reclassification due to a discontinued operation, (iv) application of a change in reporting entity, such as from a reorganization of entities under common control, (v) adjustment to provision amounts in connection with a prior business combination and (vi) revision for stock splits, stock dividends, reverse stock splits or other changes in capital structure.

The Company shall recover erroneously awarded Incentive-Based Compensation in compliance with this Policy except to the extent provided under Section V below.

III. SCOPE OF POLICY

A. Covered Persons and Recovery Period. This Policy applies to Incentive-Based Compensation received by a person where all of the following are met:

•after beginning service as an Executive Officer,

•who served as an Executive Officer at any time during the performance period for that Incentive-Based Compensation,

•while the Company has a class of securities listed on a national securities exchange, and

•during the three completed fiscal years immediately preceding the date that the Company is required to prepare a Restatement (the “Recovery Period”).

    Notwithstanding this look-back requirement, the Company is only required to apply this Policy to Incentive-Based Compensation received on or after October 2, 2023.

    For purposes of this Policy, Incentive-Based Compensation shall be deemed “received” in the Company’s fiscal period during which the Financial Reporting Measure (as defined herein)

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specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period.

B. Transition Period. In addition to the Recovery Period, this Policy applies to any transition period (that results from a change in the Company’s fiscal year) within or immediately following the Recovery Period (a “Transition Period”), provided that a Transition Period between the last day of the Company’s previous fiscal year end and the first day of the Company’s new fiscal year that comprises a period of nine to 12 months

will be deemed a completed fiscal year.

C. Determining Recovery Period and Method of Recovery. For purposes of determining the relevant Recovery Period, the date that the Company is required to prepare the Restatement is the earlier to occur of:

•the date the board of directors of the Company (the “Board”), a committee of the Board, or the officer or officers of the Company authorized to take such action if Board action is not required, concludes, or reasonably should have concluded, that the Company is required to prepare a Restatement, and

•the date a court, regulator, or other legally authorized body directs the Company to prepare a Restatement.

For clarity, the Company’s obligation to recover erroneously awarded Incentive-Based Compensation under this Policy is not dependent on if or when a Restatement is filed.

Without limiting this Section III, the Compensation Committee of the Company’s Board (the “Committee”) will have discretion in determining how to accomplish recovery of erroneously awarded Incentive-Based Compensation under this Policy, recognizing that different means of recovery may be appropriate in different circumstances.

IV. AMOUNT SUBJECT TO RECOVERY

    A. Recoverable Amount.The amount of Incentive-Based Compensation subject to recovery under this Policy is the amount of Incentive-Based Compensation received that exceeds the amount of Incentive-Based Compensation that otherwise would have been received had it been determined based on the restated amounts, computed without regard to any taxes paid.

B.Covered Compensation Based on Stock Price or TSR. For Incentive-Based Compensation based on stock price or total shareholder return (“TSR”), where the amount of erroneously awarded Incentive-Based Compensation is not subject to mathematical recalculation directly from the information in a Restatement, the recoverable amount shall be determined by the Committee based on a reasonable estimate of the effect of the Restatement on the stock price or TSR upon which the Incentive-Based Compensation was received. In such event, the Company shall maintain documentation of the determination of that reasonable estimate and provide such documentation to NYSE.

V. EXCEPTIONS

    The Company shall recover erroneously awarded Incentive-Based Compensation in compliance with this Policy except to the extent that the conditions set out below are met and the Committee has made a determination that recovery would be impracticable:

-2-

    A. Direct Expense Exceeds Recoverable Amount.The direct expense paid to a third party to assist in enforcing this Policy would exceed the amount to be recovered.

    B. Recovery from Certain Tax-Qualified Retirement Plans. Recovery would

likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of 26 U.S.C. 401(a)(13) or 26 U.S.C. 411(a) and regulations thereunder.

C.Violation of Law. Recovery would violate home country law adopted prior to November 28, 2022.

In the case of clause (A), before concluding it would be impracticable to recover any amount of erroneously awarded Incentive-Based Compensation based on expense of enforcement, the Company shall make a reasonable attempt to recover such erroneously awarded Incentive-Based Compensation, document such reasonable attempt(s) to recover, and provide that documentation to NYSE; and in the case of clause (C), before concluding it would be impracticable to recover any amount of erroneously awarded compensation based on violation of home country law, obtain an opinion of home country counsel, acceptable to NYSE, that recovery would result in such a violation and provide that

opinion to NYSE.

VI. PROHIBITION AGAINST INDEMNIFICATION

    Notwithstanding the terms of any indemnification arrangement or insurance policy with any individual covered by this Policy, the Company shall not indemnify any Executive Officer or former Executive Officer against the loss of erroneously awarded Incentive-Based Compensation, including any payment or reimbursement for the cost of insurance obtained by any such covered individual to fund amounts recoverable under this Policy.

VII. DISCLOSURE

    The Company shall file all disclosures with respect to this Policy and recoveries under this Policy in accordance with the requirements of the U.S. Federal securities laws, including the disclosure required by the applicable Securities and Exchange Commission (“SEC”) filings.

VIII. DEFINITIONS

Unless the context otherwise requires, the following definitions apply for purposes of this Policy:

    “Executive Officer” meansthe individuals identified in accordance with Section 303A.14 of the Listing Standard.

    “Financial Reporting Measures” means any of the following: (i) measures that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measures that are derived wholly or in part from such measures (including “non-GAAP” financial measures), (ii) stock price and (iii) TSR. A Financial Reporting Measure need not be presented within the Company’s financial statements or included in a filing with the SEC.

    “Incentive-Based Compensation”means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure; however it does not include (i) base salaries, (ii) discretionary cash bonuses, (iii) cash or equity-based awards that are

-3-

based upon subjective, strategic or operational standards and (iv) equity-based awards that vest solely on the passage of time.

IX. ADMINISTRATION; AMENDMENT; TERMINATION

This Policy will be administered by the Committee. Any determinations of the Committee will be final, binding and conclusive and need not be uniform with respect to each individual covered by this Policy.

    The Committee may amend this Policy from time to time and may terminate this Policy at any time, in each case in its sole discretion.

X. EFFECTIVENESS; OTHER RECOUPMENT RIGHTS

This Policy shall be effective as amended on February 5, 2024. Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to the Company and its subsidiaries and affiliates under applicable law or pursuant to the terms of any similar policy or similar provision in any employment agreement, equity award agreement or similar agreement.

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XML

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	001-16383
Entity Registrant Name	CHENIERE ENERGY, INC.
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	95-4352386
Entity Address, Address Line One	845 Texas Avenue
Entity Address, Address Line Two	Suite 1250
Entity Address, City or Town	Houston
Entity Address, State or Province	TX
Entity Address, Postal Zip Code	77002
City Area Code	713
Local Phone Number	375-5000
Title of 12(b) Security	Common Stock, $ 0.003 par value
Trading Symbol	LNG
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false
Entity Shell Company	false
Entity Public Float			$ 36,500
Entity Common Stock, Shares Outstanding		234,692,274
Documents Incorporated by Reference	The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.
Entity Central Index Key	0000003570
Amendment Flag	false
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	Houston, Texas
Auditor Firm ID	185

XML

Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Revenues
Revenues		$ 20,394	$ 33,428	$ 15,864
Operating costs and expenses
Cost of sales (excluding items shown separately below)		1,356	25,632	13,773
Operating and maintenance expense		1,835	1,681	1,444
Selling, general and administrative expense		474	416	325
Depreciation and amortization expense		1,196	1,119	1,011
Other		44	21	12
Total operating costs and expenses		4,905	28,869	16,565
Income (loss) from operations		15,489	4,559	(701)
Other income (expense)
Interest expense, net of capitalized interest		(1,141)	(1,406)	(1,438)
Gain (loss) on modification or extinguishment of debt		15	(66)	(116)
Interest and dividend income		211	57	3
Other income (expense), net		4	(50)	(26)
Total other expense		(911)	(1,465)	(1,577)
Income (loss) before income taxes and non-controlling interest		14,578	3,094	(2,278)
Less: income tax provision (benefit)		2,519	459	(713)
Net income (loss)		12,059	2,635	(1,565)
Less: net income attributable to non-controlling interest		2,178	1,207	778
Net income (loss) attributable to common stockholders		$ 9,881	$ 1,428	$ (2,343)
Net income (loss) per share attributable to common stockholders—basic (1)	[1]	$ 40.99	$ 5.69	$ (9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	[1]	$ 40.72	$ 5.64	$ (9.25)
Weighted average number of common shares outstanding—basic		241.0	251.1	253.4
Weighted average number of common shares outstanding—diluted		242.6	253.4	253.4
LNG [Member]
Revenues
Revenues		$ 19,569	$ 31,804	$ 15,395
Regasification [Member]
Revenues
Revenues		135	1,068	269
Other [Member]
Revenues
Revenues		$ 690	$ 556	$ 200

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

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Current assets
Cash and cash equivalents	$ 4,066	[1]	$ 1,353
Restricted cash and cash equivalents	459	[1]	1,134
Trade and other receivables, net of current expected credit losses	1,106		1,944
Inventory	445		826
Current derivative assets	141		120
Margin deposits	18		134
Other current assets, net	96		97
Total current assets	6,331		5,608
Property, plant and equipment, net of accumulated depreciation	32,456		31,528
Operating lease assets	2,641		2,625
Derivative assets	863		35
Deferred tax assets	26		864
Other non-current assets, net	759		606
Total assets	43,076	[1]	41,266
Current liabilities
Accounts payable	181		124
Accrued liabilities	1,780		2,679
Current debt, net of discount and debt issuance costs	300		813
Deferred revenue	179		234
Current operating lease liabilities	655		616
Current derivative liabilities	750		2,301
Other current liabilities	43		28
Total current liabilities	3,888		6,795
Long-term debt, net of discount and debt issuance costs	23,397		24,055
Operating lease liabilities	1,971		1,971
Finance lease liabilities	467		494
Derivative liabilities	2,378		7,947
Deferred tax liabilities	1,545		0
Other non-current liabilities	410		175
Commitments and contingencies (see Note 20)
Stockholders’ equity (deficit)
Preferred stock: $0.0001 par value, 5.0 million shares authorized, none issued	0		0
Common stock: $0.003 par value, 480.0 million shares authorized; 277.9 million shares and 276.7 million shares issued at December 31, 2023 and 2022, respectively	1		1
Treasury stock: 40.9 million shares and 31.2 million shares at December 31, 2023 and 2022, respectively, at cost	(3,864)		(2,342)
Additional paid-in-capital	4,377		4,314
Accumulated income (deficit)	4,546		(4,942)
Total Cheniere stockholders’ equity (deficit)	5,060		(2,969)
Non-controlling interest	3,960		2,798
Total stockholders’ equity (deficit)	9,020		(171)
Total liabilities and stockholders’ equity (deficit)	$ 43,076	[1]	$ 41,266

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

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Consolidated Balance Sheets Parentheticals - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Assets	$ 43,076	[1]	$ 41,266
Cash and cash equivalents	$ 4,066	[1]	$ 1,353
Preferred Stock, Par Value	$ 0.0001		$ 0.0001
Preferred Stock, Shares Authorized	5,000,000		5,000,000
Preferred Stock, Shares Issued	0		0
Common Stock, Par Value Per Share	$ 0.003		$ 0.003
Common stock, Shares Authorized	480,000,000		480,000,000
Common Stock, Shares, Issued	277,900,000		276,700,000
Restricted cash and cash equivalents	$ 459	[1]	$ 1,134
Treasury Stock
Treasury Stock, Common	40,900,000		31,200,000
CQP [Member]
Assets	$ 17,740		$ 18,905
Liabilities	18,805		21,664
Cash and cash equivalents	575		904
Restricted cash and cash equivalents	$ 56		$ 92

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

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Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Millions	Total	Common Stock	Treasury Stock	Additional Paid-in Capital	Accumulated Income (Deficit)	Non-controlling Interest
Common Stock, Shares, Outstanding, Beginning of Period at Dec. 31, 2020		252,300
Treasury Stock, Shares, Beginning of Period at Dec. 31, 2020			20,800
Stockholders' Equity, Beginning of Period at Dec. 31, 2020	$ 2,218	$ 1	$ (872)	$ 4,273	$ (3,593)	$ 2,409
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Vesting of share-based compensation awards, shares		2,100	0
Vesting of share-based compensation awards	0	$ 0	$ 0	0	0	0
Share-based compensation	105	$ 0	$ 0	105	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock		(700)
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares			700
Issued shares withheld from employees related to share-based compensation, at cost	$ (48)	$ 0	$ (47)	(1)	0	0
Shares repurchased, at cost, shares	100	(100)	100
Shares repurchased, at cost	$ (9)	$ 0	$ (9)	0	0	0
Net income attributable to non-controlling interest	778	0	0	0	0	778
Distributions to non-controlling interest	(649)	0	0	0	0	(649)
Dividends declared	(85)	0	0	0	(85)	0
Net income (loss) attributable to common stockholders	(2,343)	$ 0	$ 0	0	(2,343)	0
Common Stock, Shares, Outstanding, End of Period at Dec. 31, 2021		253,600
Treasury Stock, Shares, End of Period at Dec. 31, 2021			21,600
Stockholders' Equity, End of Period at Dec. 31, 2021	$ (33)	$ 1	$ (928)	4,377	(6,021)	2,538
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 0.33
Vesting of share-based compensation awards, shares		1,500	0
Vesting of share-based compensation awards	$ 0	$ 0	$ 0	0	0	0
Share-based compensation	112	$ 0	$ 0	112	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock		(300)
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares			300
Issued shares withheld from employees related to share-based compensation, at cost	$ (63)	$ 0	$ (41)	(22)	0	0
Shares repurchased, at cost, shares	9,350	(9,300)	9,300
Shares repurchased, at cost	$ (1,373)	$ 0	$ (1,373)	0	0	0
Reacquisition of equity component of convertible notes, net of tax	(149)	0	0	(153)	4	0
Net income attributable to non-controlling interest	1,207	0	0	0	0	1,207
Distributions to non-controlling interest	(947)	0	0	0	0	(947)
Dividends declared	(353)	0	0	0	(353)	0
Net income (loss) attributable to common stockholders	1,428	$ 0	$ 0	0	1,428	0
Common Stock, Shares, Outstanding, End of Period at Dec. 31, 2022		245,500
Treasury Stock, Shares, End of Period at Dec. 31, 2022			31,200
Stockholders' Equity, End of Period at Dec. 31, 2022	$ (171)	$ 1	$ (2,342)	4,314	(4,942)	2,798
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 1.385
Vesting of share-based compensation awards, shares		1,200	0
Vesting of share-based compensation awards	$ 0	$ 0	$ 0	0	0	0
Share-based compensation	100	$ 0	$ 0	100	0	0
Shares withheld from employees related to share-based compensation, at cost, shares, common stock		(200)
Issued shares withheld from employees related to share-based compensation, at cost, shares, treasury shares			200
Issued shares withheld from employees related to share-based compensation, at cost	$ (63)	$ 0	$ (26)	(37)	0	0
Shares repurchased, at cost, shares	9,540	(9,500)	9,500
Shares repurchased, at cost	$ (1,496)	$ 0	$ (1,496)	0	0	0
Net income attributable to non-controlling interest	2,178	0	0	0	0	2,178
Distributions to non-controlling interest	(1,016)	0	0	0	0	(1,016)
Dividends declared	(393)	0	0	0	(393)	0
Net income (loss) attributable to common stockholders	9,881	$ 0	$ 0	0	9,881	0
Common Stock, Shares, Outstanding, End of Period at Dec. 31, 2023		237,000
Treasury Stock, Shares, End of Period at Dec. 31, 2023			40,900
Stockholders' Equity, End of Period at Dec. 31, 2023	$ 9,020	$ 1	$ (3,864)	$ 4,377	$ 4,546	$ 3,960
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Common Stock, Dividends, Per Share, Declared	$ 1.62

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash flows from operating activities
Net income (loss)	$ 12,059	$ 2,635	$ (1,565)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Unrealized foreign currency exchange gain, net	(2)	(5)	0
Depreciation and amortization expense	1,196	1,119	1,011
Share-based compensation expense	250	205	140
Amortization of debt issuance costs, premium and discount	44	57	72
Reduction of right-of-use assets	623	607	393
Loss (gain) on modification or extinguishment of debt	(15)	66	116
Total losses (gains) on derivative instruments, net	(7,890)	6,531	5,989
Net cash used for settlement of derivative instruments	(79)	(904)	(1,579)
Deferred taxes	2,389	440	(715)
Repayment of paid-in-kind interest related to repurchase of convertible notes	0	(13)	(190)
Other, net	20	92	52
Changes in operating assets and liabilities:
Trade and other receivables	840	(502)	(799)
Inventory	377	(123)	(409)
Margin deposits	116	631	(741)
Accounts payable and accrued liabilities	(982)	250	1,144
Total deferred revenue	3	124	55
Total operating lease liabilities	(607)	(622)	(418)
Other, net	76	(65)	(87)
Net cash provided by operating activities	8,418	10,523	2,469
Cash flows from investing activities
Property, plant and equipment, net	(2,121)	(1,830)	(966)
Proceeds from sale of property, plant and equipment	0	1	68
Investment in equity method investments	(61)	(15)	0
Other, net	(20)	0	(14)
Net cash used in investing activities	(2,202)	(1,844)	(912)
Cash flows from financing activities
Proceeds from issuances of debt	1,397	1,575	5,911
Redemptions, repayments and repurchases of debt	(2,598)	(6,771)	(6,810)
Distributions to non-controlling interest	(1,016)	(947)	(649)
Payments related to tax withholdings for share-based compensation	(63)	(63)	(48)
Repurchase of common stock	(1,473)	(1,373)	(9)
Dividends to stockholders	(393)	(349)	(85)
Other, net	(34)	(86)	(127)
Net cash used in financing activities	(4,180)	(8,014)	(1,817)
Effect of exchange rate changes on cash, cash equivalents and restricted cash and cash equivalents	2	5	0
Net increase (decrease) in cash, cash equivalents and restricted cash and cash equivalents	2,038	670	(260)
Cash, cash equivalents and restricted cash and cash equivalents—beginning of period	2,487	1,817	2,077
Cash, cash equivalents and restricted cash and cash equivalents—end of period	$ 4,525	$ 2,487	$ 1,817

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Consolidated Statements of Cash Flows - Balances per Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Balances per Consolidated Balance Sheets:
Cash and cash equivalents	$ 4,066	[1]	$ 1,353
Restricted cash and cash equivalents	459	[1]	1,134
Total cash, cash equivalents and restricted cash and cash equivalents	$ 4,525		$ 2,487	$ 1,817	$ 2,077

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

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Organization and Nature of Operations

12 Months Ended

Dec. 31, 2023

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Organization and Nature of Operations

ORGANIZATION AND NATURE OF OPERATIONS

We operate two natural gas liquefaction and export facilities located in Cameron Parish, Louisiana at Sabine Pass and near Corpus Christi, Texas (respectively, the “Sabine Pass LNG Terminal” and “Corpus Christi LNG Terminal”).

CQP owns the Sabine Pass LNG Terminal, which has natural gas liquefaction facilities consisting of six operational Trains, for a total production capacity of approximately 30 mtpa of LNG (the “SPL Project”). The Sabine Pass LNG Terminal also has operational regasification facilities that include five LNG storage tanks, vaporizers and three marine berths. We also own and operate a 94-mile natural gas supply pipeline that interconnects the Sabine Pass LNG Terminal with several interstate and intrastate pipelines (the “Creole Trail Pipeline”). As of December 31, 2023, we owned 100% of the general partner interest, a 48.6% limited partner interest and 100% of the incentive distribution rights of CQP.

The Corpus Christi LNG Terminal currently has three operational Trains for a total production capacity of approximately 15 mtpa of LNG, three LNG storage tanks and two marine berths. Additionally, we are constructing an expansion of the Corpus Christi LNG Terminal (the “Corpus Christi Stage 3 Project”) for seven midscale Trains with an expected total production capacity of over 10 mtpa of LNG. We also own a 21.5-mile natural gas supply pipeline that interconnects the Corpus Christi LNG Terminal with several interstate and intrastate natural gas pipelines (the “Corpus Christi Pipeline” and together with the Trains, storage tanks, and marine berths at the Corpus Christi LNG Terminal and the Corpus Christi Stage 3 Project, the “CCL Project”).

We are pursuing expansion projects to provide additional liquefaction capacity at the SPL Project and the CCL Project (collectively, the “Liquefaction Projects”), and we have commenced commercialization to support the additional liquefaction capacity associated with these expansion projects.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

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

VIEs

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

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

Non-controlling Interests

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

recognized within equity. See Note 9—Non-controlling Interest and Variable Interest Entities for additional details about our non-controlling interest.

Estimates

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

Fair Value Measurements

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

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

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 7—Derivative Instruments, and liability-classified share-based compensation awards, as disclosed in Note 16—Share-Based Compensation.

The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 11—Debt for our debt fair value estimates, including our estimation methods.

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 13—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition.

Cash and Cash Equivalents

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

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

Current Expected Credit Losses

Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms,

the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. We record charges and reversals of current expected credit losses in selling, general and administrative in our Consolidated Statements of Operations.

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

	Year Ended December 31,
	2023		2022		2021
Current expected credit losses, beginning of period	$	5	$	9	$	7
Charges (reversals)	(2)		(4)		2
Current expected credit losses, end of period	$	3	$	5	$	9

Inventory

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

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of our LNG terminals once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary review and selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.

We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except land which is not depreciated. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.

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

We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2023, 2022 and 2021.

Advances of Cash and Conveyed Assets to Service Providers

We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances are recognized within other non-current assets on our Consolidated Balance Sheets and amortized within depreciation and amortization expense on our Consolidated Statements of Operations over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately 31 years as of both December 31, 2023 and 2022.

Interest Capitalization

We capitalize interest costs mainly during the construction period of our LNG terminals and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings. We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Leases

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

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

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

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

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

When we determine the arrangement is, or contains, a lease in which we are the lessor or sublessor, we assess classification of the lease as either an operating lease, sales-type lease or direct financing lease. All of our arrangements have been assessed as operating leases and consist of sublessor arrangements in which we have not been relieved of our primary

obligation under the original lease. Our sublessor arrangements are not recognized on our Consolidated Balance Sheets and we recognize income from these arrangements on a straight-line basis over the sublease term.

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets related to our long-term SPAs and regasification contracts, each discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits on our Consolidated Balance Sheets. Our FX derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

We have contracted our anticipated production capacity under SPAs and under IPM agreements. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers. 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. We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL’s customers through our integrated marketing function. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective agreements.

Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.

Debt

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

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method.

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

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

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

Asset Retirement Obligations

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

We have not recorded an ARO associated with the Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Share-based Compensation

We have awarded share-based compensation in the form of restricted stock shares, restricted stock units, performance stock units and phantom units. The awards and our related accounting policies are more fully described in Note 16—Share-based Compensation.

Foreign Currency

The functional currency of all of our subsidiaries is the U.S. dollar. Certain of our subsidiaries transact in currencies outside of the U.S. dollar, which gives rise to the recognition of transaction gains and losses based on the change in exchange rates between the U.S. dollar and the currency in which the foreign currency transaction is denominated. During the years ended December 31, 2023, 2022 and 2021, we recognized net transaction gains (losses) totaling $(20) million, $60 million and $33 million, respectively, substantially all of which related to commercial transactions executed by Cheniere Marketing. The transaction gains and losses on such commercial transactions primarily consisted of those on Euro denominated receivables and related foreign currency hedges arising from the sale of cargoes, which are presented within LNG revenues in our Consolidated Statements of Operations with the underlying activities. The remaining transaction gains and losses are presented primarily within other income (expense), net in our Consolidated Statements of Operations.

Income Taxes

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

As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes.

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

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

We account for our federal investment tax credits under the flow-through method.

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

Net Income (Loss) Per Share

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

Refer to Note 18—Net Income (Loss) per Share Attributable to Common Stockholders for additional details of the computation for the years ended December 31, 2023, 2022 and 2021.

Business Segment

We have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker is regularly provided with consolidated financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our customers. The financial measures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) attributable to common stockholders and total consolidated assets, as presented in our Consolidated Financial Statements.

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 11—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the

impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

ASU 2023-07

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. We plan to adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

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Restricted Cash and Cash Equivalents

12 Months Ended

Dec. 31, 2023

Restricted Cash and Cash Equivalents [Abstract]

Restricted Cash and Cash Equivalents

RESTRICTED CASH AND CASH EQUIVALENTS

As of December 31, 2023 and 2022, we had $459 million and $1.1 billion of restricted cash and cash equivalents, respectively, for which the usage or withdrawal of such cash is contractually or legally restricted, primarily to the payment of liabilities related to the Liquefaction Projects, as required under certain debt arrangements.

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Trade and Other Receivables, Net of Current Expected Credit Losses

12 Months Ended

Dec. 31, 2023

Receivables [Abstract]

Trade and Other Receivables, Net of Current Expected Credit Losses

TRADE AND OTHER RECEIVABLES, NET OF CURRENT EXPECTED CREDIT LOSSES

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

	December 31,
	2023		2022
Trade receivables
SPL and CCL	$	525	$	922
Cheniere Marketing	451		917
Other	4		4
Other receivables	126		101
Total trade and other receivables, net of current expected credit losses	$	1,106	$	1,944

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Inventory

12 Months Ended

Dec. 31, 2023

Inventory Disclosure [Abstract]

Inventory

INVENTORY

Inventory consisted of the following (in millions):

	December 31,
	2023		2022
LNG in-transit	$	112	$	356
LNG	88		212
Materials	207		194
Natural gas	35		60
Other	3		4
Total inventory	$	445	$	826

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Property, Plant and Equipment, Net of Accumulated Depreciation

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

PROPERTY, PLANT AND EQUIPMENT, NET OF ACCUMULATED DEPRECIATION

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

	December 31,
	2023		2022
Terminal and related assets
Terminal and interconnecting pipeline facilities (1)	$	34,069	$	33,815
Land	463		451
Construction-in-process	3,480		1,685
Accumulated depreciation	(6,099)		(4,985)
Total terminal and related assets, net of accumulated depreciation	31,913		30,966
Fixed assets and other
Computer and office equipment	37		33
Furniture and fixtures	31		20
Computer software	125		121
Leasehold improvements	43		48
Other	21		20
Accumulated depreciation	(183)		(191)
Total fixed assets and other, net of accumulated depreciation	74		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(63)		(22)
Total assets under finance leases, net of accumulated depreciation	469		511
Property, plant and equipment, net of accumulated depreciation	$	32,456	$	31,528

(1)Includes power generation facility and associated power infrastructure located near Corpus Christi, Texas that was acquired during the year ended December 31, 2023 to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

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

	Year Ended December 31,
	2023		2022		2021
Depreciation expense	$	1,190	$	1,113	$	1,006
Offsets to LNG terminal costs (1)	—		204		319

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Projects during the testing phase for its construction.

Terminal and related assets

Our terminal and related assets are depreciated using the straight-line depreciation method applied to groups of LNG terminal assets with varying useful lives. The identifiable components of our terminal and related assets have depreciable lives between 6 and 50 years, as follows:

Components	Useful life (years)
LNG storage tanks	50
Natural gas pipeline facilities	40
Marine berth, electrical, facility and roads	35
Water pipelines	30
Regasification processing equipment	30
Sendout pumps	20
Liquefaction processing equipment	6-50
Other	10-30

Fixed Assets and Other

Our fixed assets and other are recorded at cost and are depreciated on a straight-line method based on estimated lives of the individual assets or groups of assets.

Assets under Finance Leases

Our assets under finance leases primarily consist of certain tug vessels and LNG vessel time charters that meet the classification of a finance lease. These assets are depreciated on a straight-line method over the respective lease term. See Note 12—Leases for additional details of our finance leases.

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Derivative Instruments

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

DERIVATIVE INSTRUMENTS

We have entered into the following derivative instruments:

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

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

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

We recognize our derivative instruments as either assets or liabilities and measure those instruments at fair value. None of our derivative instruments are designated as cash flow, fair value or net investment hedging instruments, and changes in fair value are recorded within our Consolidated Statements of Operations to the extent not utilized for the commissioning process, in which case such changes are capitalized.

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

	Fair Value Measurements as of
	December 31, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	25	$	36	$	(2,178)	$	(2,117)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	30		(20)		—		10		1		(47)		—		(46)
FX Derivatives liability	—		(17)		—		(17)		—		(28)		—		(28)

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

We include a significant portion of our Liquefaction Supply Derivatives as Level 3 within the valuation hierarchy as the fair value is developed through the use of internal models which incorporate significant unobservable inputs. In instances where observable data is unavailable, consideration is given to the assumptions that market participants may use in valuing the asset or liability. To the extent valued using an option pricing model, we consider the future prices of energy units for unobservable periods to be a significant unobservable input to estimated net fair value. In estimating the future prices of energy units, we make judgments about market risk related to liquidity of commodity indices and volatility utilizing available market

data. Changes in facts and circumstances or additional information may result in revised estimates and judgments, and actual results may differ from these estimates and judgments. We derive our volatility assumptions based on observed historical settled global LNG market pricing or accepted proxies for global LNG market pricing as well as settled domestic natural gas pricing. Such volatility assumptions also contemplate, as of the balance sheet date, observable forward curve data of such indices, as well as evolving available industry data and independent studies.

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

The Level 3 fair value measurements of our natural gas positions within our Liquefaction Supply Derivatives could be materially impacted by a significant change in certain natural gas and international LNG prices. The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(2,178)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.090) - $0.505 / $(0.060)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	87% - 379% / 196%

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

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

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

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

	Year Ended December 31,
	2023		2022		2021
Balance, beginning of period	$	(9,924)	$	(4,036)	$	241
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	5,685		(5,120)		(2,509)
Included in cost of sales, new deals (3)	15		(1,373)		(1,796)
Purchases and settlements:
Purchases (4)	—		—		(1)
Settlements (5)	2,045		605		29
Transfers out of level 3 (6)	1		—		—
Balance, end of period	$	(2,178)	$	(9,924)	$	(4,036)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	5,700	$	(6,493)	$	(4,305)

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

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

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

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

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

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

All existing counterparty derivative contracts provide for the unconditional right of set-off in the event of default. We have elected to report derivative assets and liabilities arising from those derivative contracts with the same counterparty and the unconditional contractual right of set-off on a net basis. The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments, in instances when our derivative instruments are in an asset position. Additionally, counterparties are at risk that we will be unable to meet our commitments in instances where our derivative instruments are in a liability position. We incorporate both our own nonperformance risk and the respective counterparty’s nonperformance risk in fair value measurements depending on the position of the derivative. In adjusting the fair value of our derivative contracts for the effect of nonperformance risk, we have considered the impact of any applicable credit enhancements, such as collateral postings, set-off rights and guarantees.

Commodity Derivatives

SPL and CCL hold Liquefaction Supply Derivatives which are primarily indexed to the natural gas market and international LNG indices. As of December 31, 2023, the remaining fixed terms of the Liquefaction Supply Derivatives ranged up to approximately 15 years, some of which commence upon the satisfaction of certain events or states of affairs.

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

The following table shows the notional amounts of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”):

	December 31, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	14,019	49	14,504	50

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of December 31, 2023.

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location (1)		Year Ended December 31,
			2023		2022		2021
LNG Trading Derivatives	LNG revenues		$	139	$	(387)	$	(1,812)
LNG Trading Derivatives	Recovery (cost) of sales		(132)		(2)		91
Liquefaction Supply Derivatives (2)	LNG revenues		(5)		2		3
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales		7,912		(6,203)		(4,303)

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

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

FX Derivatives

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

The total notional amount of our FX Derivatives was $789 million and $619 million as of December 31, 2023 and 2022, respectively.

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location		Year Ended December 31,
			2023		2022		2021
FX Derivatives	LNG revenues		$	(24)	$	57	$	33

Fair Value and Location of Derivative Assets and Liabilities on the Consolidated Balance Sheets

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

	December 31, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	49	$	92	$	—	$	141
Derivative assets	863		—		—		863
Total derivative assets	912		92		—		1,004
Current derivative liabilities	(651)		(82)		(17)		(750)
Derivative liabilities	(2,378)		—		—		(2,378)
Total derivative liabilities	(3,029)		(82)		(17)		(3,128)
Derivative asset (liability), net	$	(2,117)	$	10	$	(17)	$	(2,124)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $3 million and $111 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $4 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $15 million and $23 million, as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $3 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

Consolidated Balance Sheets Presentation

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:

	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives
As of December 31, 2023
Gross assets	$	1,272	$	94	$	—
Offsetting amounts	(360)		(2)		—
Net assets (1)	$	912	$	92	$	—
Gross liabilities	$	(3,095)	$	(110)	$	(17)
Offsetting amounts	66		28		—
Net liabilities (2)	$	(3,029)	$	(82)	$	(17)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $141 million and $863 million, respectively, as of December 31, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $750 million and $2,378 million, respectively, as of December 31, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

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Other Non-Current Assets

12 Months Ended

Dec. 31, 2023

Other Assets, Noncurrent [Abstract]

Other Non-Current Assets

OTHER NON-CURRENT ASSETS, NET

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	244	$	171
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminals, net of accumulated amortization	175		170
Equity method investments (1)	111		16
Goodwill	77		77
Debt issuance costs and debt discount, net of accumulated amortization	58		60
Advance tax-related payments and receivables	20		20
Other, net	74		92
Total other non-current assets, net	$	759	$	606

(1)Includes investment in equity interest and capacity agreements with a pipeline developer and operator, expected to support delivery of natural gas feedstock to the Corpus Christi LNG Terminal for the Corpus Christi Stage 3 Project.

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Non-Controlling Interest and Variable Interest Entity

12 Months Ended

Dec. 31, 2023

Noncontrolling Interest and Variable Interest Entity [Abstract]

Non-Controlling Interest and Variable Interest Entity

NON-CONTROLLING INTEREST AND VARIABLE INTEREST ENTITIES

We own a 48.6% limited partner interest in CQP in the form of 239.9 million common units, with the remaining non-controlling limited partner interest held by Blackstone Inc., Brookfield Asset Management, Inc. (“Brookfield”) and the public. We also own 100% of the general partner interest and the incentive distribution rights in CQP.

CQP is a limited partnership formed by us in 2006 to own and operate the Sabine Pass LNG Terminal and related assets. Our subsidiary, Cheniere Partners GP, is the general partner of CQP. In 2012, CQP, Cheniere and Blackstone CQP Holdco LP (“Blackstone CQP Holdco”) entered into a unit purchase agreement whereby CQP sold 100.0 million Class B units to Blackstone CQP Holdco in a private placement. The board of directors of Cheniere Partners GP was modified to include three directors appointed by Blackstone CQP Holdco, four directors appointed by us and four independent directors mutually agreed upon by Blackstone CQP Holdco and us and appointed by us. In addition, we provided Blackstone CQP Holdco with a right to maintain one board seat on our Board of Directors (our “Board”). A quorum of Cheniere Partners GP directors consists of a majority of all directors, including at least two directors appointed by Blackstone CQP Holdco, two directors appointed by us and two independent directors. Blackstone CQP Holdco will no longer be entitled to appoint Cheniere Partners GP directors in the event that Blackstone CQP Holdco’s ownership in CQP is less than 20% of outstanding common units and subordinated units.

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

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

	December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	575	$	904
Restricted cash and cash equivalents	56		92
Trade and other receivables, net of current expected credit losses	373		627
Other current assets	215		269
Total current assets	1,219		1,892
Property, plant and equipment, net of accumulated depreciation	16,212		16,725
Other non-current assets, net	309		288
Total assets	$	17,740	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	811	$	1,384
Current debt, net of discount and debt issuance costs	300		—
Current derivative liabilities	196		769
Other current liabilities	201		191
Total current liabilities	1,508		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,606		16,198
Derivative liabilities	1,531		3,024
Other non-current liabilities	160		98
Total liabilities	$	18,805	$	21,664

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Accrued Liabilities

12 Months Ended

Dec. 31, 2023

Accrued Liabilities, Current [Abstract]

Accrued Liabilities

ACCRUED LIABILITIES

Accrued liabilities consisted of the following (in millions): 

	December 31,
	2023		2022
Natural gas purchases	$	729	$	1,621
Interest costs and related debt fees	399		383
LNG terminals and related pipeline costs	235		240
Compensation and benefits	266		245
LNG purchases	23		88
Other accrued liabilities	128		102
Total accrued liabilities	$	1,780	$	2,679

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Debt

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Debt

DEBT

Debt consisted of the following (in millions): 

	December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.750% due 2024 (the “2024 SPL Senior Notes”)	$	300	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,432		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,432		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.950% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,888		25,086
Current debt, net of discount and debt issuance costs	(300)		(813)
Long-term portion of discount and debt issuance costs, net	(191)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,397	$	24,055

(1)The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.

Senior Notes

SPL Senior Secured Notes

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

CQP Senior Notes

The CQP Senior Notes, except the 2033 CQP Senior Notes, are jointly and severally guaranteed by each of CQP’s subsidiaries other than SPL and, subject to certain conditions governing its guarantee, Sabine Pass LP and the 2033 CQP Senior Notes are jointly and severally guaranteed by each of CQP’s current and future subsidiaries who guarantee the CQP Revolving Credit Facility from time to time (each a “Guarantor” and collectively, the “CQP Guarantors”). The CQP Senior Notes are senior obligations of CQP, ranking equally in right of payment with CQP’s other existing and future unsubordinated debt and senior to any of its future subordinated debt. In the event that the aggregate amount of CQP’s secured indebtedness and the secured indebtedness of the CQP Guarantors (other than the CQP Senior Notes or any other series of notes issued under the CQP Base Indenture) outstanding at any one time exceeds the greater of (1) $1.5 billion and (2) 10% of net tangible assets (or 15% in the case of 2033 CQP Senior Notes), the CQP Senior Notes will be secured by a first-priority lien (subject to permitted encumbrances) on substantially all the existing and future tangible and intangible assets and rights of CQP and the CQP Guarantors and equity interests in the CQP Guarantors. The liens securing the CQP Senior Notes, if applicable, will be shared equally and ratably (subject to permitted liens) with the holders of any other senior secured obligations. CQP may, at any time, redeem all or part of the CQP Senior Notes at specified prices set forth in the respective indentures governing the CQP Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

CCH Senior Secured Notes

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

Cheniere Senior Notes

The Cheniere Senior Notes are our general senior obligations and rank senior in right of payment to all of our future obligations that are, by their terms, expressly subordinated in right of payment to the Cheniere Senior Notes and equally in right of payment with all of our other existing and future unsubordinated indebtedness. The Cheniere Senior Notes are currently unsecured, but in certain instances may become secured in the future in connection with the incurrence of additional secured indebtedness by us. When required, the Cheniere Senior Notes will be secured on a first-priority basis by a lien on substantially all of our assets and equity interests in our direct subsidiaries (other than certain excluded subsidiaries), which liens rank pari passu with the liens securing the Cheniere Revolving Credit Facility. As of December 31, 2023, the Cheniere Senior Notes are not guaranteed by any of our subsidiaries. In the future, any subsidiary that guarantees any of our material indebtedness will also guarantee the Cheniere Senior Notes. We may, at any time, redeem all or part of the Cheniere Senior Notes at specified prices set forth in the indenture governing the Cheniere Senior Notes, plus accrued and unpaid interest, if any, to the date of redemption.

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):

Years Ending December 31,	Principal Payments
2024	$	300
2025	3,543
2026	1,607
2027	2,889
2028	3,091
Thereafter	12,458
Total	$	23,888

Credit Facilities

Below is a summary of our committed credit facilities outstanding as of December 31, 2023 (in millions):

	SPL Revolving Credit Facility (1)(2)		CQP Revolving Credit Facility (1)(3)		CCH Credit Facility (4)		CCH Working Capital Facility (5)		Cheniere Revolving Credit Facility (6)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	280		—		—		155		—
Available commitment	$	720	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (7)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.075% - 2.20% or base rate plus 0.075% - 1.2%
Commitment fees on undrawn balance (7)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (8)
Maturity date	June 23, 2028		June 23, 2028		(9)		June 15, 2027		October 28, 2026

(1)In June 2023, CQP and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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

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

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

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

(6)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR. The Cheniere Revolving Credit Facility contains a financial covenant requiring us to maintain a non-consolidated leverage ratio not to exceed 5.50:1.00 as of the end of any fiscal quarter if (i) as of the last day of such fiscal quarter the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit is greater than 35% of

the aggregate commitments under the Cheniere Revolving Credit Facility (a “Covenant Trigger Event”) or (ii) a Covenant Trigger Event had occurred and been continuing as of the last day of the immediately preceding fiscal quarter and as of the last day of such ending fiscal quarter such Covenant Trigger Event had not ceased for a period of at least thirty consecutive days.

(7)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

(8)In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.

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

Loss on Extinguishment of Debt Related to Termination of Agreement with Chevron

Our loss on modification or extinguishment of debt for the year ended December 31, 2022 includes a loss on extinguishment of prospective payment obligations of $31 million associated with a premium paid to Chevron U.S.A. Inc. (“Chevron”) to terminate a revenue sharing arrangement under the terminal marine services agreement with them. See Note 13—Revenue for further discussion of the termination of agreements with Chevron.

Restrictive Debt Covenants

The indentures governing our senior notes and other agreements underlying our debt contain customary terms and events of default and certain covenants that, among other things, may limit us, our subsidiaries’ and its restricted subsidiaries’ ability to make certain investments or pay dividends or distributions. SPL and CCH are restricted from making distributions under agreements governing their respective indebtedness generally until, among other requirements, appropriate reserves have been established for debt service using cash or letters of credit and a historical debt service coverage ratio and projected debt service coverage ratio of at least 1.25:1.00 is satisfied. At December 31, 2023, our restricted net assets of consolidated subsidiaries were approximately $203 million.

As of December 31, 2023, each of our issuers was in compliance with all covenants related to their respective debt agreements.

Interest Expense

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

	Year Ended December 31,
	2023		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	—	$	36
Amortization of debt discount and debt issuance costs	—		—		10
Total interest cost related to convertible notes	—		—		46
Interest cost on debt and finance leases excluding convertible notes	1,265		1,485		1,558
Total interest cost	$	1,265	$	1,485	1,604
Capitalized interest	(124)		(79)		(166)
Total interest expense, net of capitalized interest	$	1,141	$	1,406	$	1,438

Fair Value Disclosures

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

	December 31, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,888	$	23,062	$	25,086	$	23,500

(1)As of both December 31, 2023 and 2022, $3.0 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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

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Leases

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Leases

LEASES

Our leased assets consist primarily of LNG vessels leased under time charters (“vessel charters”) and additionally include tug vessels, office space and facilities and land sites. All of our leases are classified as operating leases except for certain of our vessel charters, tug vessels and marine equipment, which are classified as finance leases.

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

		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,641	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	469		511
Total right-of-use assets		$	3,110	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	655	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,971		1,971
Non-current finance lease liabilities	Finance lease liabilities	467		494
Total lease liabilities		$	3,128	$	3,109

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

	Consolidated Statements of Operations Location	Year Ended December 31,
		2023		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	783	$	828	$	621
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	50		12		3
Interest on lease liabilities	Interest expense, net of capitalized interest	35		14		9
Total lease cost		$	868	$	854	$	633
(a) Included in operating lease cost:
Short-term lease costs		$	33	$	122	$	139
Variable lease costs		17		18		21

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

Future annual minimum lease payments for operating and finance leases as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	752	$	67
2025	612		72
2026	480		75
2027	383		77
2028	228		73
Thereafter	638		355
Total lease payments (1)	3,093		719
Less: Interest	(467)		(217)
Present value of lease liabilities	$	2,626	$	502

(1)Does not include approximately $3.8 billion of legally binding minimum payments for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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

	December 31, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.3	9.7	5.9	10.6
Weighted-average discount rate (1)	4.7%	7.7%	4.2%	7.8%

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

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

	Year Ended December 31,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	720	$	713	$	483
Operating cash flows from finance leases	35		14		10
Financing cash flows from finance leases	28		7		—
Right-of-use assets obtained in exchange for operating lease liabilities	646		1,220		1,736
Right-of-use assets obtained in exchange for finance lease liabilities (1)	8		473		—

(1)     Includes $88 million reclassified from operating leases to finance leases during the year ended December 31, 2022 as a result of modification of the underlying vessel charters.

LNG Vessel Subcharters

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

	Year Ended December 31,
	2023		2022		2021
Fixed income	$	446	$	371	$	72
Variable income	57		79		37
Total sublease income	$	503	$	450	$	109

Future annual minimum sublease payments to be received from LNG vessel subcharters as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	158
2025	5
Total sublease payments	$	163

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Revenues

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenues

REVENUES

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

	Year Ended December 31,
	2023		2022		2021
Revenues from contracts with customers
LNG revenues	$	19,459	$	32,132	$	17,171
Regasification revenues	135		1,068		269
Other revenues	187		107		91
Total revenues from contracts with customers	19,781		33,307		17,531
Net derivative gain (loss) (1)	110		(328)		(1,776)
Other (2)	503		449		109
Total revenues	$	20,394	$	33,428	$	15,864

(1)See Note 7—Derivative Instruments for additional information about our derivatives.

(2)Primarily includes revenues from LNG vessel subcharters. See Note 12—Leases for additional information about our subleases.

LNG Revenues

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

We intend to primarily use LNG sourced from our Sabine Pass LNG Terminal or our Corpus Christi LNG Terminal to provide contracted volumes to our customers. However, we supplement this LNG with volumes procured from third parties. LNG revenues recognized from LNG that was procured from third parties was $359 million, $760 million and $499 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Revenues from the sale of LNG are recognized at a point in time when the LNG is delivered to the customer based on the delivery terms described above, which is the point legal title, physical possession and the risks and rewards of ownership transfer to the customer. Each individual molecule of LNG is viewed as a separate performance obligation. We allocate the contract price (including both fixed and variable fees) in each LNG sales arrangement based on the stand-alone selling price of each performance obligation as of the time the contract was negotiated. We have concluded that the variable fees meet the exception for allocating variable consideration to specific parts of the contract. As such, the variable consideration for these contracts is allocated to each distinct molecule of LNG and recognized when that distinct molecule of LNG is delivered to the customer. Because of the use of the exception, variable consideration related to the sale of LNG is also not included in the transaction price.

When we sell LNG on a DAT basis, we consider all transportation costs, including vessel chartering, loading/unloading and canal fees, as fulfillment costs and not as separate services provided to the customer within the arrangement, regardless of

whether or not such activities occur prior to or after the customer obtains control of the LNG. We expense fulfillment costs as incurred unless otherwise dictated by GAAP.

Fees received pursuant to SPAs are recognized as LNG revenues only after substantial completion of the respective Train. Prior to substantial completion, sales generated during the commissioning phase are offset against the cost of construction for the respective Train, as the production and removal of LNG from storage is necessary to test the facility and bring the asset to the condition necessary for its intended use.

Sales of natural gas where, in the delivery of the natural gas to the end customer, we have concluded that we acted as a principal are presented within revenues in our Consolidated Statements of Operations, and where we have concluded that we acted as an agent are netted within cost of sales in our Consolidated Statements of Operations.

Regasification Revenues

The Sabine Pass LNG Terminal has operational regasification capacity of approximately 4 Bcf/d. Approximately 1 Bcf/d of the regasification capacity at the Sabine Pass LNG Terminal has been reserved under a long-term TUA with TotalEnergies Gas & Power North America, Inc. (“TotalEnergies”), under which they are required to pay fixed monthly fees to SPLNG, regardless of their use of the LNG terminal, aggregating approximately $125 million annually for 20 years that commenced in 2009, which is representative of fixed consideration in the contract. A portion of this fee is adjusted annually for inflation which is considered variable consideration. Prior to its cancellation effective December 31, 2022, SPLNG also had a TUA for 1 Bcf/d with Chevron, as further described below. Approximately 2 Bcf/d of regasification capacity of the Sabine Pass LNG Terminal has been reserved by SPL, for which the associated revenues are eliminated in consolidation.

Because SPLNG is continuously available to provide regasification service on a daily basis with the same pattern of transfer, we have concluded that SPLNG provides a single performance obligation to its customers on a continuous basis over time. We have determined that an output method of recognition based on elapsed time best reflects the benefits of this service to the customer and accordingly, LNG regasification capacity reservation fees are recognized as regasification revenues on a straight-line basis over the term of the respective TUAs.

In 2012, SPL entered into a partial TUA assignment agreement with TotalEnergies, whereby upon substantial completion of Train 5 of the SPL Project, SPL gained access to substantially all of TotalEnergies’ capacity and other services provided under TotalEnergies’ TUA with SPLNG. This agreement provides SPL with additional berthing and storage capacity at the Sabine Pass LNG Terminal that may be used to provide increased flexibility in managing LNG cargo loading and unloading activity and permit SPL to more flexibly manage its LNG storage capacity. Notwithstanding any arrangements between TotalEnergies and SPL, payments required to be made by TotalEnergies to SPLNG will continue to be made by TotalEnergies to SPLNG in accordance with its TUA and we continue to recognize the payments received from TotalEnergies as revenue. Costs incurred to TotalEnergies are recognized in operating and maintenance expense. During the years ended December 31, 2023, 2022 and 2021, SPL recorded $132 million, $131 million and $129 million, respectively, as operating and maintenance expense under this partial TUA assignment agreement.

Termination Agreement with Chevron

In June 2022, Chevron entered into an agreement with SPLNG providing for the early termination of the TUA and an associated terminal marine services agreement between the parties and their affiliates (the “Termination Agreement”), effective July 2022, for a lump sum fee of $765 million (the “Termination Fee”). Obligations pursuant to the TUA and associated agreement, including Chevron’s obligation to pay SPLNG capacity payments totaling $125 million annually (adjusted for inflation) from 2023 through 2029, terminated on December 31, 2022, upon SPLNG’s receipt of the Termination Fee in December 2022. We allocated the $765 million Termination Fee to the terminated commitments, with $796 million in cash inflows allocable to the termination of the TUA, which was recognized ratably over the July 6, 2022 to December 31, 2022 period as regasification revenues on our Consolidated Statements of Operations, and an offsetting $31 million reported, upon receipt of the Termination Fee, as a loss on extinguishment of debt on our Consolidated Statements of Operations allocable to a premium paid to Chevron to terminate a revenue sharing arrangement with them that was accounted for as debt.

Contract Assets and Liabilities

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	250	$	186

Contract assets represent our right to consideration for transferring goods or services to the customer under the terms of a sales contract when the associated consideration is not yet due and also include consideration paid to our customers that will reduce the amount of revenue recognized as the remaining performance obligations in the contract are satisfied. The change in contract assets between the years ended December 31, 2023 and 2022 was primarily attributable to additional revenue recognized due to the delivery of LNG under certain SPAs for which the associated consideration was not yet due.

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

	Year Ended December 31, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	218
Revenue recognized from prior period deferral	(244)
Deferred revenue, end of period	$	294

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2023 and 2022 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

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

	December 31, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	111.0	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	111.7		$	112.8

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

(2)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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met and consideration is not otherwise constrained from ultimate pricing and receipt.

We have elected the following exemptions which omit certain potential future sources of revenue from the table above:

(1)We omit from the table above all performance obligations that are part of a contract that has an original expected duration of one year or less.

(2)The table above excludes substantially all variable consideration under our SPAs and TUAs. We omit from the table above all variable consideration that is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct good or service that forms part of a single performance obligation when that performance obligation qualifies as a series. The amount of revenue from variable fees that is not included in the transaction price will vary based on the future prices of the underlying variable index, primarily Henry Hub, throughout the contract terms, to the extent customers elect to take delivery of their LNG, and adjustments to the consumer price index. Certain of our contracts contain additional variable consideration based on the outcome of contingent events and the movement of various indexes. We have not included such variable consideration in the transaction price to the extent the consideration is considered constrained due to the uncertainty of ultimate pricing and receipt. Additionally, we have excluded variable consideration related to volumes that contractually are subject to additional liquefaction capacity beyond what is currently in construction or operation. The following table summarizes the amount of variable consideration earned under contracts with customers included in the table above:

	Year Ended December 31,
	2023		2022
LNG revenues	69	%	72	%
Regasification revenues	7	%	2	%

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Related Party Transactions

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Related Party Transactions

RELATED PARTY TRANSACTIONS

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

	Year Ended December 31,
	2023		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	$	—	$	—	$	1
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	10		7		7
Cost of sales
Natural Gas Supply Agreements (3)	—		—		162
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		1
Total cost of sales	—		—		163
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	9		9		9
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	62		72		46

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of CQP’s limited partner interests.

(2)Midship Pipeline is a subsidiary of Midship Holdings, LLC, which we recognize as an equity method investment.

(3)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, when the related party entity was acquired by a non-related party.

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

	December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	3	$	1
Accrued liabilities	6		1

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

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

	Year Ended December 31,
	2023		2022		2021
U.S.	$	11,176	$	(1,575)	$	(2,317)
International	3,402		4,669		39
Total income (loss) before income taxes and non-controlling interest	$	14,578	$	3,094	$	(2,278)

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

	Year Ended December 31,
	2023		2022		2021
Current:
Federal	$	130	$	6	$	—
State	1		2		3
Foreign	(1)		11		5
Total current	130		19		8
Deferred:
Federal	2,377		320		(633)
State	15		118		(89)
Foreign	(3)		2		1
Total deferred	2,389		440		(721)
Total income tax provision (benefit)	$	2,519	$	459	$	(713)

Our income tax rates do not bear a customary relationship to statutory income tax rates. A reconciliation of the federal statutory income tax rate of 21% to our effective income tax rate is as follows: 

	Year Ended December 31,
	2023		2022		2021
U.S. federal statutory tax rate	21.0	%	21.0	%	21.0	%
Income not taxable to Cheniere	(3.1)		(8.2)		7.2
State tax, net of federal benefit	0.1		0.5		(2.5)
Foreign-derived intangible income deduction	(0.7)		(1.2)		—
Valuation allowance	—		2.6		5.6
Other	—		0.1		—
Effective tax rate as reported	17.3	%	14.8	%	31.3	%

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

	December 31,
	2023		2022
Deferred tax assets
Net operating loss (“NOL”) carryforwards
Federal	$	915	$	1,968
State	163		177
Federal and state tax credits	33		66
Derivative instruments	98		1,345
Operating lease liabilities	550		542
Other	298		311
Less: valuation allowance (1)	(147)		(143)
Total deferred tax assets	1,910		4,266
Deferred tax liabilities
Investment in partnerships	(309)		(211)
Property, plant and equipment	(2,564)		(2,646)
Operating lease assets	(538)		(536)
Other	(18)		(9)
Total deferred tax liabilities	(3,429)		(3,402)
Net deferred tax assets (liabilities)	$	(1,519)	$	864

(1)Valuation allowance primarily related to state NOL carryforward deferred tax assets and increased by $4 million and $80 million during the years ended December 31, 2023 and 2022, respectively, and decreased by $127 million during year ended December 31, 2021.

NOL and tax credit carryforwards

As of December 31, 2023, we had federal and state NOL carryforwards of approximately $4.3 billion and $2.2 billion, respectively. All of our NOLs have an indefinite carryforward period.

As of December 31, 2023, we had federal and state tax credit carryforwards of $32 million and $1 million, respectively, which will expire between 2028 and 2033. As of December 31, 2023, all of the federal tax credit carryforwards were foreign tax credit carryforwards.

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

Unrecognized Tax Benefits

As of December 31, 2023, we had unrecognized tax benefits of $73 million. If recognized, $66 million of unrecognized tax benefits would affect our effective tax rate in future periods. Interest and penalties related to income tax matters are recognized as part of income tax expense. Interest recognized as part of income tax provision was $4 million and zero as of December 31, 2023 and 2022, respectively, and cumulative accrued interest was $4 million and zero as of December 31, 2023 and 2022, respectively. There were no penalties associated with liabilities for unrecognized tax benefits recorded for the years ended December 31, 2023 and 2022. We do not expect the amount of our existing unrecognized tax benefit to significantly increase or decrease within the next 12 months.

We are subject to tax in the U.S. and various state and foreign jurisdictions and we are subject to periodic audits and reviews by taxing authorities. Federal and United Kingdom tax returns for the years after 2017 and state tax returns for the years after 2019 remain open for examination. Tax authorities may have the ability to review and adjust carryover attributes that were generated prior to these periods if utilized in an open tax year.

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

	Year Ended December 31,
	2023		2022
Balance at beginning of the year	$	74	$	65
Additions based on tax positions related to current year	—		10
Reductions for tax positions of prior years	(1)		(1)
Balance at end of the year	$	73	$	74

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Share-Based Compensation

12 Months Ended

Dec. 31, 2023

Share-Based Payment Arrangement [Abstract]

Share-Based Compensation

SHARE-BASED COMPENSATION

We have granted restricted stock shares, restricted stock units, performance stock units and phantom units to employees and non-employee directors under the 2011 Incentive Plan, as amended (the “2011 Plan”) and the 2020 Incentive Plan (the “2020 Plan”). The 2011 Plan and the 2020 Plan provide for the issuance of 35.0 million shares and 8.0 million shares, respectively, of our common stock that may be in the form of various share-based performance awards as determined by the Compensation Committee of our Board (the “Compensation Committee”).

We initially recognize share-based compensation based upon the estimated fair value of awards.

For equity-classified share-based compensation awards, compensation cost is recognized based on the grant-date fair value and not subsequently remeasured unless modified. For liability-classified share-based compensation awards that cash settle or include an election to be cash settled, compensation costs are remeasured at fair value through settlement or maturity.

Except for awards that contain market conditions, the grant-date fair value is estimated based on our stock price on the grant date. The grant-date fair value of awards containing market conditions is estimated using a fair value model as further described herein.

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

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

The recognition period for share-based compensation costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period.

We account for forfeitures as they occur.

Total share-based compensation consisted of the following (in millions):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs before income taxes:
Equity awards	$	100	$	112	$	105
Liability awards	155		97		40
Total share-based compensation	255		209		145
Capitalized share-based compensation	(5)		(4)		(5)
Total share-based compensation costs before income taxes	$	250	$	205	$	140
Tax benefit associated with share-based compensation costs	$	54	$	48	$	33

    

The total unrecognized compensation cost at December 31, 2023 relating to non-vested share-based compensation arrangements consisted of the following:

	Unrecognized Compensation Cost (in millions)		Recognized over a weighted average period (years)
Restricted Stock Unit and Performance Stock Unit Awards	$	181	1.4

Equity-Classified Awards

Restricted Stock Share Awards

Restricted stock share awards are awards of common stock that are granted to the members of our Board of Directors for their service, subject to restrictions on transfer and to a risk of forfeiture if the recipient is unaffiliated with us prior to the lapse of the restrictions. These awards vest over a one-year service period. There were nominal non-vested restricted stock share awards outstanding as of December 31, 2023.

The fair value of restricted stock share awards vested for the year ended December 31, 2023 was $1 million.

Restricted Stock Units

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

The table below provides a summary of activity related to our equity-classified restricted stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	2.3	$	92.52
Granted	0.8	150.59
Forfeited	(0.1)	118.77
Modified to liability awards (1)	(0.2)	115.26
Vested (2)	(1.2)	84.12
Non-vested at December 31, 2023	1.6	$	123.24

(1)See further details in Liability-Classified Awards below.

(2)The total fair value of shares vested was $183 million for the year ended December 31, 2023.

Performance Stock Units

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

Where applicable, the compensation for performance stock units containing a market condition of ATSR is based on a fair value assigned to the market metric using a Monte Carlo model as of the grant date, which utilizes level 3 inputs such as projected stock volatility and projected risk free rates and remains constant through the vesting period for the equity-settled component.

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

For performance stock units containing a cash-settlement feature, the compensation cost of the cash settled component is remeasured at each reporting period, as discussed in Liability-Classified Awards below.

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

	Year Ended December 31,
	2023		2022		2021
Fair value assumptions:
Dividend yield (1)	—	%	—	%	—	%
Expected volatility (2)	27.5% - 32.7%		36.4% - 40.2%		27.0% - 41.0%
Risk-free interest rate (2)	4.2% - 4.8%		4.4% - 4.7%		0.7% - 1.4%
Weighted average expected remaining term, in years	1.5		1.4		1.5

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

(2)Represents the range associated with individual vesting years.

The table below provides a summary of activity related to our equity-classified performance stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	0.6	$	92.11
Granted (1)	0.2	163.04
Incremental units achieved (2)	0.3	72.05
Forfeited	(0.1)	107.61
Modified to liability awards (3)	(0.3)	106.25
Vested (4)	(0.2)	55.26
Non-vested at December 31, 2023	0.5	$	124.19

(1)Includes 0.1 million performance stock units granted in 2023 to certain officers containing a cash settlement cap of $3 million.

(2)Represents incremental units recognized as a result of final performance measures or estimated measures.

(3)See further details in Liability-Classified Awards below.

(4)The total fair value of shares vested was $36 million for the year ended December 31, 2023.

Liability-Classified Awards

Restricted stock units and performance stock units granted to certain officers may be settled in cash in lieu of shares, following approval by the Compensation Committee, in order to limit dilution from equity grants consistent with our share repurchase program under our long-term capital allocation plan, provided that we have sufficient liquidity to do so and the officers maintain certain stock ownership requirements. The Compensation Committee also has authorization from the Board to permit certain officers to make an election to cash settle their earned performance stock units that are expected to vest in 2025 and restricted stock units that are expected to vest in 2025 and 2026. Notwithstanding those awards which contain a cash settlement option, performance stock units granted to certain officers contain a cash settlement cap of $3 million.

A total of 0.5 million units were reclassified from equity to liability during the year ended December 31, 2023, as a result of modifications made for certain employees to settle certain awards in cash in lieu of shares. Under GAAP, the modifications are treated as an exchange of the original award for a new award. During the years ended December 31, 2023, 2022 and 2021, we recognized $86 million, $56 million and $18 million, respectively, in incremental expense as a result of the modifications, attributed to six, six, and five employees impacted, respectively.

During the year ended December 31, 2023, we paid $84 million to settle a total of 0.5 million liability-classified awards, which approximated the fair value of the awards on the settlement date and was inclusive of payout for an incremental 0.3 million of performance stock units based on final performance measures achieved.

As described above, liability-classified share-based compensation awards are remeasured at fair value through settlement or maturity. The fair value of non-vested liability-classified awards was $165 million and $98 million as of December 31, 2023 and 2022, respectively, and consisted of 0.2 million of unvested restricted stock units and 0.6 million of unvested performance stock units as of December 31, 2023 and 0.2 million of unvested restricted stock units and 0.1 million of unvested performance stock units as of December 31, 2022.

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Employee Benefit Plan

12 Months Ended

Dec. 31, 2023

Retirement Benefits [Abstract]

Employee Benefit Plan

EMPLOYEE BENEFIT PLAN

We have a defined contribution plan (“401(k) Plan”) which allows eligible employees to contribute up to 75% of their compensation up to the Internal Revenue Service maximum. We match each employee’s deferrals (contributions) up to 6% of compensation and may make additional contributions at our discretion. Employees are immediately vested in the contributions made by us. Our contributions to the 401(k) Plan were $17 million, $16 million and $15 million for of the years ended December 31, 2023, 2022 and 2021, respectively. We have made no discretionary contributions to the 401(k) Plan to date.

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Net Income (Loss) Per Share Attributable to Common Stockholders

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Net Income (Loss) Per Share Attributable to Common Stockholders

NET INCOME (LOSS) PER SHARE ATTRIBUTABLE TO COMMON STOCKHOLDERS

The following table reconciles basic and diluted weighted average common shares outstanding and common stock dividends declared (in millions, except per share data):

	Year Ended December 31,
	2023		2022		2021
Net income (loss) attributable to common stockholders	$	9,881	$	1,428	$	(2,343)
Weighted average common shares outstanding:
Basic	241.0		251.1		253.4
Dilutive unvested stock	1.6		2.3		—
Diluted	242.6		253.4		253.4
Net income (loss) per share attributable to common stockholders—basic (1)	$	40.99	$	5.69	$	(9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	40.72	$	5.64	$	(9.25)
Dividends paid per common share	$	1.62	$	1.385	$	0.33

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

On January 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.

Potentially dilutive securities that were not included in the diluted net income (loss) per share computations because their effects would have been anti-dilutive were as follows (in millions):

	Year Ended December 31,
	2023	2022	2021
Unvested stock (1)	—	—	1.8
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	0.3	—
Total potentially dilutive common shares	—	0.3	1.8

(1)Includes the impact of unvested shares containing performance conditions to the extent that the underlying performance conditions are satisfied based on actual results as of the respective period end dates.

(2)The 2045 Cheniere Convertible Senior Notes were redeemed or converted in cash on January 5, 2022. However, the adoption of ASU 2020-06 on January 1, 2022 required a presumption of share settlement for the purpose of calculating the impact to diluted earnings per share during the period the notes were outstanding in 2022. Such impact was anti-dilutive as a result of the reported net loss attributable to common stockholders during the 2022 period.

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Share Repurchase Programs

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Share Repurchase Programs

SHARE REPURCHASE PROGRAMS

On September 7, 2021, our Board authorized a reset in the previously existing share repurchase program to $1.0 billion, inclusive of any amounts remaining under the previous authorization as of September 30, 2021, for an additional three years beginning on October 1, 2021. 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. The following table presents information with respect to common stock repurchased under our share repurchase program (in millions, except per share data):

	Year Ended December 31,
	2023		2022		2021
Total shares repurchased	9.54		9.35		0.10
Weighted average price paid per share	$	155.50	$	146.88	$	87.32
Total cost of repurchases (1)	$	1,484	$	1,373	$	9

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

As of December 31, 2023, we had approximately $2.1 billion remaining under our share repurchase program. Subsequent to December 31, 2023 and through February 16, 2024, we repurchased approximately 2.9 million shares for over $450 million.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

COMMITMENTS AND CONTINGENCIES

Commitments

We have various future commitments under executed contracts that include unconditional purchase obligations and other commitments which do not meet the definition of a liability as of December 31, 2023 and thus are not recognized as liabilities in our Consolidated Financial Statements.

EPC Contract

CCL has a lump sum turnkey contract with Bechtel Energy Inc. (“Bechtel”) for the engineering, procurement and construction of the Corpus Christi Stage 3 Project. The total contract price of the EPC contract is approximately $5.7 billion, inclusive of amounts incurred under change orders through December 31, 2023. As of December 31, 2023, we had approximately $2.9 billion remaining obligations under this contract.

Natural Gas Supply, Transportation and Storage Service Agreements

SPL and CCL have physical natural gas supply contracts to secure natural gas feedstock for the SPL Project and the CCL Project, respectively. As of December 31, 2023, the remaining fixed terms of these contracts ranged up to 15 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs.

Additionally, SPL and CCL have natural gas transportation and storage service agreements for the SPL Project and the CCL Project, respectively. The initial fixed terms of the natural gas transportation agreements range up to 20 years, with renewal options for certain contracts and some of which commence upon the satisfaction of certain events or states of affairs. The initial fixed term of the natural gas storage service agreements ranges up to 10 years.

As of December 31, 2023, the obligations of SPL and CCL under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are currently expected to be met were as follows (in billions):

Years Ending December 31,	Payments Due to Third Parties (1) (2)		Payments Due to Related Parties (1) (3)
2024	$	6.2	$	0.1
2025	6.3		0.1
2026	5.9		0.1
2027	5.3		0.1
2028	4.3		0.1
Thereafter	29.5		0.8
Total	$	57.5	$	1.3

(1)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. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

(2)Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

(3)Includes $1.0 billion under natural gas transportation and storage service agreements with unsatisfied contractual conditions.

Other Agreements

We have certain fixed commitments under SPL’s partial TUA assignment agreement with TotalEnergies and other agreements of $1.4 billion. See Note 13—Revenues for further discussion of the partial TUA assignment.

We have approximately $3.8 billion of legally binding minimum payments primarily for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years. See Note 12—Leases for further discussion of our leases, including leases for vessel charters that have not yet commenced as of December 31, 2023.

Environmental and Regulatory Matters

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

Legal Proceedings

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

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Customer Concentration

12 Months Ended

Dec. 31, 2023

Risks and Uncertainties [Abstract]

Customer Concentration

CUSTOMER CONCENTRATION

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers			Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Year Ended December 31,			December 31,
	2023	2022	2021	2023	2022
Customer A	*	*	12%	*	*
Customer B	*	*	12%	*	*
Customer C	*	*	10%	*	*
Customer D	*	*	*	13%	*

* Less than 10%

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business.

	Revenues from External Customers
	Year Ended December 31,
	2023		2022		2021
Singapore	$	3,407	$	3,273	$	1,740
United Kingdom	2,908		4,642		1,246
United States	2,868		5,213		1,340
Ireland	1,596		2,726		1,838
South Korea	1,503		2,225		1,680
Spain	1,357		2,226		1,577
India	1,166		2,109		1,375
Switzerland	534		1,725		582
Germany	131		1,747		507
Other countries	4,924		7,542		3,979
Total	$	20,394	$	33,428	$	15,864

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Supplemental Cash Flow Information

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information [Abstract]

Supplemental Cash Flow Information

SUPPLEMENTAL CASH FLOW INFORMATION

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

	Year Ended December 31,
	2023		2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	1,032	$	891	$	1,365
Cash paid for income taxes, net	117		30		4
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net and other non-current assets	204		181		117
Share-based compensation capitalized to property, plant and equipment	5		4		5
Conveyance of property, plant and equipment in exchange for other non-current assets	—		17		—
Contribution of other non-current assets in exchange for equity method investment	30		—		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		4		1
Unpaid repurchases of treasury stock inclusive of excise taxes	23		—		—

See Note 12—Leases for supplemental cash flow information related to our leases.

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Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net income (loss) attributable to common stockholders	$ 9,881	$ 1,428	$ (2,343)

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Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Basis of Presentation, Policy

Basis of Presentation

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

Variable Interest Entity, Policy

VIEs

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

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

Non-controlling Interests, Policy

Non-controlling Interests

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

recognized within equity. See Note 9—Non-controlling Interest and Variable Interest Entities for additional details about our non-controlling interest.

Use of Estimates, Policy

Estimates

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

Fair Value Measurements, Policy

Fair Value Measurements

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

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

Recurring fair-value measurements are performed for derivative instruments, as disclosed in Note 7—Derivative Instruments, and liability-classified share-based compensation awards, as disclosed in Note 16—Share-Based Compensation.

The carrying amount of cash and cash equivalents, restricted cash and cash equivalents, trade and other receivables, net of current expected credit losses, contract assets, margin deposits, accounts payable and accrued liabilities reported on the Consolidated Balance Sheets approximates fair value. The fair value of debt is the estimated amount we would have to pay to repurchase our debt in the open market, including any premium or discount attributable to the difference between the stated interest rate and market interest rate at each balance sheet date. Refer to Note 11—Debt for our debt fair value estimates, including our estimation methods.

Revenue Recognition, Policy

Revenue Recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration to which we expect to be entitled to in exchange for those goods or services. See Note 13—Revenues for further discussion of our revenue streams and accounting policies related to revenue recognition.

Cash and Cash Equivalents, Policy

Cash and Cash Equivalents

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

Restricted Cash and Cash Equivalents, Policy

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents consist of funds that are contractually or legally restricted as to usage or withdrawal and have been presented separately from cash and cash equivalents on our Consolidated Balance Sheets.

Current Expected Credit Losses, Policy

Current Expected Credit Losses

Current expected credit losses consider the risk of loss based on past events, current conditions and reasonable and supportable forecasts. A counterparty’s ability to pay is assessed through a credit review process that considers payment terms,

the counterparty’s established credit rating or our assessment of the counterparty’s credit worthiness, contract terms, payment status and other risks or available financial assurances. We record charges and reversals of current expected credit losses in selling, general and administrative in our Consolidated Statements of Operations.

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

	Year Ended December 31,
	2023		2022		2021
Current expected credit losses, beginning of period	$	5	$	9	$	7
Charges (reversals)	(2)		(4)		2
Current expected credit losses, end of period	$	3	$	5	$	9

Inventory, Policy

Inventory

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

Property, Plant and Equipment, Policy

Property, Plant and Equipment

Property, plant and equipment are recorded at cost. Expenditures for construction and commissioning activities, major renewals and betterments that extend the useful life of an asset are capitalized, while expenditures for maintenance and repairs (including those for planned major maintenance projects) to maintain property, plant and equipment in operating condition are generally expensed as incurred.

Generally, we begin capitalizing the costs of our LNG terminals once the individual project meets the following criteria: (1) regulatory approval has been received, (2) financing for the project is available and (3) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with preliminary review and selection of equipment alternatives, costs of securing necessary regulatory approvals and other preliminary investigation and development activities related to our LNG terminals.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land acquisition costs, detailed engineering design work and certain permits that are capitalized as other non-current assets.

We realize offsets to LNG terminal costs for sales of commissioning cargoes that were earned or loaded prior to the start of commercial operations of the respective Train during the testing phase for its construction.

We depreciate our property, plant and equipment using the straight-line depreciation method over assigned useful lives, except land which is not depreciated. Refer to Note 6—Property, Plant and Equipment, Net of Accumulated Depreciation for additional discussion of our useful lives by asset category. Upon retirement or other disposition of property, plant and equipment, the cost and related accumulated depreciation are removed from the account, and the resulting gains or losses on disposal are recorded in other operating costs and expenses.

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

We did not record any material impairments related to property, plant and equipment during the years ended December 31, 2023, 2022 and 2021.

Conveyances, Policy

Advances of Cash and Conveyed Assets to Service Providers

We may convey cash or physical assets to service providers in support of infrastructure maintained by them, which is necessary to support our own operations. Such conveyances are recognized within other non-current assets on our Consolidated Balance Sheets and amortized within depreciation and amortization expense on our Consolidated Statements of Operations over the shorter of the contractual term of the arrangement with the service provider or the useful life of the physical asset. The weighted average amortization period of these assets was approximately 31 years as of both December 31, 2023 and 2022.

Interest Capitalization, Policy

Interest Capitalization

We capitalize interest costs mainly during the construction period of our LNG terminals and related assets. Upon placing the underlying asset in service, these costs are depreciated over the estimated useful life of the corresponding assets which interest costs were incurred, except for capitalized interest associated with land, which is not depreciated.

Derivative Instruments, Policy

Derivative Instruments

We use derivative instruments to hedge our exposure to cash flow variability from commodity price and foreign currency exchange (“FX”) rate risk. Derivative instruments are recorded at fair value and included in our Consolidated Balance Sheets as current or non-current assets or liabilities depending on the derivative position and the expected timing of settlement. When we have the contractual right and intent to net settle, derivative assets and liabilities are reported on a net basis.

Changes in the fair value of our derivative instruments are recorded in earnings. We did not have any derivative instruments designated as cash flow, fair value or net investment hedges during the years ended December 31, 2023, 2022 and 2021. See Note 7—Derivative Instruments for additional details about our derivative instruments.

Leases, Policy

Leases

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

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

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

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

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

When we determine the arrangement is, or contains, a lease in which we are the lessor or sublessor, we assess classification of the lease as either an operating lease, sales-type lease or direct financing lease. All of our arrangements have been assessed as operating leases and consist of sublessor arrangements in which we have not been relieved of our primary

obligation under the original lease. Our sublessor arrangements are not recognized on our Consolidated Balance Sheets and we recognize income from these arrangements on a straight-line basis over the sublease term.

Concentration of Credit Risk, Policy

Concentration of Credit Risk

Financial instruments that potentially subject us to a concentration of credit risk consist principally of derivative instruments and accounts receivable and contract assets related to our long-term SPAs and regasification contracts, each discussed further below. Additionally, we maintain cash balances at financial institutions, which may at times be in excess of federally insured levels. We have not incurred credit losses related to these cash balances to date.

The use of derivative instruments exposes us to counterparty credit risk, or the risk that a counterparty will be unable to meet its commitments. Certain of our commodity derivative transactions are executed through over-the-counter contracts which are subject to nominal credit risk as these transactions are settled on a daily margin basis with investment grade financial institutions. Collateral deposited for such contracts is recorded within margin deposits on our Consolidated Balance Sheets. Our FX derivative instruments are placed with investment grade financial institutions whom we believe are acceptable credit risks. We monitor counterparty creditworthiness on an ongoing basis; however, we cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, we may be limited in our ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, we may not realize the benefit of some of our derivative instruments.

We have contracted our anticipated production capacity under SPAs and under IPM agreements. Substantially all of our contracted capacity is from contracts with terms exceeding 10 years. As of December 31, 2023, we had SPAs with initial terms of 10 or more years with a total of 29 different third party customers. 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. We market and sell LNG produced by the Liquefaction Projects that is not contracted by CCL or SPL’s customers through our integrated marketing function. We are dependent on the respective customers’ creditworthiness and their willingness to perform under their respective agreements.

Our arrangements with our customers incorporate certain provisions to mitigate our exposure to credit losses and include, under certain circumstances, customer collateral, netting of exposures through the use of industry standard commercial agreements and, as described above, margin deposits with certain counterparties in the over-the-counter derivative market, with such margin deposits primarily facilitated by independent system operators and by clearing brokers. Payments on margin deposits, either by us or by the counterparty depending on the position, are required when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us (or to the counterparty) on or near the settlement date for non-exchange traded derivatives, and we exchange margin calls on a daily basis for exchange traded transactions.

Debt, Policy

Debt

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

Debt is recorded on our Consolidated Balance Sheets at par value adjusted for unamortized discount or premium and net of unamortized debt issuance costs related to term notes. Debt issuance costs consist primarily of arrangement fees, professional fees, legal fees, printing costs and in certain cases, commitment fees. If debt issuance costs are incurred in connection with a line of credit arrangement or on undrawn funds, the debt issuance costs are presented as an asset on our Consolidated Balance Sheets. Discounts, premiums and debt issuance costs directly related to the issuance of debt are amortized over the life of the debt and are recorded in interest expense, net of capitalized interest using the effective interest method.

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

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

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

Asset Retirement Obligations, Policy

Asset Retirement Obligations

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

We have not recorded an ARO associated with the Sabine Pass LNG Terminal. Based on the real property lease agreements at the Sabine Pass LNG Terminal, at the expiration of the term of the leases we are required to surrender the LNG terminal in good working order and repair, with normal wear and tear and casualty expected. Our property lease agreements at the Sabine Pass LNG Terminal have terms of up to 90 years including renewal options. We have determined that the cost to surrender the Sabine Pass LNG Terminal in good order and repair, with normal wear and tear and casualty expected, is immaterial.

We have not recorded an ARO associated with the Creole Trail Pipeline or the Corpus Christi Pipeline. We believe that it is not feasible to predict when the natural gas transportation services provided by the Creole Trail Pipeline or the Corpus Christi Pipeline will no longer be utilized. In addition, our right-of-way agreements associated with the Creole Trail Pipeline and the Corpus Christi Pipeline have no stipulated termination dates. We intend to operate the Creole Trail Pipeline and the Corpus Christi Pipeline as long as supply and demand for natural gas exists in the United States and intend to maintain it regularly.

Share-based Compensation, Policy

Share-based Compensation

We have awarded share-based compensation in the form of restricted stock shares, restricted stock units, performance stock units and phantom units. The awards and our related accounting policies are more fully described in Note 16—Share-based Compensation.

Foreign Currency, Policy

Foreign Currency

The functional currency of all of our subsidiaries is the U.S. dollar. Certain of our subsidiaries transact in currencies outside of the U.S. dollar, which gives rise to the recognition of transaction gains and losses based on the change in exchange rates between the U.S. dollar and the currency in which the foreign currency transaction is denominated. During the years ended December 31, 2023, 2022 and 2021, we recognized net transaction gains (losses) totaling $(20) million, $60 million and $33 million, respectively, substantially all of which related to commercial transactions executed by Cheniere Marketing. The transaction gains and losses on such commercial transactions primarily consisted of those on Euro denominated receivables and related foreign currency hedges arising from the sale of cargoes, which are presented within LNG revenues in our Consolidated Statements of Operations with the underlying activities. The remaining transaction gains and losses are presented primarily within other income (expense), net in our Consolidated Statements of Operations.

Income Taxes, Policy

Income Taxes

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

As changes in tax laws or rates are enacted, deferred tax assets and liabilities are adjusted through the current period’s provision for income taxes.

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

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

We account for our federal investment tax credits under the flow-through method.

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

Net Income (Loss) Per Share, Policy

Net Income (Loss) Per Share

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

Refer to Note 18—Net Income (Loss) per Share Attributable to Common Stockholders for additional details of the computation for the years ended December 31, 2023, 2022 and 2021.

Business Segment, Policy

Business Segment

We have determined that we operate as a single operating and reportable segment. Substantially all of our long-lived assets are located in the United States. Our chief operating decision maker is regularly provided with consolidated financial information to makes resource allocation decisions and assesses performance in the delivery of an integrated source of LNG to our customers. The financial measures regularly provided to the chief operating decision maker that are most consistent with GAAP are net income (loss) attributable to common stockholders and total consolidated assets, as presented in our Consolidated Financial Statements.

Recent Accounting Standards

Recent Accounting Standards

ASU 2020-04

In March 2020, the FASB issued ASU No. 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting. This guidance primarily provides temporary optional expedients which simplify the accounting for contract modifications to existing contracts as a result of the market transition from LIBOR to alternative reference rates. The temporary optional expedients under the standard became effective March 12, 2020 and will be available until December 31, 2024 following a subsequent amendment to the standard.

As further detailed in Note 11—Debt, all of our existing credit facilities include a variable interest rate indexed to SOFR, incorporated through amendments or replacements of previous credit facilities subsequent to the effective date of ASU 2020-04. We elected to apply the optional expedients as applicable to certain modified or replaced facilities; however, the

impact of applying the optional expedients was not material, and the transition to SOFR did not have a material impact on our cash flows.

ASU 2023-07

In November 2023, the FASB issued ASU No. 2023-07, Segment Reporting (Topic 280). This guidance requires a public entity, including entities with single reportable segment, to disclose significant segment expenses and other segment items on an annual and interim basis and provide in interim periods all disclosures about a reportable segment’s profit or loss and assets that are currently required annually. We plan to adopt this guidance and conform with the applicable disclosures retrospectively when it becomes mandatorily effective for our annual report for the year ending December 31, 2024.

ASU 2023-09

In December 2023, the FASB issued ASU No. 2023-09, Income Taxes (Topic 740). This guidance further enhances income tax disclosures, primarily through standardization and disaggregation of rate reconciliation categories and income taxes paid by jurisdiction. We plan to adopt this guidance and conform with the disclosure requirements when it becomes mandatorily effective for our annual report for the year ending December 31, 2025.

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Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Schedule Of Current Expected Credit Losses

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

	Year Ended December 31,
	2023		2022		2021
Current expected credit losses, beginning of period	$	5	$	9	$	7
Charges (reversals)	(2)		(4)		2
Current expected credit losses, end of period	$	3	$	5	$	9

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Trade and Other Receivables, Net of Current Expected Credit Losses (Tables)

12 Months Ended

Dec. 31, 2023

Receivables [Abstract]

Schedule of Accounts and Other Receivables, Net of Current Expected Credit Losses

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

	December 31,
	2023		2022
Trade receivables
SPL and CCL	$	525	$	922
Cheniere Marketing	451		917
Other	4		4
Other receivables	126		101
Total trade and other receivables, net of current expected credit losses	$	1,106	$	1,944

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Inventory (Tables)

12 Months Ended

Dec. 31, 2023

Inventory Disclosure [Abstract]

Schedule of Inventory

Inventory consisted of the following (in millions):

	December 31,
	2023		2022
LNG in-transit	$	112	$	356
LNG	88		212
Materials	207		194
Natural gas	35		60
Other	3		4
Total inventory	$	445	$	826

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Property, Plant and Equipment, Net of Accumulated Depreciation (Tables)

12 Months Ended

Dec. 31, 2023

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment, Net of Accumulated Depreciation

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

	December 31,
	2023		2022
Terminal and related assets
Terminal and interconnecting pipeline facilities (1)	$	34,069	$	33,815
Land	463		451
Construction-in-process	3,480		1,685
Accumulated depreciation	(6,099)		(4,985)
Total terminal and related assets, net of accumulated depreciation	31,913		30,966
Fixed assets and other
Computer and office equipment	37		33
Furniture and fixtures	31		20
Computer software	125		121
Leasehold improvements	43		48
Other	21		20
Accumulated depreciation	(183)		(191)
Total fixed assets and other, net of accumulated depreciation	74		51
Assets under finance leases
Marine assets	532		533
Accumulated depreciation	(63)		(22)
Total assets under finance leases, net of accumulated depreciation	469		511
Property, plant and equipment, net of accumulated depreciation	$	32,456	$	31,528

(1)Includes power generation facility and associated power infrastructure located near Corpus Christi, Texas that was acquired during the year ended December 31, 2023 to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

Schedule of Depreciation and Offsets to LNG Terminal Costs

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

	Year Ended December 31,
	2023		2022		2021
Depreciation expense	$	1,190	$	1,113	$	1,006
Offsets to LNG terminal costs (1)	—		204		319

(1)We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Projects during the testing phase for its construction.

Property Plant and Equipment Estimated Useful Lives Table

The identifiable components of our terminal and related assets have depreciable lives between 6 and 50 years, as follows:

Components	Useful life (years)
LNG storage tanks	50
Natural gas pipeline facilities	40
Marine berth, electrical, facility and roads	35
Water pipelines	30
Regasification processing equipment	30
Sendout pumps	20
Liquefaction processing equipment	6-50
Other	10-30

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value of Derivative Assets and Liabilities

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

	Fair Value Measurements as of
	December 31, 2023								December 31, 2022
	Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Total
Liquefaction Supply Derivatives asset (liability)	$	25	$	36	$	(2,178)	$	(2,117)	$	(66)	$	(29)	$	(9,924)	$	(10,019)
LNG Trading Derivatives asset (liability)	30		(20)		—		10		1		(47)		—		(46)
FX Derivatives liability	—		(17)		—		(17)		—		(28)		—		(28)

Fair Value Measurement Inputs and Valuation Techniques

The following table includes quantitative information for the unobservable inputs for our Level 3 Liquefaction Supply Derivatives as of December 31, 2023:

	Net Fair Value Liability (in millions)	Valuation Approach	Significant Unobservable Input	Range of Significant Unobservable Inputs / Weighted Average (1)
Liquefaction Supply Derivatives	$(2,178)	Market approach incorporating present value techniques	Henry Hub basis spread	$(1.090) - $0.505 / $(0.060)
		Option pricing model	International LNG pricing spread, relative to Henry Hub (2)	87% - 379% / 196%

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

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

Fair Value, Liabilities Measured on Recurring Basis, Unobservable Input Reconciliation

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

	Year Ended December 31,
	2023		2022		2021
Balance, beginning of period	$	(9,924)	$	(4,036)	$	241
Realized and change in fair value gains (losses) included in net income (loss) (1):
Included in cost of sales, existing deals (2)	5,685		(5,120)		(2,509)
Included in cost of sales, new deals (3)	15		(1,373)		(1,796)
Purchases and settlements:
Purchases (4)	—		—		(1)
Settlements (5)	2,045		605		29
Transfers out of level 3 (6)	1		—		—
Balance, end of period	$	(2,178)	$	(9,924)	$	(4,036)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period	$	5,700	$	(6,493)	$	(4,305)

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

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

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

(4)Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

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

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

Fair Value of Derivative Instruments by Balance Sheet Location

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

	December 31, 2023
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	49	$	92	$	—	$	141
Derivative assets	863		—		—		863
Total derivative assets	912		92		—		1,004
Current derivative liabilities	(651)		(82)		(17)		(750)
Derivative liabilities	(2,378)		—		—		(2,378)
Total derivative liabilities	(3,029)		(82)		(17)		(3,128)
Derivative asset (liability), net	$	(2,117)	$	10	$	(17)	$	(2,124)
	December 31, 2022
	Liquefaction Supply Derivatives (1)		LNG Trading Derivatives (2)		FX Derivatives		Total
Consolidated Balance Sheets Location
Current derivative assets	$	36	$	84	$	—	$	120
Derivative assets	35		—		—		35
Total derivative assets	71		84		—		155
Current derivative liabilities	(2,143)		(130)		(28)		(2,301)
Derivative liabilities	(7,947)		—		—		(7,947)
Total derivative liabilities	(10,090)		(130)		(28)		(10,248)
Derivative liability, net	$	(10,019)	$	(46)	$	(28)	$	(10,093)

(1)Does not include collateral posted with counterparties by us of $3 million and $111 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $4 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

(2)Does not include collateral posted with counterparties by us of $15 million and $23 million, as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $3 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

Derivative Net Presentation on Consolidated Balance Sheets

The following table shows the fair value of our derivatives outstanding on a gross and net basis (in millions) for our derivative instruments that are presented on a net basis on our Consolidated Balance Sheets:

	Liquefaction Supply Derivatives		LNG Trading Derivatives		FX Derivatives
As of December 31, 2023
Gross assets	$	1,272	$	94	$	—
Offsetting amounts	(360)		(2)		—
Net assets (1)	$	912	$	92	$	—
Gross liabilities	$	(3,095)	$	(110)	$	(17)
Offsetting amounts	66		28		—
Net liabilities (2)	$	(3,029)	$	(82)	$	(17)
As of December 31, 2022
Gross assets	$	76	$	87	$	—
Offsetting amounts	(5)		(3)		—
Net assets (1)	$	71	$	84	$	—
Gross liabilities	$	(10,436)	$	(132)	$	(29)
Offsetting amounts	346		2		1
Net liabilities (2)	$	(10,090)	$	(130)	$	(28)

(1)Includes current and non-current derivative assets of $141 million and $863 million, respectively, as of December 31, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

(2)Includes current and non-current derivative liabilities of $750 million and $2,378 million, respectively, as of December 31, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

Commodity Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Schedule of Notional Amounts of Outstanding Derivative Positions

The following table shows the notional amounts of our Liquefaction Supply Derivatives and LNG Trading Derivatives (collectively, “Commodity Derivatives”):

	December 31, 2023		December 31, 2022
	Liquefaction Supply Derivatives (1)	LNG Trading Derivatives	Liquefaction Supply Derivatives	LNG Trading Derivatives
Notional amount, net (in TBtu)	14,019	49	14,504	50

(1)Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of December 31, 2023.

Derivative Instruments, Gain (Loss)

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location (1)		Year Ended December 31,
			2023		2022		2021
LNG Trading Derivatives	LNG revenues		$	139	$	(387)	$	(1,812)
LNG Trading Derivatives	Recovery (cost) of sales		(132)		(2)		91
Liquefaction Supply Derivatives (2)	LNG revenues		(5)		2		3
Liquefaction Supply Derivatives (2)	Recovery (cost) of sales		7,912		(6,203)		(4,303)

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

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

FX Derivatives [Member]

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Derivative Instruments, Gain (Loss)

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

		Gain (Loss) Recognized in Consolidated Statements of Operations
	Consolidated Statements of Operations Location		Year Ended December 31,
			2023		2022		2021
FX Derivatives	LNG revenues		$	(24)	$	57	$	33

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Other Non-Current Assets (Tables)

12 Months Ended

Dec. 31, 2023

Other Assets, Noncurrent [Abstract]

Schedule of Other Non-Current Assets

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	244	$	171
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminals, net of accumulated amortization	175		170
Equity method investments (1)	111		16
Goodwill	77		77
Debt issuance costs and debt discount, net of accumulated amortization	58		60
Advance tax-related payments and receivables	20		20
Other, net	74		92
Total other non-current assets, net	$	759	$	606

(1)Includes investment in equity interest and capacity agreements with a pipeline developer and operator, expected to support delivery of natural gas feedstock to the Corpus Christi LNG Terminal for the Corpus Christi Stage 3 Project.

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Non-Controlling Interest and Variable Interest Entity (Tables)

12 Months Ended

Dec. 31, 2023

CQP [Member]

Noncontrolling Interest and Variable Interest Entity [Line Items]

Condensed Balance Sheet of Cheniere Partners

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

	December 31,
	2023		2022
ASSETS
Current assets
Cash and cash equivalents	$	575	$	904
Restricted cash and cash equivalents	56		92
Trade and other receivables, net of current expected credit losses	373		627
Other current assets	215		269
Total current assets	1,219		1,892
Property, plant and equipment, net of accumulated depreciation	16,212		16,725
Other non-current assets, net	309		288
Total assets	$	17,740	$	18,905
LIABILITIES
Current liabilities
Accrued liabilities	$	811	$	1,384
Current debt, net of discount and debt issuance costs	300		—
Current derivative liabilities	196		769
Other current liabilities	201		191
Total current liabilities	1,508		2,344
Long-term debt, net of premium, discount and debt issuance costs	15,606		16,198
Derivative liabilities	1,531		3,024
Other non-current liabilities	160		98
Total liabilities	$	18,805	$	21,664

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Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2023

Accrued Liabilities, Current [Abstract]

Schedule of Accrued Liabilities

Accrued liabilities consisted of the following (in millions): 

	December 31,
	2023		2022
Natural gas purchases	$	729	$	1,621
Interest costs and related debt fees	399		383
LNG terminals and related pipeline costs	235		240
Compensation and benefits	266		245
LNG purchases	23		88
Other accrued liabilities	128		102
Total accrued liabilities	$	1,780	$	2,679

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Debt (Tables)

12 Months Ended

Dec. 31, 2023

Debt Disclosure [Abstract]

Schedule of Debt Instruments

Debt consisted of the following (in millions): 

	December 31,
	2023		2022
SPL:
Senior Secured Notes:
5.750% due 2024 (the “2024 SPL Senior Notes”)	$	300	$	2,000
5.625% due 2025	2,000		2,000
5.875% due 2026	1,500		1,500
5.00% due 2027	1,500		1,500
4.200% due 2028	1,350		1,350
4.500% due 2030	2,000		2,000
4.746% weighted average rate due 2037	1,782		1,782
Total SPL Senior Secured Notes	10,432		12,132
Working capital revolving credit and letter of credit reimbursement agreement (the “SPL Working Capital Facility”)	—		—
Revolving credit and guaranty agreement (the “SPL Revolving Credit Facility”)	—		—
Total debt - SPL	10,432		12,132
CQP:
Senior Notes:
4.500% due 2029	1,500		1,500
4.000% due 2031	1,500		1,500
3.25% due 2032	1,200		1,200
5.950% due 2033 (the “2033 CQP Senior Notes”)	1,400		—
Total CQP Senior Notes	5,600		4,200
Credit facilities (the “CQP Credit Facilities”)	—		—
Revolving credit and guaranty agreement (the “CQP Revolving Credit Facility”)	—		—
Total debt - CQP	5,600		4,200
CCH:
Senior Secured Notes:
7.000% due 2024	—		498
5.875% due 2025	1,491		1,491
5.125% due 2027	1,201		1,271
3.700% due 2029	1,125		1,361
3.788% weighted average rate due 2039	2,539		2,633
Total CCH Senior Secured Notes	6,356		7,254
Term loan facility agreement (the “CCH Credit Facility”)	—		—
Working capital facility agreement (the “CCH Working Capital Facility”) (1)	—		—
Total debt - CCH	6,356		7,254
Cheniere:
4.625% Senior Notes due 2028	1,500		1,500
Revolving credit agreement (the “Cheniere Revolving Credit Facility”)	—		—
Total debt - Cheniere	1,500		1,500
Total debt	23,888		25,086
Current debt, net of discount and debt issuance costs	(300)		(813)
Long-term portion of discount and debt issuance costs, net	(191)		(218)
Total long-term debt, net of discount and debt issuance costs	$	23,397	$	24,055

(1)The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.

Schedule of Maturities of Long-term Debt

Below is a schedule of future principal payments that we are obligated to make on our outstanding debt at December 31, 2023 (in millions):

Years Ending December 31,	Principal Payments
2024	$	300
2025	3,543
2026	1,607
2027	2,889
2028	3,091
Thereafter	12,458
Total	$	23,888

Schedule of Line of Credit Facilities and Delayed Draw Term Loan

Below is a summary of our committed credit facilities outstanding as of December 31, 2023 (in millions):

	SPL Revolving Credit Facility (1)(2)		CQP Revolving Credit Facility (1)(3)		CCH Credit Facility (4)		CCH Working Capital Facility (5)		Cheniere Revolving Credit Facility (6)
Total facility size	$	1,000	$	1,000	$	3,260	$	1,500	$	1,250
Less:
Outstanding balance	—		—		—		—		—
Letters of credit issued	280		—		—		155		—
Available commitment	$	720	$	1,000	$	3,260	$	1,345	$	1,250
Priority ranking	Senior secured		Senior unsecured		Senior secured		Senior secured		Unsecured
Interest rate on available balance (7)	SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.75% or base rate plus 0.0% - 0.75%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.125% - 2.0% or base rate plus 0.125% - 1.0%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.5% or base rate plus 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.0% - 1.5% or base rate plus 0.0% - 0.5%		SOFR plus credit spread adjustment of 0.1%, plus margin of 1.075% - 2.20% or base rate plus 0.075% - 1.2%
Commitment fees on undrawn balance (7)	0.075% - 0.30%		0.10% - 0.30%		0.525%		0.10% - 0.20%		0.115% - 0.365% (8)
Maturity date	June 23, 2028		June 23, 2028		(9)		June 15, 2027		October 28, 2026

(1)In June 2023, CQP and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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

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

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

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

(6)In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR. The Cheniere Revolving Credit Facility contains a financial covenant requiring us to maintain a non-consolidated leverage ratio not to exceed 5.50:1.00 as of the end of any fiscal quarter if (i) as of the last day of such fiscal quarter the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit is greater than 35% of

the aggregate commitments under the Cheniere Revolving Credit Facility (a “Covenant Trigger Event”) or (ii) a Covenant Trigger Event had occurred and been continuing as of the last day of the immediately preceding fiscal quarter and as of the last day of such ending fiscal quarter such Covenant Trigger Event had not ceased for a period of at least thirty consecutive days.

(7)The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating.

(8)In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.

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

Schedule of Interest Expense

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

	Year Ended December 31,
	2023		2022		2021
Interest cost on convertible notes:
Interest per contractual rate	$	—	$	—	$	36
Amortization of debt discount and debt issuance costs	—		—		10
Total interest cost related to convertible notes	—		—		46
Interest cost on debt and finance leases excluding convertible notes	1,265		1,485		1,558
Total interest cost	$	1,265	$	1,485	1,604
Capitalized interest	(124)		(79)		(166)
Total interest expense, net of capitalized interest	$	1,141	$	1,406	$	1,438

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

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

	December 31, 2023				December 31, 2022
	Carrying Amount		Estimated Fair Value (1)		Carrying Amount		Estimated Fair Value (1)
Senior notes	$	23,888	$	23,062	$	25,086	$	23,500

(1)As of both December 31, 2023 and 2022, $3.0 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Schedule of Leases, Balance Sheet Location

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

		December 31,
	Consolidated Balance Sheets Location	2023		2022
Right-of-use assets—Operating	Operating lease assets	$	2,641	$	2,625
Right-of-use assets—Financing	Property, plant and equipment, net of accumulated depreciation	469		511
Total right-of-use assets		$	3,110	$	3,136
Current operating lease liabilities	Current operating lease liabilities	$	655	$	616
Current finance lease liabilities	Other current liabilities	35		28
Non-current operating lease liabilities	Operating lease liabilities	1,971		1,971
Non-current finance lease liabilities	Finance lease liabilities	467		494
Total lease liabilities		$	3,128	$	3,109

Schedule of Lease Cost, Income Statement Location

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

	Consolidated Statements of Operations Location	Year Ended December 31,
		2023		2022		2021
Operating lease cost (a)	Operating costs and expenses (1)	$	783	$	828	$	621
Finance lease cost:
Amortization of right-of-use assets	Depreciation and amortization expense	50		12		3
Interest on lease liabilities	Interest expense, net of capitalized interest	35		14		9
Total lease cost		$	868	$	854	$	633
(a) Included in operating lease cost:
Short-term lease costs		$	33	$	122	$	139
Variable lease costs		17		18		21

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

Schedule of Maturity of Lease Liabilities

Future annual minimum lease payments for operating and finance leases as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Operating Leases		Finance Leases
2024	$	752	$	67
2025	612		72
2026	480		75
2027	383		77
2028	228		73
Thereafter	638		355
Total lease payments (1)	3,093		719
Less: Interest	(467)		(217)
Present value of lease liabilities	$	2,626	$	502

(1)Does not include approximately $3.8 billion of legally binding minimum payments for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

Lease, Other Quantitative Information

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

	December 31, 2023		December 31, 2022
	Operating Leases	Finance Leases	Operating Leases	Finance Leases
Weighted-average remaining lease term (in years)	6.3	9.7	5.9	10.6
Weighted-average discount rate (1)	4.7%	7.7%	4.2%	7.8%

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

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

	Year Ended December 31,
	2023		2022		2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	720	$	713	$	483
Operating cash flows from finance leases	35		14		10
Financing cash flows from finance leases	28		7		—
Right-of-use assets obtained in exchange for operating lease liabilities	646		1,220		1,736
Right-of-use assets obtained in exchange for finance lease liabilities (1)	8		473		—

(1)     Includes $88 million reclassified from operating leases to finance leases during the year ended December 31, 2022 as a result of modification of the underlying vessel charters.

Schedule of Sublease Income

The following table shows the sublease income recognized in other revenues on our Consolidated Statements of Operations (in millions):

	Year Ended December 31,
	2023		2022		2021
Fixed income	$	446	$	371	$	72
Variable income	57		79		37
Total sublease income	$	503	$	450	$	109

Sublease Payment to be Received, Fiscal Year Maturity

Future annual minimum sublease payments to be received from LNG vessel subcharters as of December 31, 2023 are as follows (in millions): 

Years Ending December 31,	Sublease Payments
2024	$	158
2025	5
Total sublease payments	$	163

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Revenues (Tables)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue

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

	Year Ended December 31,
	2023		2022		2021
Revenues from contracts with customers
LNG revenues	$	19,459	$	32,132	$	17,171
Regasification revenues	135		1,068		269
Other revenues	187		107		91
Total revenues from contracts with customers	19,781		33,307		17,531
Net derivative gain (loss) (1)	110		(328)		(1,776)
Other (2)	503		449		109
Total revenues	$	20,394	$	33,428	$	15,864

(1)See Note 7—Derivative Instruments for additional information about our derivatives.

(2)Primarily includes revenues from LNG vessel subcharters. See Note 12—Leases for additional information about our subleases.

Contract Assets

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

	December 31,
	2023		2022
Contract assets, net of current expected credit losses	$	250	$	186

Contract Liabilities

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

	Year Ended December 31, 2023
Deferred revenue, beginning of period	$	320
Cash received but not yet recognized in revenue	218
Revenue recognized from prior period deferral	(244)
Deferred revenue, end of period	$	294

We record deferred revenue when we receive consideration, or such consideration is unconditionally due from a customer, prior to transferring goods or services to the customer under the terms of a sales contract. Changes in deferred revenue during the years ended December 31, 2023 and 2022 are primarily attributable to differences between the timing of revenue recognition and the receipt of advance payments related to delivery of LNG under certain SPAs.

Transaction Price Allocated to Future Performance Obligations

The following table discloses the aggregate amount of the transaction price that is allocated to performance obligations that have not yet been satisfied:

	December 31, 2023			December 31, 2022
	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)	Unsatisfied Transaction Price (in billions)		Weighted Average Recognition Timing (years) (1)
LNG revenues (2)	$	111.0	9	$	112.0	9
Regasification revenues	0.7		3	0.8		4
Total revenues	$	111.7		$	112.8

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

(2)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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met and consideration is not otherwise constrained from ultimate pricing and receipt.

Revenue, Remaining Performance Obligation, Variable Consideration

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

	Year Ended December 31,
	2023		2022
LNG revenues	69	%	72	%
Regasification revenues	7	%	2	%

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2023

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

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

	Year Ended December 31,
	2023		2022		2021
LNG Revenues
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	$	—	$	—	$	1
Other revenues
Operating Agreement and Construction Management Agreement with Midship Pipeline Company, LLC (“Midship Pipeline”) (2)	10		7		7
Cost of sales
Natural Gas Supply Agreements (3)	—		—		162
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	—		—		1
Total cost of sales	—		—		163
Operating and maintenance expense
Natural Gas Transportation and Storage Agreements with Midship Pipeline (2)	9		9		9
Natural Gas Transportation and Storage Agreements with a related party through Brookfield (1)	62		72		46

(1)This related party is partially owned by Brookfield, who indirectly owns a portion of CQP’s limited partner interests.

(2)Midship Pipeline is a subsidiary of Midship Holdings, LLC, which we recognize as an equity method investment.

(3)Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, when the related party entity was acquired by a non-related party.

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

	December 31,
	2023		2022
Trade and other receivables, net of current expected credit losses	$	3	$	1
Accrued liabilities	6		1

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Income before Income Tax, Domestic and Foreign

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

	Year Ended December 31,
	2023		2022		2021
U.S.	$	11,176	$	(1,575)	$	(2,317)
International	3,402		4,669		39
Total income (loss) before income taxes and non-controlling interest	$	14,578	$	3,094	$	(2,278)

Schedule of Components of Income Tax Expense (Benefit)

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

	Year Ended December 31,
	2023		2022		2021
Current:
Federal	$	130	$	6	$	—
State	1		2		3
Foreign	(1)		11		5
Total current	130		19		8
Deferred:
Federal	2,377		320		(633)
State	15		118		(89)
Foreign	(3)		2		1
Total deferred	2,389		440		(721)
Total income tax provision (benefit)	$	2,519	$	459	$	(713)

Schedule of Effective Income Tax Rate Reconciliation

Our income tax rates do not bear a customary relationship to statutory income tax rates. A reconciliation of the federal statutory income tax rate of 21% to our effective income tax rate is as follows: 

	Year Ended December 31,
	2023		2022		2021
U.S. federal statutory tax rate	21.0	%	21.0	%	21.0	%
Income not taxable to Cheniere	(3.1)		(8.2)		7.2
State tax, net of federal benefit	0.1		0.5		(2.5)
Foreign-derived intangible income deduction	(0.7)		(1.2)		—
Valuation allowance	—		2.6		5.6
Other	—		0.1		—
Effective tax rate as reported	17.3	%	14.8	%	31.3	%

Schedule of Deferred Tax Assets and Liabilities

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

	December 31,
	2023		2022
Deferred tax assets
Net operating loss (“NOL”) carryforwards
Federal	$	915	$	1,968
State	163		177
Federal and state tax credits	33		66
Derivative instruments	98		1,345
Operating lease liabilities	550		542
Other	298		311
Less: valuation allowance (1)	(147)		(143)
Total deferred tax assets	1,910		4,266
Deferred tax liabilities
Investment in partnerships	(309)		(211)
Property, plant and equipment	(2,564)		(2,646)
Operating lease assets	(538)		(536)
Other	(18)		(9)
Total deferred tax liabilities	(3,429)		(3,402)
Net deferred tax assets (liabilities)	$	(1,519)	$	864

(1)Valuation allowance primarily related to state NOL carryforward deferred tax assets and increased by $4 million and $80 million during the years ended December 31, 2023 and 2022, respectively, and decreased by $127 million during year ended December 31, 2021.

Schedule of Unrecognized Tax Benefits Roll Forward

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

	Year Ended December 31,
	2023		2022
Balance at beginning of the year	$	74	$	65
Additions based on tax positions related to current year	—		10
Reductions for tax positions of prior years	(1)		(1)
Balance at end of the year	$	73	$	74

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2023

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Share-based Compensation Expense, Net

Total share-based compensation consisted of the following (in millions):

	Year Ended December 31,
	2023		2022		2021
Share-based compensation costs before income taxes:
Equity awards	$	100	$	112	$	105
Liability awards	155		97		40
Total share-based compensation	255		209		145
Capitalized share-based compensation	(5)		(4)		(5)
Total share-based compensation costs before income taxes	$	250	$	205	$	140
Tax benefit associated with share-based compensation costs	$	54	$	48	$	33

Share-based Payment Arrangement, Nonvested Award, Cost

The total unrecognized compensation cost at December 31, 2023 relating to non-vested share-based compensation arrangements consisted of the following:

	Unrecognized Compensation Cost (in millions)		Recognized over a weighted average period (years)
Restricted Stock Unit and Performance Stock Unit Awards	$	181	1.4

Schedule Of Share Based-Payment Award, Performance Stock Units, Valuation Assumptions

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

	Year Ended December 31,
	2023		2022		2021
Fair value assumptions:
Dividend yield (1)	—	%	—	%	—	%
Expected volatility (2)	27.5% - 32.7%		36.4% - 40.2%		27.0% - 41.0%
Risk-free interest rate (2)	4.2% - 4.8%		4.4% - 4.7%		0.7% - 1.4%
Weighted average expected remaining term, in years	1.5		1.4		1.5

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

(2)Represents the range associated with individual vesting years.

Equity-Classified Restricted Stock Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Nonvested Share Activity

The table below provides a summary of activity related to our equity-classified restricted stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	2.3	$	92.52
Granted	0.8	150.59
Forfeited	(0.1)	118.77
Modified to liability awards (1)	(0.2)	115.26
Vested (2)	(1.2)	84.12
Non-vested at December 31, 2023	1.6	$	123.24

(1)See further details in Liability-Classified Awards below.

(2)The total fair value of shares vested was $183 million for the year ended December 31, 2023.

Equity-Classified Performance Stock Units [Member]

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Share-Based Payment Arrangement, Performance Shares, Outstanding Activity

The table below provides a summary of activity related to our equity-classified performance stock units (in millions, except for per unit information):

	Units	Weighted Average Grant Date Fair Value Per Unit
Non-vested at January 1, 2023	0.6	$	92.11
Granted (1)	0.2	163.04
Incremental units achieved (2)	0.3	72.05
Forfeited	(0.1)	107.61
Modified to liability awards (3)	(0.3)	106.25
Vested (4)	(0.2)	55.26
Non-vested at December 31, 2023	0.5	$	124.19

(1)Includes 0.1 million performance stock units granted in 2023 to certain officers containing a cash settlement cap of $3 million.

(2)Represents incremental units recognized as a result of final performance measures or estimated measures.

(3)See further details in Liability-Classified Awards below.

(4)The total fair value of shares vested was $36 million for the year ended December 31, 2023.

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Net Income (Loss) Per Share Attributable to Common Stockholders (Tables)

12 Months Ended

Dec. 31, 2023

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The following table reconciles basic and diluted weighted average common shares outstanding and common stock dividends declared (in millions, except per share data):

	Year Ended December 31,
	2023		2022		2021
Net income (loss) attributable to common stockholders	$	9,881	$	1,428	$	(2,343)
Weighted average common shares outstanding:
Basic	241.0		251.1		253.4
Dilutive unvested stock	1.6		2.3		—
Diluted	242.6		253.4		253.4
Net income (loss) per share attributable to common stockholders—basic (1)	$	40.99	$	5.69	$	(9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	$	40.72	$	5.64	$	(9.25)
Dividends paid per common share	$	1.62	$	1.385	$	0.33

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

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

Potentially dilutive securities that were not included in the diluted net income (loss) per share computations because their effects would have been anti-dilutive were as follows (in millions):

	Year Ended December 31,
	2023	2022	2021
Unvested stock (1)	—	—	1.8
4.25% Convertible Senior Notes due 2045 (the “2045 Cheniere Convertible Senior Notes”) (2)	—	0.3	—
Total potentially dilutive common shares	—	0.3	1.8

(1)Includes the impact of unvested shares containing performance conditions to the extent that the underlying performance conditions are satisfied based on actual results as of the respective period end dates.

(2)The 2045 Cheniere Convertible Senior Notes were redeemed or converted in cash on January 5, 2022. However, the adoption of ASU 2020-06 on January 1, 2022 required a presumption of share settlement for the purpose of calculating the impact to diluted earnings per share during the period the notes were outstanding in 2022. Such impact was anti-dilutive as a result of the reported net loss attributable to common stockholders during the 2022 period.

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Share Repurchase Programs (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Share Repurchases Under the Share Repurchase Program

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

	Year Ended December 31,
	2023		2022		2021
Total shares repurchased	9.54		9.35		0.10
Weighted average price paid per share	$	155.50	$	146.88	$	87.32
Total cost of repurchases (1)	$	1,484	$	1,373	$	9

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

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

SPL and CCL | Natural Gas Supply, Transportation And Storage Service Agreements [Member]

Long-term Purchase Commitment [Line Items]

Contractual Obligation, Fiscal Year Maturity Schedule

As of December 31, 2023, the obligations of SPL and CCL under natural gas supply, transportation and storage service agreements for contracts in which contractual conditions were met or are currently expected to be met were as follows (in billions):

Years Ending December 31,	Payments Due to Third Parties (1) (2)		Payments Due to Related Parties (1) (3)
2024	$	6.2	$	0.1
2025	6.3		0.1
2026	5.9		0.1
2027	5.3		0.1
2028	4.3		0.1
Thereafter	29.5		0.8
Total	$	57.5	$	1.3

(1)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. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

(2)Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

(3)Includes $1.0 billion under natural gas transportation and storage service agreements with unsatisfied contractual conditions.

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Customer Concentration (Tables)

12 Months Ended

Dec. 31, 2023

Risks and Uncertainties [Abstract]

Schedule of Revenue and Accounts Receivable by Major Customers

The concentration of our customer credit risk in excess of 10% of total revenues and/or trade and other receivables, net of current expected credit losses and contract assets, net of current expected credit losses was as follows:

	Percentage of Total Revenues from External Customers			Percentage of Trade and Other Receivables, Net and Contract Assets, Net from External Customers
	Year Ended December 31,			December 31,
	2023	2022	2021	2023	2022
Customer A	*	*	12%	*	*
Customer B	*	*	12%	*	*
Customer C	*	*	10%	*	*
Customer D	*	*	*	13%	*

* Less than 10%

Schedule of Revenue from External Customers by Country

The following table shows revenues from external customers attributable to the country in which the revenues were derived (in millions). We attribute revenues from external customers to the country in which the party to the applicable agreement has its principal place of business.

	Revenues from External Customers
	Year Ended December 31,
	2023		2022		2021
Singapore	$	3,407	$	3,273	$	1,740
United Kingdom	2,908		4,642		1,246
United States	2,868		5,213		1,340
Ireland	1,596		2,726		1,838
South Korea	1,503		2,225		1,680
Spain	1,357		2,226		1,577
India	1,166		2,109		1,375
Switzerland	534		1,725		582
Germany	131		1,747		507
Other countries	4,924		7,542		3,979
Total	$	20,394	$	33,428	$	15,864

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Supplemental Cash Flow Information (Tables)

12 Months Ended

Dec. 31, 2023

Supplemental Cash Flow Information [Abstract]

Schedule of Cash Flow, Supplemental Disclosures

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

	Year Ended December 31,
	2023		2022		2021
Cash paid during the period for interest on debt, net of amounts capitalized	$	1,032	$	891	$	1,365
Cash paid for income taxes, net	117		30		4
Non-cash investing activity:
Unpaid purchases of property, plant and equipment, net and other non-current assets	204		181		117
Share-based compensation capitalized to property, plant and equipment	5		4		5
Conveyance of property, plant and equipment in exchange for other non-current assets	—		17		—
Contribution of other non-current assets in exchange for equity method investment	30		—		—
Non-cash financing activity:
Unpaid dividends declared on unvested common stock	3		4		1
Unpaid repurchases of treasury stock inclusive of excise taxes	23		—		—

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Organization and Nature of Operations (Details)	12 Months Ended
	Dec. 31, 2023 mi unit milliontonnes / yr item trains
Organization and Nature of Operations [Line Items]
Number Of Natural Gas Liquefaction And Export Facilities | unit	2
Sabine Pass LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	6
Total Production Capability | milliontonnes / yr	30
Number of LNG Storage Tanks | unit	5
Number of Marine Berths Operating | item	3
Creole Trail Pipeline [Member]
Organization and Nature of Operations [Line Items]
Length of Natural Gas Pipeline | mi	94
Corpus Christi LNG Terminal [Member]
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Operating | trains	3
Total Production Capability | milliontonnes / yr	15
Number of LNG Storage Tanks | unit	3
Number of Marine Berths Operating | item	2
Corpus Christi Stage 3 Project
Organization and Nature of Operations [Line Items]
Number of Liquefaction LNG Trains Constructing | trains	7
Corpus Christi Stage 3 Project | Minimum [Member]
Organization and Nature of Operations [Line Items]
Total Production Capability | milliontonnes / yr	10
Corpus Christi Pipeline [Member]
Organization and Nature of Operations [Line Items]
Length of Natural Gas Pipeline | mi	21.5
CQP [Member]
Organization and Nature of Operations [Line Items]
General Partner ownership percentage	100.00%
Limited Partner ownership percentage	48.60%
Incentive Distribution Right Ownership Percentage	100.00%

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Summary of Significant Accounting Policies (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) customer	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Current expected credit losses, beginning of period	$ 5.0	$ 9.0	$ 7.0
Charged to selling, general and administrative expense	(2.0)	(4.0)	2.0
Current expected credit losses, end of period	3.0	5.0	9.0
Impairment expense related to property, plant and equipment	$ 0.0	$ 0.0	0.0
Amortization Period Of Conveyed Assets	31 years	31 years
Derivative Instruments in Hedges, at Fair Value, Net	$ 0.0	$ 0.0	0.0
Foreign Currency Transaction Gain (Loss), after Tax	$ (20.0)	$ 60.0	$ 33.0
Income Tax Rate, Corporate Alternative Minimum Tax	15.00%
Customer Concentration Risk [Member] | SPA Customers [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Concentration Risk, Number of Significant Customers | customer	29
Sabine Pass LNG Terminal [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0.0
Creole Trail Pipeline [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	0.0
Corpus Christi Pipeline [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Asset Retirement Obligation	$ 0.0
Maximum [Member] | Sabine Pass LNG Terminal [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
Property lease term	90 years
Minimum [Member] | Customer Concentration Risk [Member]
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
SPA, Term of Agreement	10 years
Weighted Average [Member] | SPA and IPM Customers
Basis of Presentation and Summary of Significant Accounting Policies [Line Items]
SPA and IPM, Remaining Term	16 years

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Restricted Cash and Cash Equivalents (Details) - USD ($) $ in Millions	Dec. 31, 2023		Dec. 31, 2022
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 459	[1]	$ 1,134
SPL Project and CCL Project
Restricted Cash and Cash Equivalents Items [Line Items]
Restricted cash and cash equivalents	$ 459		$ 1,100

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

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Trade and Other Receivables, Net of Current Expected Credit Losses (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accounts and Other Receivables [Line Items]
Other receivables	$ 126	$ 101
Total trade and other receivables, net of current expected credit losses	1,106	1,944
SPL and CCL
Accounts and Other Receivables [Line Items]
Trade receivables	525	922
Cheniere Marketing
Accounts and Other Receivables [Line Items]
Trade receivables	451	917
Other
Accounts and Other Receivables [Line Items]
Trade receivables	$ 4	$ 4

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Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Inventory [Line Items]
Inventory	$ 445	$ 826
LNG in-transit [Member]
Inventory [Line Items]
Inventory	112	356
LNG [Member]
Inventory [Line Items]
Inventory	88	212
Materials [Member]
Inventory [Line Items]
Inventory	207	194
Natural gas [Member]
Inventory [Line Items]
Inventory	35	60
Other [Member]
Inventory [Line Items]
Inventory	$ 3	$ 4

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Property, Plant and Equipment, Net of Accumulated Depreciation (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Property, plant and equipment, net of accumulated depreciation		$ 32,456	$ 31,528
Terminal and related assets [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation		(6,099)	(4,985)
Property, plant and equipment, net of accumulated depreciation		31,913	30,966
Terminal and interconnecting pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross	[1]	34,069	33,815
Land [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		463	451
Construction-in-process [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		3,480	1,685
Fixed assets and other [Member]
Property, Plant and Equipment [Line Items]
Accumulated depreciation		(183)	(191)
Property, plant and equipment, net of accumulated depreciation		74	51
Computer and office equipment [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		37	33
Furniture and fixtures [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		31	20
Computer software [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		125	121
Leasehold improvements [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		43	48
Other [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		21	20
Assets under finance leases [Member]
Property, Plant and Equipment [Line Items]
Property, plant and equipment, gross		532	533
Accumulated depreciation		(63)	(22)
Property, plant and equipment, net of accumulated depreciation		$ 469	$ 511

[1] Includes power generation facility and associated power infrastructure located near Corpus Christi, Texas that was acquired during the year ended December 31, 2023 to mitigate power price risk associated with our anticipated increased power load at the Corpus Christi LNG Terminal.

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Property, Plant and Equipment, Net of Accumulated Depreciation - Schedule of Depreciation and Offsets to LNG Terminal Costs (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Depreciation expense		$ 1,190	$ 1,113	$ 1,006
Offsets to LNG terminal costs	[1]	$ 0	$ 204	$ 319

[1] We recognize offsets to LNG terminal costs related to the sale of commissioning cargoes because these amounts were earned or loaded prior to the start of commercial operations of the respective Trains of the Liquefaction Projects during the testing phase for its construction.

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Property, Plant and Equipment, Net of Accumulated Depreciation - Estimated Useful Lives (Details)	Dec. 31, 2023
Terminal and related assets [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Terminal and related assets [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
LNG storage tanks [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Natural gas pipeline facilities [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	40 years
Marine berth, electrical, facility and roads [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	35 years
Water pipelines [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Regasification processing equipment [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years
Sendout pumps [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	20 years
Liquefaction processing equipment [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	6 years
Liquefaction processing equipment [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	50 years
Other [Member] | Minimum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	10 years
Other [Member] | Maximum [Member]
Property, Plant and Equipment [Line Items]
Property, Plant and Equipment, Useful Life	30 years

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Derivative Instruments - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Instruments in Hedges, at Fair Value, Net	$ 0	$ 0	$ 0
Liquefaction Supply Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	15 years
LNG Trading Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year
FX Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Notional Amount	$ 789	$ 619
FX Derivatives [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Term of Contract	1 year

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Derivative Instruments - Fair Value of Derivative Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Liquefaction Supply Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ (2,117)	$ (10,019)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	25	(66)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	36	(29)
Liquefaction Supply Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(2,178)	(9,924)
LNG Trading Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	10	(46)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	30	1
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(20)	(47)
LNG Trading Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(17)	(28)
FX Derivatives [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	0	0
FX Derivatives [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	(17)	(28)
FX Derivatives [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative Assets (Liabilities), at Fair Value, Net	$ 0	$ 0

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Derivative Instruments - Fair Value Inputs - Quantitative Information (Details) - Liquefaction Supply Derivatives [Member] - Fair Value, Inputs, Level 3 [Member]	12 Months Ended
	Dec. 31, 2023 USD ($)
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Net Fair Value Liabilities	$ (2,178,000,000)
Valuation, Market Approach [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	(1.090)	[1]
Valuation, Market Approach [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	0.505	[1]
Valuation, Market Approach [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread	$ (0.060)	[1]
Valuation Technique, Option Pricing Model [Member] | Minimum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	87.00%	[1],[2]
Valuation Technique, Option Pricing Model [Member] | Maximum [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	379.00%	[1],[2]
Valuation Technique, Option Pricing Model [Member] | Weighted Average [Member]
Fair Value Measurement Inputs and Valuation Tecniques [Line Items]
Fair Value Inputs Basis Spread Percentage	196.00%	[1],[2]

[1] Unobservable inputs were weighted by the relative fair value of the instruments.

[2] Spread contemplates U.S. dollar-denominated pricing.

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Derivative Instruments - Schedule of Level 3 Derivatives Activity (Details) - Physical Liquefaction Supply Derivatives and Physical LNG Trading Derivative - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Assets (Liabilities) Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Balance, beginning of period		$ (9,924)	$ (4,036)	$ 241
Realized and change in fair value gains (losses) included in net income:
Included in cost of sales, existing deals	[1],[2]	5,685	(5,120)	(2,509)
Included in cost of sales, new deals	[1],[3]	15	(1,373)	(1,796)
Purchases and settlements:
Purchases	[4]	0	0	(1)
Settlements	[5]	2,045	605	29
Transfers out of level 3	[6]	1	0	0
Balance, end of period		(2,178)	(9,924)	(4,036)
Favorable (unfavorable) changes in fair value relating to instruments still held at the end of the period		$ 5,700	$ (6,493)	$ (4,305)

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

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

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

[4] Includes any day one gain (loss) recognized during the reporting period on deals that were entered into during the reporting period which continue to exist at the end of the period, in addition to any derivative contracts acquired from entities at a value other than zero on acquisition date, such as derivatives assigned or novated during the reporting period and continuing to exist at the end of the period.

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

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

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Derivative Instruments - Schedule of Notional Amounts of Outstanding Derivative Positions (Details) - tbtu	Dec. 31, 2023		Dec. 31, 2022
Liquefaction Supply Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	14,019	[1]	14,504
LNG Trading Derivatives [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount	49		50

[1] Inclusive of amounts under contracts with unsatisfied contractual conditions and exclusive of extension options that were uncertain to be taken as of December 31, 2023.

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Derivative Instruments - Derivative Instruments, Gain (Loss) (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
LNG Trading Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	$ 139	$ (387)	$ (1,812)
LNG Trading Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1]	(132)	(2)	91
Liquefaction Supply Derivatives [Member] | LNG Revenues [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	(5)	2	3
Liquefaction Supply Derivatives [Member] | Recovery (cost) of sales [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net	[1],[2]	7,912	(6,203)	(4,303)
FX Derivatives [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative gain (loss), net		$ (24)	$ 57	$ 33
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Revenues	Revenues	Revenues

[1] Fair value fluctuations associated with commodity derivative activities are classified and presented consistently with the item economically hedged and the nature and intent of the derivative instrument.

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

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Derivative Instruments - Fair Value of Derivative Instruments by Balance Sheet Location (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Current derivative assets		$ 141	$ 120
Derivative assets		863	35
Total derivative assets		1,004	155
Current derivative liabilities		(750)	(2,301)
Derivative liabilities		(2,378)	(7,947)
Total derivative liabilities		(3,128)	(10,248)
Derivative asset (liability), net		$ (2,124)	$ (10,093)
Derivative Asset, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative assets	Current derivative assets
Derivative Asset, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative assets	Derivative assets
Derivative Liability, Current, Statement of Financial Position [Extensible Enumeration]		Current derivative liabilities	Current derivative liabilities
Derivative Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]		Derivative liabilities	Derivative liabilities
Liquefaction Supply Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[1]	$ 49	$ 36
Derivative assets	[1]	863	35
Total derivative assets	[1]	912	71
Current derivative liabilities	[1]	(651)	(2,143)
Derivative liabilities	[1]	(2,378)	(7,947)
Total derivative liabilities	[1]	(3,029)	(10,090)
Derivative asset (liability), net	[1]	(2,117)	(10,019)
Derivative, collateral posted by us		3	111
Derivative, collateral posted by counterparties		4	0
LNG Trading Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets	[2]	92	84
Derivative assets	[2]	0	0
Total derivative assets	[2]	92	84
Current derivative liabilities	[2]	(82)	(130)
Derivative liabilities	[2]	0	0
Total derivative liabilities	[2]	(82)	(130)
Derivative asset (liability), net	[2]	10	(46)
Derivative, collateral posted by us		15	23
Derivative, collateral posted by counterparties		3	0
FX Derivatives [Member]
Derivatives, Fair Value [Line Items]
Current derivative assets		0	0
Derivative assets		0	0
Total derivative assets		0	0
Current derivative liabilities		(17)	(28)
Derivative liabilities		0	0
Total derivative liabilities		(17)	(28)
Derivative asset (liability), net		$ (17)	$ (28)

[1] Does not include collateral posted with counterparties by us of $3 million and $111 million as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $4 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

[2] Does not include collateral posted with counterparties by us of $15 million and $23 million, as of December 31, 2023 and 2022, respectively, which are included in margin deposits on our Consolidated Balance Sheets, and collateral posted by counterparties to us of $3 million and zero as of December 31, 2023 and 2022, respectively, which are included in other current liabilities on our Consolidated Balance Sheets.

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Derivative Instruments - Derivative Net Presentation on Consolidated Balance Sheets (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Current derivative assets		$ 141	$ 120
Derivative assets		863	35
Current derivative liabilities		750	2,301
Derivative liabilities		2,378	7,947
Liquefaction Supply Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		1,272	76
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(360)	(5)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	912	71
Liquefaction Supply Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(3,095)	(10,436)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		66	346
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(3,029)	(10,090)
LNG Trading Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		94	87
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		(2)	(3)
Derivative Assets (Liabilities), at Fair Value, Net	[1]	92	84
LNG Trading Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(110)	(132)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		28	2
Derivative Assets (Liabilities), at Fair Value, Net	[2]	(82)	(130)
FX Derivatives Asset [Member]
Derivative [Line Items]
Derivative Asset, Gross Amounts Recognized		0	0
Derivative Asset, Gross Amounts Offset in the Consolidated Balance Sheets		0	0
Derivative Assets (Liabilities), at Fair Value, Net	[1]	0	0
FX Derivatives Liability [Member]
Derivative [Line Items]
Derivative Liability, Gross Amounts Recognized		(17)	(29)
Derivative Liability, Gross Amounts Offset in the Consolidated Balance Sheets		0	1
Derivative Assets (Liabilities), at Fair Value, Net	[2]	$ (17)	$ (28)

[1] Includes current and non-current derivative assets of $141 million and $863 million, respectively, as of December 31, 2023 and $120 million and $35 million, respectively, as of December 31, 2022.

[2] Includes current and non-current derivative liabilities of $750 million and $2,378 million, respectively, as of December 31, 2023 and $2,301 million and $7,947 million, respectively, as of December 31, 2022.

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Other Non-Current Assets - Schedule of Non-Current Assets (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Other Assets, Noncurrent [Abstract]
Contract assets, net of current expected credit losses		$ 244	$ 171
Advances of cash and conveyed assets to service providers for infrastructure to support LNG terminals, net of accumulated amortization		175	170
Equity method investments (1)	[1]	111	16
Goodwill		77	77
Debt issuance costs and debt discount, net of accumulated amortization		58	60
Advance tax-related payments and receivables		20	20
Other, net		74	92
Total other non-current assets, net		$ 759	$ 606

[1] Includes investment in equity interest and capacity agreements with a pipeline developer and operator, expected to support delivery of natural gas feedstock to the Corpus Christi LNG Terminal for the Corpus Christi Stage 3 Project.

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Non-Controlling Interest and Variable Interest Entity (Details) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) unit shares		Dec. 31, 2012 shares	Dec. 31, 2022 USD ($)
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 4,066	[1]		$ 1,353
Restricted cash and cash equivalents	459	[1]		1,134
Trade and other receivables, net of current expected credit losses	1,106			1,944
Other current assets, net	96			97
Total current assets	6,331			5,608
Property, plant and equipment, net of accumulated depreciation	32,456			31,528
Other non-current assets, net	759			606
Total assets	43,076	[1]		41,266
Accrued liabilities	1,780			2,679
Current debt, net of discount and debt issuance costs	300			813
Current derivative liabilities	750			2,301
Other current liabilities	43			28
Total current liabilities	3,888			6,795
Long-term debt, net of discount and debt issuance costs	23,397			24,055
Derivative liabilities	2,378			7,947
Other non-current liabilities	$ 410			175
Cheniere Energy Partners GP, LLC [Member] | Blackstone CQP Holdco [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Number Of Members Of The Board Of Directors | unit	3
Minimum Number Of Members Of The Board Of Directors Required For Quorum | unit	2
Cheniere Energy Partners GP, LLC [Member] | Cheniere [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Number Of Members Of The Board Of Directors | unit	4
Minimum Number Of Members Of The Board Of Directors Required For Quorum | unit	2
Cheniere Energy Partners GP, LLC [Member] | Blackstone CQP Holdco LP and Cheniere [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Number Of Members Of The Board Of Directors | unit	4
Minimum Number Of Members Of The Board Of Directors Required For Quorum | unit	2
Blackstone CQP Holdco [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Number Of Members Of The Board Of Directors | unit	1
Class B Units [Member] | Blackstone CQP Holdco [Member] | CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Partners Capital Account, Units Sold In Private Placement | shares			100.0
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	48.60%
General Partner ownership percentage	100.00%
Incentive Distribution Right Ownership Percentage	100.00%
CQP [Member] | Blackstone CQP Holdco [Member] | Director Appointment Entitlement, Minimum [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Limited Partner ownership percentage	20.00%
CQP [Member] | Common Units [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Partners Capital Account, Units, Units Held | shares	239.9
CQP [Member]
Noncontrolling Interest and Variable Interest Entity [Line Items]
Cash and cash equivalents	$ 575			904
Restricted cash and cash equivalents	56			92
Trade and other receivables, net of current expected credit losses	373			627
Other current assets, net	215			269
Total current assets	1,219			1,892
Property, plant and equipment, net of accumulated depreciation	16,212			16,725
Other non-current assets, net	309			288
Total assets	17,740			18,905
Accrued liabilities	811			1,384
Current debt, net of discount and debt issuance costs	300			0
Current derivative liabilities	196			769
Other current liabilities	201			191
Total current liabilities	1,508			2,344
Long-term debt, net of discount and debt issuance costs	15,606			16,198
Derivative liabilities	1,531			3,024
Other non-current liabilities	160			98
Total liabilities	$ 18,805			$ 21,664

[1] Amounts presented include balances held by our consolidated variable interest entity (“VIE”), CQP, as further discussed in Note 9—Non-controlling Interest and Variable Interest Entity. As of December 31, 2023, total assets and liabilities of CQP were $17.7 billion and $18.8 billion, respectively, including $575 million of cash and cash equivalents and $56 million of restricted cash and cash equivalents.

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Accrued Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Accrued Liabilities, Current [Abstract]
Natural gas purchases	$ 729	$ 1,621
Interest costs and related debt fees	399	383
LNG terminals and related pipeline costs	235	240
Compensation and benefits	266	245
LNG purchases	23	88
Other accrued liabilities	128	102
Total accrued liabilities	$ 1,780	$ 2,679

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Debt - Narrative (Details) $ in Millions	1 Months Ended	12 Months Ended
	Jun. 30, 2022 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Debt Instrument [Line Items]
Debt, Minimum Historical Debt Service Coverage Ratio And Projected Debt Service Coverage Ratio		1.25
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries		$ 203
Chevron U.S.A. Inc.
Debt Instrument [Line Items]
Contract Termination Fee	$ 765
Gain (Loss) on extinguishment of obligations [Member] | Chevron U.S.A. Inc.
Debt Instrument [Line Items]
Contract Termination Fee			$ 31

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Debt - Schedule of Debt Instruments (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 23,888	$ 25,086
Current portion of long-term debt		(300)	(813)
Long-term portion of discount and debt issuance costs, net		(191)	(218)
Total Long-Term Debt, Net of Premium, Discount and Debt Issuance Costs		23,397	24,055
SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		10,432	12,132
2024 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 300	2,000
Debt Instrument, Interest Rate, Stated Percentage		5.75%
2025 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage		5.625%
2026 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		5.00%
2028 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,350	1,350
Debt Instrument, Interest Rate, Stated Percentage		4.20%
2030 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,000	2,000
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2037 SPL Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,782	1,782
2037 SPL Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		4.746%
SPL Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
SPL Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		0	0
CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		5,600	4,200
2029 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.50%
2031 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.00%
2032 CQP Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,200	1,200
Debt Instrument, Interest Rate, Stated Percentage		3.25%
2033 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,400	0
Debt Instrument, Interest Rate, Stated Percentage		5.95%
CQP Credit Facilities [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CQP Revolving Credit Facility
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		0	0
CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		6,356	7,254
2024 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	498
Debt Instrument, Interest Rate, Stated Percentage		7.00%
2025 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,491	1,491
Debt Instrument, Interest Rate, Stated Percentage		5.875%
2027 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,201	1,271
Debt Instrument, Interest Rate, Stated Percentage		5.125%
2029 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,125	1,361
Debt Instrument, Interest Rate, Stated Percentage		3.70%
2039 CCH Senior Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 2,539	2,633
2039 CCH Senior Notes [Member] | Weighted Average [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.788%
CCH Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
CCH Working Capital Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount	[1]	0	0
Line of Credit Facility, Annual Temporary Requirement, Balance, Outstanding Principal		$ 0
Line of Credit Facility, Annual Temporary Requirement, Period, Number of Consecutive Business Days		5 days
2028 Cheniere Senior Secured Notes [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 1,500	1,500
Debt Instrument, Interest Rate, Stated Percentage		4.625%
Cheniere Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 0	0
Cheniere [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		1,500	1,500
SPL [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		10,432	12,132
CQP [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		5,600	4,200
CCH [Member]
Debt Instrument [Line Items]
Debt, Long-term and Short-term, Combined Amount		$ 6,356	$ 7,254

[1] The CCH Working Capital Facility is classified as short-term debt as we are required to reduce the aggregate outstanding principal amount to zero for a period of five consecutive business days at least once each year.

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Debt - Senior Notes (Details) - CQP [Member]	12 Months Ended
	Dec. 31, 2023 USD ($)
Debt Instrument [Line Items]
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Monetary Amount	$ 1,500,000,000
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Percentage of Net Tangible Assets	10.00%
2033 Cheniere Energy Partners Senior Notes
Debt Instrument [Line Items]
Debt Instrument, Secured Debt Condition, Secured Indebtedness and Attributable Indebtedness Threshold, Percentage of Net Tangible Assets	15.00%

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Debt - Schedule of Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Long-term Debt, Fiscal Year Maturity [Abstract]
2024	$ 300
2025	3,543
2026	1,607
2027	2,889
2028	3,091
Thereafter	12,458
Total	$ 23,888

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Debt - Credit Facilities Table (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
SPL Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,000	[1],[2]
Outstanding balance	0	[1],[2]
Letters of credit issued	280	[1],[2]
Available commitment	$ 720	[1],[2]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028	[1],[2]
SPL Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.075%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.75%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.00%	[1],[2],[3]
SPL Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.75%	[1],[2],[3]
CQP Revolving Credit Facility
Line of Credit Facility [Line Items]
Total facility size	$ 1,000	[1],[4]
Outstanding balance	0	[1],[4]
Letters of credit issued	0	[1],[4]
Available commitment	$ 1,000	[1],[4]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 23, 2028	[1],[4]
CQP Revolving Credit Facility | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[1],[3],[4]
CQP Revolving Credit Facility | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.30%	[1],[3],[4]
CQP Revolving Credit Facility | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[1],[3],[4]
CQP Revolving Credit Facility | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.125%	[1],[3],[4]
CQP Revolving Credit Facility | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.00%	[1],[3],[4]
CQP Revolving Credit Facility | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.125%	[1],[3],[4]
CQP Revolving Credit Facility | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[1],[3],[4]
CCH Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 3,260	[5]
Outstanding balance	0	[5]
Letters of credit issued	0	[5]
Available commitment	$ 3,260	[5]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Line of Credit Facility, Commitment Fee Percentage	0.525%	[3],[5]
CCH Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Maturity date	Jun. 15, 2029
Debt Instrument, Maturity Date, Years after Substantial Completion	2 years
CCH Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[3],[5]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[3],[5]
CCH Credit Facility [Member] | Base Rate [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[3],[5]
CCH Working Capital Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,500	[6]
Outstanding balance - current	0	[6]
Letters of credit issued	155	[6]
Available commitment	$ 1,345	[6]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Jun. 15, 2027	[6]
CCH Working Capital Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.10%	[3],[6]
CCH Working Capital Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.20%	[3],[6]
CCH Working Capital Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[3],[6]
CCH Working Capital Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.00%	[3],[6]
CCH Working Capital Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.50%	[3],[6]
CCH Working Capital Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.00%	[3],[6]
CCH Working Capital Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.50%	[3],[6]
Cheniere Revolving Credit Facility [Member]
Line of Credit Facility [Line Items]
Total facility size	$ 1,250	[7]
Outstanding balance	0	[7]
Letters of credit issued	0	[7]
Available commitment	$ 1,250	[7]
Debt Instrument, Description of Variable Rate Basis	SOFR or base rate
Maturity date	Oct. 28, 2026	[7]
Quarterly Non-Consolidated Leverage Ratio Covenant, Maximum	5.50
Debt Instrument, Liquidity Covenant Threshold, Sum Of Outstanding Loans And Unreimbursed Letters Of Credit, Percentage of Commitments, Minimum	35.00%
Non-Consolidated Leverage Ration Requirement, Period Covenant Trigger Event Has Continued	30 days
Cheniere Revolving Credit Facility [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.115%	[3],[7],[8]
Cheniere Revolving Credit Facility [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Line of Credit Facility, Commitment Fee Percentage	0.365%	[3],[7],[8]
Cheniere Revolving Credit Facility [Member] | SOFR
Line of Credit Facility [Line Items]
Debt Instrument, Credit Spread Adjustment On Variable Rate	0.10%	[3],[7]
Cheniere Revolving Credit Facility [Member] | SOFR | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.075%	[3],[7]
Cheniere Revolving Credit Facility [Member] | SOFR | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	2.20%	[3],[7]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Minimum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	0.075%	[3],[7]
Cheniere Revolving Credit Facility [Member] | Base Rate [Member] | Maximum [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Basis Spread on Variable Rate	1.20%	[3],[7]

[1] In June 2023, CQP and SPL refinanced and replaced the CQP Credit Facilities and the SPL Working Capital Facility with the CQP Revolving Credit Facility and the SPL Revolving Credit Facility, respectively, resulting in extended maturity dates, revised borrowing capacities, reduced rate of interest and commitment fees applicable thereunder and certain other changes to terms and conditions.

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

[3] The margin on the interest rate and the commitment fees is subject to change based on the applicable entity’s credit rating

[4] The obligations under the CQP Revolving Credit Facility are jointly, severally and unconditionally guaranteed by Cheniere Investments, SPLNG, CTPL, Sabine Pass LNG-GP, LLC, Sabine Pass Tug Services, LLC and Cheniere Pipeline GP Interests, LLC.

[5] The obligations of CCH under the CCH Credit Facility are secured by a first priority lien on substantially all of the assets of CCH and its subsidiaries and by a pledge by CCH Holdco I of its limited liability company interests in CCH.

[6] The obligations of CCH under the CCH Working Capital Facility are secured by substantially all of the assets of CCH and the CCH Guarantors as well as all of the membership interests in CCH and each of the CCH Guarantors on a pari passu basis with the CCH Senior Secured Notes and the CCH Credit Facility.

[7] In June 2023, we amended the Cheniere Revolving Credit Facility to update the indexed interest rate to SOFR. The Cheniere Revolving Credit Facility contains a financial covenant requiring us to maintain a non-consolidated leverage ratio not to exceed 5.50:1.00 as of the end of any fiscal quarter if (i) as of the last day of such fiscal quarter the aggregate principal amount of outstanding loans plus drawn and unreimbursed letters of credit is greater than 35% of the aggregate commitments under the Cheniere Revolving Credit Facility (a “Covenant Trigger Event”) or (ii) a Covenant Trigger Event had occurred and been continuing as of the last day of the immediately preceding fiscal quarter and as of the last day of such ending fiscal quarter such Covenant Trigger Event had not ceased for a period of at least thirty consecutive days.

[8] In April 2023, the commitment fees for the Cheniere Revolving Credit Facility were reduced as a result of achieving certain ESG metrics.

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Debt - Interest Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Amortization of debt issuance costs, premium and discount	$ 44	$ 57	$ 72
Total interest cost	1,265	1,485	1,604
Capitalized interest	(124)	(79)	(166)
Total interest expense, net of capitalized interest	1,141	1,406	1,438
Convertible Debt [Member]
Debt Instrument [Line Items]
Interest per contractual rate	0	0	36
Amortization of debt issuance costs, premium and discount	0	0	10
Total interest cost	0	0	46
Debt and Finance Leases Excluding Convertible Debt [Member]
Debt Instrument [Line Items]
Total interest cost	$ 1,265	$ 1,485	$ 1,558

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Debt - Schedule of Carrying Values and Estimated Fair Values of Debt Instruments (Details) - USD ($) $ in Millions		Dec. 31, 2023	Dec. 31, 2022
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		$ 23,888	$ 25,086
Senior Notes [Member] | Carrying Amount [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Carrying Amount, Debt		23,888	25,086
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 2 and Level 3
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value	[1]	23,062	23,500
Senior Notes [Member] | Estimated Fair Value [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes, Estimated Fair Value		$ 3,000	$ 3,000

[1] As of both December 31, 2023 and 2022, $3.0 billion of the fair value of our senior notes were classified as Level 3 since these senior notes were valued by applying an unobservable illiquidity adjustment to the price derived from trades or indicative bids of instruments with similar terms, maturities and credit standing. The remainder of our senior notes are classified as Level 2, based on prices derived from trades or indicative bids of the instruments.

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Leases - Balance Sheet Location Table (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Right-of-use assets—Operating	$ 2,641	$ 2,625
Right-of-use assets—Financing	469	511
Total right-of-use assets	3,110	3,136
Current operating lease liabilities	655	616
Current finance lease liabilities	35	28
Operating lease liabilities	1,971	1,971
Non-current finance lease liabilities	467	494
Total lease liabilities	$ 3,128	$ 3,109
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Right-of-use assets—Operating	Right-of-use assets—Operating
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Property, plant and equipment, net of accumulated depreciation	Property, plant and equipment, net of accumulated depreciation
Operating Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Current operating lease liabilities	Current operating lease liabilities
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Operating lease liabilities	Operating lease liabilities
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Non-current finance lease liabilities	Non-current finance lease liabilities

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Leases - Income Statement Location Table (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Finance lease cost:
Total lease cost		$ 868	$ 854	$ 633
Operating costs and expenses [Member]
Lessee, Lease, Description [Line Items]
Operating lease cost	[1]	783	828	621
Finance lease cost:
Short-term lease costs		33	122	139
Variable lease costs		17	18	21
Depreciation and amortization expense [Member]
Finance lease cost:
Amortization of right-of-use assets		50	12	3
Interest expense, net of capitalized interest [Member]
Finance lease cost:
Interest on lease liabilities		$ 35	$ 14	$ 9

[1] Presented in the appropriate line item within operating costs and expenses, consistent with the nature of the asset under lease.

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Leases - Future Minimum Payments Table (Details) $ in Millions	Dec. 31, 2023 USD ($)
Operating Leases, Future Minimum Payments
2024	$ 752
2025	612
2026	480
2027	383
2028	228
Thereafter	638
Total lease payments	3,093	[1]
Less: Interest	(467)
Present value of lease liabilities	2,626
Finance Leases, Future Minimum Payments
2024	67
2025	72
2026	75
2027	77
2028	73
Thereafter	355
Total lease payments	719	[1]
Less: Interest	(217)
Present value of lease liabilities	502
Operating Lease, Lease Not yet Commenced, Payments Due	$ 3,800
Maximum [Member]
Finance Leases, Future Minimum Payments
Operating Leases, Lease Not yet Commenced, Term of Contract	15 years

[1] Does not include approximately $3.8 billion of legally binding minimum payments for vessel charters executed as of December 31, 2023 that will commence in future periods with fixed minimum lease terms of up to 15 years.

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Leases - Other Quantitative Information (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
Weighted-average remaining lease term		6 years 3 months 18 days	5 years 10 months 24 days
Weighted-average discount rate	[1]	4.70%	4.20%
Finance Leases
Weighted-average remaining lease term		9 years 8 months 12 days	10 years 7 months 6 days
Weighted-average discount rate	[1]	7.70%	7.80%
Operating cash flows from operating leases		$ 720	$ 713	$ 483
Operating cash flows from finance leases		35	14	10
Financing cash flows from finance leases		28	7	0
Right-of-use assets obtained in exchange for operating lease liabilities		646	1,220	1,736
Right-of-use assets obtained in exchange for finance lease liabilities (1)	[2]	$ 8	473	$ 0
Right-Of-Use Asset Obtained In Exchange For Finance Lease Liability, Reclassification From Operating Lease			$ 88

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

[2] Includes $88 million reclassified from operating leases to finance leases during the year ended December 31, 2022 as a result of modification of the underlying vessel charters.

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Leases - Subleases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Lessor, Operating Lease, Description
Sublease Income, Fixed	$ 446	$ 371	$ 72
Sublease Income, Variable	57	79	37
Sublease Income, Total	503	$ 450	$ 109
Operating Leases, Future Minimum Payments Receivable
2024	158
2025	5
Total sublease payments	$ 163

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Revenues - Narrative 10-K (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) unit	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Disaggregation of Revenue [Line Items]
LNG Volume, Purchase Price Percentage of Henry Hub	115.00%
Revenues from contracts with customers	$ 19,781	$ 33,307	$ 17,531
Regasification Capacity | unit	4
Operating and maintenance expense	$ 1,835	1,681	1,444
Terminal Use Agreement Regasification Capacity Partial [Member]
Disaggregation of Revenue [Line Items]
Operating and maintenance expense	$ 132	131	129
TotalEnergies Gas & Power North America, Inc.
Disaggregation of Revenue [Line Items]
Regasification Capacity | unit	1
Revenue Performance Obligation Fixed Consideration	$ 125
Long-term Purchase Commitment, Period	20 years
Chevron U.S.A. Inc.
Disaggregation of Revenue [Line Items]
Regasification Capacity | unit	1
SPL [Member]
Disaggregation of Revenue [Line Items]
Regasification Capacity | unit	2
Liquefied Natural Gas Procured From Third Parties [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers	$ 359	$ 760	$ 499

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Revenues - Schedule of Disaggregation of Revenue (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		$ 19,781	$ 33,307	$ 17,531
Net derivative gain (loss)	[1]	110	(328)	(1,776)
Other revenues	[2]	503	449	109
Total revenues		20,394	33,428	15,864
LNG [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		19,459	32,132	17,171
Total revenues		19,569	31,804	15,395
Regasification [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		135	1,068	269
Total revenues		135	1,068	269
Other [Member]
Disaggregation of Revenue [Line Items]
Revenues from contracts with customers		187	107	91
Total revenues		$ 690	$ 556	$ 200

[1] See Note 7—Derivative Instruments for additional information about our derivatives.

[2] Primarily includes revenues from LNG vessel subcharters. See Note 12—Leases for additional information about our subleases.

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Revenues - Termination Agreement with Chevron (Details) - Chevron U.S.A. Inc. - USD ($) $ in Millions	1 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2023	Dec. 31, 2022
Revenue from External Customer [Line Items]
Contract Termination Fee	$ 765
Terminated commitments [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee		$ 796
Gain (Loss) on extinguishment of obligations [Member]
Revenue from External Customer [Line Items]
Contract Termination Fee				$ 31
Regasification [Member]
Revenue from External Customer [Line Items]
Revenue Performance Obligation Fixed Consideration			$ 125

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Revenues - Contract Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Contract assets, net of current expected credit losses	$ 250	$ 186
Change In Contract With Customer, Liability [Roll Forward]
Deferred revenue, beginning of period	320
Cash received but not yet recognized in revenue	218
Revenue recognized from prior period deferral	(244)
Deferred revenue, end of period	$ 294

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Revenues - Schedule of Transaction Price Allocated to Future Performance Obligations (Details) - USD ($) $ in Billions		Dec. 31, 2023	Dec. 31, 2022
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 112.8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 111.7
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	[1]		$ 112.0
Weighted Average Recognition Timing	[1],[2]		9 years
LNG [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price	[1]	$ 111.0
Weighted Average Recognition Timing	[1],[2]	9 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price			$ 0.8
Weighted Average Recognition Timing	[2]		4 years
Regasification [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Unsatisfied Transaction Price		$ 0.7
Weighted Average Recognition Timing	[2]	3 years

[1] 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 considered completed contracts for revenue recognition purposes and are included in the transaction price above when the conditions are considered probable of being met and consideration is not otherwise constrained from ultimate pricing and receipt.

[2] The weighted average recognition timing represents an estimate of the number of years during which we shall have recognized half of the unsatisfied transaction price.

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Revenues - Remaining Performance Obligation, Variable Consideration (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
LNG [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	69.00%	72.00%
Regasification [Member]
Revenue, Remaining Performance Obligation, Variable Consideration [Line Items]
Revenue, Variable Consideration Received From Customers, Percentage	7.00%	2.00%

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Related Party Transaction [Line Items]
Revenues		$ 20,394	$ 33,428	$ 15,864
Cost of sales		1,356	25,632	13,773
Operating and maintenance expense		1,835	1,681	1,444
Trade and other receivables, net of current expected credit losses		1,106	1,944
Accrued liabilities		1,780	2,679
Related Party [Member]
Related Party Transaction [Line Items]
Cost of sales		0	0	163
Trade and other receivables, net of current expected credit losses		3	1
Accrued liabilities		6	1
LNG [Member]
Related Party Transaction [Line Items]
Revenues		19,569	31,804	15,395
Other [Member]
Related Party Transaction [Line Items]
Revenues		690	556	200
Natural Gas Transportation and Storage Agreements [Member] | Midship Pipeline [Member]
Related Party Transaction [Line Items]
Operating and maintenance expense	[1]	9	9	9
Natural Gas Transportation and Storage Agreements [Member] | Related Party through Brookfield Ownership [Member]
Related Party Transaction [Line Items]
Cost of sales	[2]	0	0	1
Operating and maintenance expense	[2]	62	72	46
Natural Gas Transportation and Storage Agreements [Member] | LNG [Member] | Related Party through Brookfield Ownership [Member]
Related Party Transaction [Line Items]
Revenues	[2]	0	0	1
Operation and Maintenance Agreement [Member] | Other [Member] | Midship Pipeline [Member]
Related Party Transaction [Line Items]
Revenues	[1]	10	7	7
Natural Gas Supply Agreement [Member]
Related Party Transaction [Line Items]
Cost of sales	[3]	$ 0	$ 0	$ 162

[1] Midship Pipeline is a subsidiary of Midship Holdings, LLC, which we recognize as an equity method investment.

[2] This related party is partially owned by Brookfield, who indirectly owns a portion of CQP’s limited partner interests.

[3] Includes amounts recorded related to natural gas supply contracts that SPL and CCL had with related parties. These agreements ceased to be considered related party agreements during 2021, when the related party entity was acquired by a non-related party.

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Income Taxes - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Tax Credit Carryforwards	$ 33	$ 66
Unrecognized Tax Benefits	73	74	$ 65
Unrecognized Tax Benefits that Would Impact Effective Tax Rate	66
Unrecognized Tax Benefits, Interest on Income Taxes Expense	4	0
Unrecognized Tax Benefits, Interest on Income Taxes Accrued	4	0
Unrecognized Tax Benefits, Income Tax Penalties Expense	0	$ 0
Federal Tax [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration	4,300
Deferred Tax Assets, Tax Credit Carryforwards	32
State Tax [Member]
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards, Not Subject to Expiration	2,200
Deferred Tax Assets, Tax Credit Carryforwards	$ 1

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Income Taxes - Components of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income (loss) before income taxes and non-controlling interest, U.S.	$ 11,176	$ (1,575)	$ (2,317)
Income (loss) before income taxes and non-controlling interest, International	3,402	4,669	39
Income (loss) before income taxes and non-controlling interest	$ 14,578	$ 3,094	$ (2,278)

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Income Taxes - Provision for Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current
Federal	$ 130	$ 6	$ 0
State	1	2	3
Foreign	(1)	11	5
Total current	130	19	8
Deferred
Federal	2,377	320	(633)
State	15	118	(89)
Foreign	(3)	2	1
Total deferred	2,389	440	(721)
Total income tax provision (benefit)	$ 2,519	$ 459	$ (713)

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Income Taxes - Reconciliation of Effective Income Tax Rate (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
U.S. federal statutory tax rate	21.00%	21.00%	21.00%
Income not taxable to Cheniere	(3.10%)	(8.20%)	7.20%
State tax, net of federal benefit	0.10%	0.50%	(2.50%)
Foreign-derived intangible income deduction	(0.70%)	(1.20%)	0.00%
Valuation allowance	0.00%	2.60%	5.60%
Other	0.00%	0.10%	0.00%
Effective tax rate as reported	17.30%	14.80%	31.30%

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Income Taxes - Components of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Net operating loss carryforwards and credits
Federal	$ 915	$ 1,968
State	163	177
Federal and state tax credits	33	66
Derivative instruments	98	1,345
Operating lease liabilities	550	542
Other	298	311
Less: valuation allowance	(147)	(143)
Total deferred tax assets	1,910	4,266
Deferred tax liabilities
Investment in partnerships	(309)	(211)
Property, plant and equipment	(2,564)	(2,646)
Operating lease assets	(538)	(536)
Other	(18)	(9)
Total deferred tax liabilities	(3,429)	(3,402)
Deferred Tax Liabilities, Net	(1,519)
Net deferred tax assets		864
Increase (decrease) in valuation allowance	$ 4	$ 80	$ (127)

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Income Taxes - Changes in Gross Amounts of Unrecognized Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Balance at beginning of year	$ 74	$ 65
Additions based on tax positions related to current year	0	10
Reductions for tax positions of prior years	(1)	(1)
Balance at end of year	$ 73	$ 74

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Share-Based Compensation - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) shares
Restricted Stock Share Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	1 year
Nonvested shares outstanding	0
Fair value of awards vested | $	$ 1
Restricted Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Award Vesting Period	3 years
Performance Stock Units [Member] | Minimum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Percentage	0.00%
Performance Stock Units [Member] | Maximum [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Percentage	300.00%
2011 Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	35,000,000
2020 Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Shares Authorized	8,000,000

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Share-Based Compensation - Schedule of Share-Based Compensation (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	$ 255	$ 209	$ 145
Capitalized share-based compensation	(5)	(4)	(5)
Total share-based compensation costs before income taxes	250	205	140
Tax benefit associated with share-based compensation expense	54	48	33
Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	100	112	105
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total share-based compensation	$ 155	$ 97	$ 40

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Share-Based Compensation - Schedule of Unrecognized Compensation Cost (Details) - Restricted Share Unit And Performance Stock Unit Awards [Member] $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost	$ 181
Recognized over a weighted average period	1 year 4 months 24 days

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Share-Based Compensation - Schedule of Non-vested Equity-Classified Restricted Stock Units (Details) - Equity-Classified Restricted Stock Units [Member] $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at January 1, 2023, Units | shares	2,300
Non-vested at January 1, 2023, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 92.52
Granted, Units | shares	800
Granted, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 150.59
Forfeited, Units | shares	(100)
Forfeited, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 118.77
Modified to liability awards, units | shares	(200)	[1]
Modified to liability awards, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 115.26	[1]
Vested, Units | shares	(1,200)	[2]
Vested, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 84.12	[2]
Non-vested at December 31, 2023, Units | shares	1,600
Non-vested at December 31, 2023, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 123.24
Fair value of units vested | $	$ 183

[1] See further details in Liability-Classified Awards below.

[2] The total fair value of shares vested was $183 million for the year ended December 31, 2023.

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Share-Based Compensation - Schedule Of Performance Stock Units Valuation Assumptions (Details) - Performance Stock Units [Member]		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Dividend yield	[1]	0.00%	0.00%	0.00%
Expected Volatility Rate, Minimum	[2]	27.50%	36.40%	27.00%
Expected Volatility Rate, Maximum	[2]	32.70%	40.20%	41.00%
Risk Free Interest Rate, Minimum	[2]	4.20%	4.40%	0.70%
Risk Free Interest Rate, Maximum	[2]	4.80%	4.70%	1.40%
Share-Based Compensation Arrangement by Share-Based Payment Award, Fair Value Assumptions, Expected Term		1 year 6 months	1 year 4 months 24 days	1 year 6 months

[1] The performance stock units are entitled to dividend equivalents during the performance period. Therefore, when calculating simulated returns, we applied an annual dividend yield of zero percent.

[2] Represents the range associated with individual vesting years.

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Share-Based Compensation - Schedule Of Non-vested Equity-Classified Performance Stock Units (Details) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) $ / shares shares
Equity-Classified Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Non-vested at January 1, 2023, Units	600
Non-vested at January 1, 2023, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 92.11
Granted, Units	200	[1]
Granted, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 163.04	[1]
Incremental Units Achieved, Units	300	[2]
Incremental Units Achieved, Weighted Average Grant Date Fair Value per Unit | $ / shares	$ 72.05	[2]
Forfeited, Units	(100)
Forfeited, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 107.61
Modified to liability awards, units	(300)	[3]
Modified to liability awards, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 106.25	[3]
Vested, Units	(200)	[4]
Vested, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 55.26	[4]
Non-vested at December 31, 2023, Units	500
Non-vested at December 31, 2023, Weighted Average Grant Date Fair Value Per Unit | $ / shares	$ 124.19
Fair value of units vested | $	$ 36
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-Based Compensation Arrangement by Share-Based Payment Award, Shares Issued in Period With Cash Settlement Option	100
Performance Stock Units Cash Settlement Cap Per Officer | $	$ 3

[1] Includes 0.1 million performance stock units granted in 2023 to certain officers containing a cash settlement cap of $3 million.

[2] Represents incremental units recognized as a result of final performance measures or estimated measures.

[3] See further details in Liability-Classified Awards below.

[4] The total fair value of shares vested was $36 million for the year ended December 31, 2023

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Share-Based Compensation - Liability-Classified Awards (Details) shares in Thousands, $ / shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) employees $ / shares shares	Dec. 31, 2022 USD ($) employees $ / shares shares	Dec. 31, 2021 USD ($) employees
Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance Stock Units Cash Settlement Cap Per Officer | $	$ 3
Share-Based Payment Arrangement, Plan Modification, Incremental Cost | $	$ 86	$ 56	$ 18
Share-based Payment Arrangement, Plan Modification, Number of Grantees Affected | employees	6	6	5
Incremental Grants in Period	300
Equity Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Modified to liability awards, units	500
Liability Awards [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of units vested | $	$ 84
Vested, Units	500
Nonvested award fair value | $ / shares	$ 165,000	$ 98,000
Liability-Classified Restricted Stock Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested shares outstanding	200	200
Liability-Classified Performance Stock Units [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Nonvested shares outstanding	600	100

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Employee Benefit Plan (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	75.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Employees' Gross Pay	6.00%
Defined Contribution Plan, Contributions	$ 17	$ 16	$ 15
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 0

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Net Income (Loss) Per Share Attributable to Common Stockholders (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions			12 Months Ended
		Jan. 26, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Net income (loss) attributable to common stockholders			$ 9,881	$ 1,428	$ (2,343)
Weighted average number of common shares outstanding, basic			241.0	251.1	253.4
Dilutive Unvested Stock			1.6	2.3	0.0
Weighted Average Number of Shares Outstanding, Diluted			242.6	253.4	253.4
Net income (loss) per share attributable to common stockholders—basic (1)	[1]		$ 40.99	$ 5.69	$ (9.25)
Net income (loss) per share attributable to common stockholders—diluted (1)	[1]		40.72	5.64	(9.25)
Common Stock, Dividends, Per Share, Declared			$ 1.62	$ 1.385	$ 0.33
Antidilutive securities excluded from computation of earnings per share			0.0	0.3	1.8
2045 Cheniere Convertible Senior Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			4.25%
Subsequent Event [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Common Stock, Dividends, Per Share, Declared		$ 0.435
Unvested stock
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[2]		0.0	0.0	1.8
2045 Cheniere Convertible Senior Notes [Member]
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	[3]		0.0	0.3	0.0

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

[2] Includes the impact of unvested shares containing performance conditions to the extent that the underlying performance conditions are satisfied based on actual results as of the respective period end dates.

[3] The 2045 Cheniere Convertible Senior Notes were redeemed or converted in cash on January 5, 2022. However, the adoption of ASU 2020-06 on January 1, 2022 required a presumption of share settlement for the purpose of calculating the impact to diluted earnings per share during the period the notes were outstanding in 2022. Such impact was anti-dilutive as a result of the reported net loss attributable to common stockholders during the 2022 period.

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Share Repurchase Programs - Narrative (Details) - USD ($) shares in Thousands, $ in Millions			2 Months Ended	12 Months Ended
	Oct. 01, 2022	Oct. 01, 2021	Feb. 16, 2024	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021	Sep. 30, 2021
Share Repurchases [Line Items]
Stock Repurchase Program, Authorized Amount									$ 1,000
Stock Repurchase Program, Period in Force		3 years
Stock Repurchase Program, Remaining Authorized Repurchase Amount				$ 2,100
Total shares repurchased				9,540		9,350		100
Total cost of repurchases				$ 1,484	[1]	$ 1,373	[1]	$ 9
Subsequent Event [Member]
Share Repurchases [Line Items]
Total shares repurchased			2,900
Total cost of repurchases			$ 450
Subsequent Board Approved Increase [Member]
Share Repurchases [Line Items]
Stock Repurchase Program, Period in Force	3 years
Stock Repurchase Program, Increased in Authorized Amount	$ 4,000

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

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Share Repurchase Programs - Schedule of Share Repurchases (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Equity [Abstract]
Total shares repurchased	9,540		9,350		100
Weighted average price paid per share	$ 155.50		$ 146.88		$ 87.32
Total cost of repurchases	$ 1,484	[1]	$ 1,373	[1]	$ 9

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

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Commitments and Contingencies - Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Commitments and Contingencies [Line Items]
Operating Lease, Lease Not yet Commenced, Payments Due	$ 3,800
Maximum [Member]
Commitments and Contingencies [Line Items]
Operating Leases, Lease Not yet Commenced, Term of Contract	15 years
SPL and CCL | Natural Gas Supply Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	15 years
SPL and CCL | Natural Gas Transportation Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	20 years
SPL and CCL | Natural Gas Storage Service Agreements [Member] | Maximum [Member]
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Period	10 years
SPL [Member] | Partial TUA Assignment Agreement and Other Agreements
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	$ 1,400
CCL [Member] | Bechtel EPC Contract Corpus Christi Stage 3
Commitments and Contingencies [Line Items]
Long-term Purchase Commitment, Amount	5,700
Purchase Commitment, Remaining Minimum Amount Committed	$ 2,900

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Commitments and Contingencies - Purchase Obligations Table (Details) - SPL and CCL - Natural Gas Supply, Transportation And Storage Service Agreements [Member] $ in Billions	Dec. 31, 2023 USD ($)
Nonrelated Party
Long-term Purchase Commitment [Line Items]
2024	$ 6.2	[1],[2]
2025	6.3	[1],[2]
2026	5.9	[1],[2]
2027	5.3	[1],[2]
2028	4.3	[1],[2]
Thereafter	29.5	[1],[2]
Total	57.5	[1],[2]
Purchase obligation with unsatisfied contractual conditions	0.8
Related Party [Member]
Long-term Purchase Commitment [Line Items]
2024	0.1	[2],[3]
2025	0.1	[2],[3]
2026	0.1	[2],[3]
2027	0.1	[2],[3]
2028	0.1	[2],[3]
Thereafter	0.8	[2],[3]
Total	1.3	[2],[3]
Purchase obligation with unsatisfied contractual conditions	$ 1.0

[1] Includes $0.8 billion under natural gas supply agreements with unsatisfied contractual conditions.

[2] 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. Some of our contracts may not have been negotiated as part of arranging financing for the underlying assets providing the natural gas supply, transportation and storage services.

[3] Includes $1.0 billion under natural gas transportation and storage service agreements with unsatisfied contractual conditions.

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Customer Concentration - Schedule of Customer Concentration (Details) - Customer Concentration Risk [Member]	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2021
Customer A [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		12.00%
Customer B [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		12.00%
Customer C [Member] | Total Revenues from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage		10.00%
Customer D [Member] | Accounts Receivable, Net and Contract Assets, Net from External Customers [Member]
Concentration Risk [Line Items]
Concentration Risk, Percentage	13.00%

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Customer Concentration - Schedule of Revenue from External Customers by Country (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Concentration Risk [Line Items]
Revenues from External Customers	$ 20,394	$ 33,428	$ 15,864
Geographic Concentration Risk [Member] | Singapore
Concentration Risk [Line Items]
Revenues from External Customers	3,407	3,273	1,740
Geographic Concentration Risk [Member] | United Kingdom
Concentration Risk [Line Items]
Revenues from External Customers	2,908	4,642	1,246
Geographic Concentration Risk [Member] | United States
Concentration Risk [Line Items]
Revenues from External Customers	2,868	5,213	1,340
Geographic Concentration Risk [Member] | Ireland
Concentration Risk [Line Items]
Revenues from External Customers	1,596	2,726	1,838
Geographic Concentration Risk [Member] | South Korea
Concentration Risk [Line Items]
Revenues from External Customers	1,503	2,225	1,680
Geographic Concentration Risk [Member] | Spain
Concentration Risk [Line Items]
Revenues from External Customers	1,357	2,226	1,577
Geographic Concentration Risk [Member] | India
Concentration Risk [Line Items]
Revenues from External Customers	1,166	2,109	1,375
Geographic Concentration Risk [Member] | Switzerland
Concentration Risk [Line Items]
Revenues from External Customers	534	1,725	582
Geographic Concentration Risk [Member] | Germany
Concentration Risk [Line Items]
Revenues from External Customers	131	1,747	507
Geographic Concentration Risk [Member] | Other countries
Concentration Risk [Line Items]
Revenues from External Customers	$ 4,924	$ 7,542	$ 3,979

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Supplemental Cash Flow Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Supplemental Cash Flow Information [Abstract]
Cash paid during the period for interest on debt, net of amounts capitalized	$ 1,032	$ 891	$ 1,365
Cash paid for income taxes, net	117	30	4
Unpaid purchases of property, plant and equipment, net and other non-current assets	204	181	117
Share-based compensation capitalized to property, plant and equipment	5	4	5
Conveyance of property, plant and equipment in exchange for other non-current assets	0	17	0
Contribution of other non-current assets in exchange for equity method investment	30	0	0
Unpaid dividends declared on unvested common stock	3	4	1
Unpaid repurchases of treasury stock inclusive of excise taxes	$ 23	$ 0	$ 0